EXHIBIT 99.1
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ADVANTAGE ENERGY INCOME FUND
RENEWAL ANNUAL INFORMATION FORM
2004
MARCH 21, 2005
TABLE OF CONTENTS
PAGE
GLOSSARY OF TERMS..............................................................1
ABBREVIATIONS..................................................................4
CONVERSION.....................................................................4
ADVANTAGE ENERGY INCOME FUND...................................................6
GENERAL DEVELOPMENT OF THE BUSINESS............................................7
RECENT DEVELOPMENTS............................................................9
DESCRIPTION OF OUR BUSINESS AND OPERATIONS.....................................9
STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION..................10
ADDITIONAL INFORMATION RESPECTING ADVANTAGE ENERGY INCOME FUND................28
ADDITIONAL INFORMATION RESPECTING ADVANTAGE OIL & GAS LTD.....................34
ADDITIONAL INFORMATION RESPECTING ADVANTAGE INVESTMENT MANAGEMENT LTD.........41
MARKET FOR SECURITIES.........................................................48
ESCROWED SECURITIES...........................................................50
PAST PROMOTER.................................................................50
LEGAL PROCEEDINGS.............................................................50
INTEREST OF INSIDERS AND OTHERS IN MATERIAL TRANSACTIONS......................50
MATERIAL CONTRACTS............................................................50
INTEREST OF EXPERTS...........................................................51
AUDITORS, TRANSFER AGENT AND REGISTRAR........................................51
AUDIT COMMITTEE INFORMATION...................................................51
AUDIT COMMITTEE CHARTER.......................................................52
AUDIT SERVICE FEES............................................................56
RISK FACTORS..................................................................56
ADDITIONAL INFORMATION........................................................64
SCHEDULES
"A" - REPORT OF MANAGEMENT AND DIRECTORS ON RESERVES DATA AND OTHER INFORMATION
"B" - REPORT ON RESERVES DATA
GLOSSARY OF TERMS
"DEBENTURES" means, collectively, the 7.50% Debentures, 7.75% Debentures, 8.25%
Debentures, 9% Debentures and 10% Debentures;
"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;
"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 us or in the
management and administration of AOG, the Royalty and us including, without
limitation: (a) all reasonable costs and expenses relating to AOG, the Royalty
and us and paid directly to third parties by or on behalf of AOG, us or our
affiliates, including, without limitation, Trustee's fees; and (b) all
reasonable costs and expenses incurred specifically for AOG or us relating to
AOG, the Royalty or us 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 us
(other than the Management Fees). For greater clarity, employee bonuses and
amounts paid to employees under incentive plans are not reimbursable;
"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;
"LONG TERM NOTE INDENTURE" means the master note indenture dated September 30,
2004 between AOG and Computershare Trust Company of Canada providing for the
issuance of the Long Term Notes;
"LONG TERM NOTES" means the unsecured subordinated promissory notes of AOG
issued to us from time to time under the Long Term Note Indenture;
"MANAGEMENT AGREEMENT" means the amended and restated management agreement dated
October 4, 2004 among AOG, the Manager and the Trustee on our behalf;
"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;
"MEDIUM TERM NOTE INDENTURE" means the master note indenture dated September 30,
2004 between AOG and Computershare Trust Company of Canada providing for the
issue of Medium Term Notes;
"MEDIUM TERM NOTES" means the unsecured subordinated promissory notes of AOG
issued to us from time to time under the Medium Term Note Indenture;
"NOTE INDENTURES" means, collectively, the Long Term Note Indenture and the
Medium Term Note Indenture;
"NOTE TRUSTEE" means Computershare Trust Company of Canada, or its successor as
trustee under the Note Indentures;
"NOTES" means the unsecured subordinated promissory notes of AOG issued to us
from time to time under the Note Indentures;
"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;
2
"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 we receive 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
royalties, gross overriding royalties and lessors' royalties, but for certainty
not deducting the Royalty or any royalties payable to us by AOG in all other
respects;
"PERMITTED INVESTMENTS" means, with respect to up to 25% of our total assets,
(unless otherwise approved by the board of directors of AOG 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;
"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;
"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 us dated as of December 1, 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 our settlor to the Trustee for the purpose of settling the Trust;
"SHAREHOLDER AGREEMENT" means the shareholder agreement entered into as of May
24, 2001 between AOG and the Trustee, as our trustee for and on our behalf;
"SUBSEQUENT INVESTMENT" means those investments which we are 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;
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"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", 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 trust indenture between Computershare Trust Company
of Canada and AOG made effective as of April 17, 2001, supplemented as of May
22, 2002 and amended and restated as of June 25, 2002, May 28, 2002 and May 26,
2004, pursuant to which Advantage was formed, as the same may be further
amended, restated or replaced from time to time;
"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 of AOG; and
"UNITHOLDERS" means the holders from time to time of one or more Trust Units, as
shown on the register of such holders maintained by the Trust or by the Transfer
Agent on behalf of the Trust.
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 renewal annual information form are in Canadian dollars, except where
otherwise indicated.
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ABBREVIATIONS
OIL AND NATURAL GAS LIQUIDS NATURAL GAS
- --------------------------- -----------
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 6.293
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
5
YOU SHOULD NOT RELY ON FORWARD-LOOKING STATEMENTS
BECAUSE THEY ARE INHERENTLY UNCERTAIN
Certain statements contained in this renewal annual information form, and in
certain documents incorporated by reference into this renewal annual information
form, constitute forward-looking statements. These statements relate to future
events or our future performance. All statements other than statements of
historical fact may be forward-looking statements. Forward-looking statements
are often, but not always, identified by the use of words such as "seek",
"anticipate", "plan", "continue", "estimate", "expect", "may", "will",
"project", "predict", "potential", "targeting", "intend", "could", "might",
"should", "believe" and similar expressions. These statements involve known and
unknown risks, uncertainties and other factors that may cause actual results or
events to differ materially from those anticipated in such forward-looking
statements. We 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 renewal annual information
form should not be unduly relied upon. These statements speak only as of the
date of this renewal annual information form or as of the date specified in the
documents incorporated by reference into this renewal annual information form,
as the case may be.
In particular, this renewal annual information form, and the documents
incorporated by reference, contain forward-looking statements pertaining to the
following:
o the performance characteristics of our assets;
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 renewal 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 fluctuation in foreign exchange or interest rates;
o stock market volatility and market valuations;
o changes in income tax laws or changes in tax laws and incentive
programs relating to the oil and gas industry and income trusts;
o geological, technical, drilling and processing problems and other
difficulties in producing petroleum reserves; and
o the other factors discussed under "Risk Factors".
Statements relating to "reserves" or "resources" are deemed to be
forward-looking statements, as they involve the implied assessment, based on
certain estimates and assumptions, that the resources and reserves described can
be profitably produced in the future. Readers are cautioned that the foregoing
lists of factors are not exhaustive. The forward looking statements contained in
this renewal annual information form and the documents incorporated by reference
herein are expressly qualified by this cautionary statement. Neither the Trust,
the Manager, nor AOG undertakes any obligation to publicly update or revise any
forward-looking statements and readers should also carefully consider the
matters discussed under the heading "Risk Factors" in this renewal annual
information form.
6
ADVANTAGE ENERGY INCOME FUND
GENERAL
Advantage Energy Income Fund ("ADVANTAGE", the "TRUST", the "FUND", "US", "WE",
or "OUR" and, where the context requires, also includes the Trust's
subsidiaries) is an entity that provides monthly cash distributions to its
holders ("UNITHOLDERS") of trust units ("TRUST UNITS") of the Trust. 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.
Advantage Oil & Gas Ltd. ("AOG") is an oil and natural gas exploitation and
development company that is wholly-owned by us. It was originally incorporated
in 1979 as Westrex Energy Corp. ("WESTREX"). Through a plan of arrangement under
the BUSINESS CORPORATIONS ACT (Alberta) ("ABCA"), Westrex merged with Search
Energy Inc. on December 31, 1996, and changed its name to Search Energy Corp.
("SEARCH") on January 2, 1997.
Effective May 24, 2001, all of the issued and outstanding common shares of
Search were acquired by 925212 Alberta Ltd. ("ACQUISITIONCO"), a corporation
wholly-owned by us. 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 Resources Inc. ("DUE WEST"). Effective August 1, 2001, Search and Due
West were amalgamated and continued as "Search Energy Corp.". Effective January
1, 2002, Search acquired a number of natural gas properties located primarily in
southern Alberta formerly administered by Gascan Resources Ltd. 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 Resources
Ltd. ("BEST PACIFIC"). On December 2, 2003, AOG acquired all of the issued and
outstanding shares of MarkWest Resources Canada Corp. ("MARKWEST"). MarkWest was
amalgamated with AOG effective January 1, 2004. On September 15, 2004, we
indirectly acquired certain petroleum and natural gas properties and related
assets from Anadarko Canada Corporation ("ANADARKO") for approximately
$186,000,000 before closing adjustments. On December 21, 2004, we indirectly
acquired Defiant Energy Corporation ("DEFIANT") by way of the Arrangement (as
defined herein) involving a combination of cash consideration, Trust Units and
Exchangeable Shares of AOG. Effective January 1, 2005, Defiant amalgamated with
AOG.
In accordance with the Management Agreement, Advantage Investment Management
Ltd. (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.
Our head office, the head office of the Manager and AOG and the registered
office of AOG is located at Suite 3100, 150 - 6th Avenue S.W., Calgary, Alberta,
T2P 3Y7. The registered office of the Manager is located at Suite 1400, 350 -
7th Avenue S.W., Calgary, Alberta, T2P 3N9.
OUR ORGANIZATIONAL STRUCTURE
The following diagram sets forth our organizational structure as at the date
hereof.
[GRAPHIC OMITTED]
[ORGANIZATIONAL CHART]
Notes:
(1) The Unitholders own 100% of the Trust.
(2) Cash distributions are made to Unitholders monthly based upon our 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 us as to how to vote in
respect of all matters to be placed before us, including the selection of
directors of AOG, approving AOG's financial statements, and appointing the
auditors of AOG, who shall be the same as our auditors. The Shareholder
Agreement provides that the Unitholders are entitled to elect a majority of the
board of directors of AOG and the Manager has the right to designate two of such
directors.
GENERAL DEVELOPMENT OF THE BUSINESS
2002
On January 29, 2002, we 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. We used the net proceeds
of the issue to complete the acquisition of certain natural gas properties, to
repay bank debt and to fund our 2002 capital expenditure program.
The first annual and special meeting of Unitholders was held on June 25, 2002 at
which, among other things, Unitholders considered and approved the name change
from "Search Energy Corp." to "Advantage Oil & Gas Ltd." and the addition of a
class of non-voting common shares for AOG. On September 10, 2002, we completed
an asset exchange transaction whereby it acquired additional interests in
producing natural gas properties at Vermilion, Alberta in consideration for our
interest in heavy oil properties located in Wainwright, Alberta. The exchange
was structured as a property swap with us neither receiving nor paying any cash
in relation to the transaction.
On September 30, 2002, we announced that it had entered into an acquisition
agreement providing for an offer to purchase, by way of formal take-over bid,
all of the issued and outstanding common shares of Best Pacific, including all
shares issued upon the exercise of outstanding options and warrants, on the
basis of $1.25 cash consideration for each share. We acquired 95% of the shares
and completed the compulsory acquisition of the remaining shares effective
November 21, 2002. The acquisition of Best Pacific had a net purchase price,
after adjustments and fees, of
8
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.
On October 18, 2002, in conjunction with the acquisition of Best Pacific, we
closed an offering, on a bought deal basis by way of short form prospectus, of
$55,000,000 aggregate principal amount of debentures, which 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 (the "10% DEBENTURES"). Interest is payable
on the 10% Debentures semi-annually and commenced on May 1, 2003. The net
proceeds of the offering were used to fund the acquisition of Best Pacific, to
reduce bank indebtedness and for general corporate purposes.
2003
On July 8, 2003, we completed the issue, by way of short form prospectus, of
$30,000,000 principal amount of 9% convertible unsecured subordinated
debentures, which debentures mature on August 1, 2008 and are convertible into
Trust Units at $17.00 per Trust Unit (the "9% DEBENTURES"). The net proceeds of
the offering were used to fund an expanded capital expenditure program and to
repay debt.
On December 8, 2003, we 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 subordinated debentures, which debentures mature on February 1, 2009
and are convertible into Trust Units at $16.50 per Trust Unit (the "8 1/4%
DEBENTURES"). The net proceeds of the offering were used to fund the acquisition
of MarkWest, to reduce amounts outstanding under our credit facility and to fund
drilling and exploitation capital expenditures. In conjunction with the
completion of the financing, we also announced the completion of the MarkWest
acquisition for total cash consideration of $96,800,000 prior to adjustments.
2004
On September 15, 2004, we completed an issue, by way of short form prospectus,
of 3,500,000 Trust Units and $75 million aggregate principal amount of 7.50%
convertible unsecured subordinated debentures (the "7.50% Debentures") and $50
million aggregate principal amount of 7.75% convertible unsecured subordinated
debentures (the "7.75% DEBENTURES") to partially finance the acquisition of
certain petroleum and natural gas properties and related assets from Anadarko.
On December 21, 2004, we closed the Defiant Acquisition in exchange for a
combination of cash consideration, Trust Units and Exchangeable Shares of AOG.
See "Significant Acquisitions" for further details.
On December 21, 2004, we announced the closing of our acquisition of Defiant
(the "DEFIANT ACQUISITION") by way of plan of arrangement (the "ARRANGEMENT")
under section 193 of the ABCA. Pursuant to the Arrangement, shareholders of
Defiant could elect to receive (i) 0.201373 of a Trust Unit for each Defiant
share, (ii) 0.201373 of an AOG exchangeable share for each Defiant share, or
(iii) $2.79889 per Defiant share and the balance of the consideration in Trust
Units as set out in option (i). In addition, Defiant shareholders received one
sixth of one common share of Defiant Resources Corporation, a newly incorporated
exploration company.
The Defiant Acquisition is consistent with our strategy of focusing on natural
gas and light oil properties that provide low risk drilling upside. The
transaction is accretive to our 2005 cash flow and production per unit and
provides us with additional lower risk drilling and recompletion opportunities.
The asset base acquired from Defiant is highly concentrated consisting of three
core areas located in central Alberta in close proximity to our existing
operations and approximately 90% of the production is operated, with four
projects representing 85% of the current production.
SIGNIFICANT ACQUISITIONS
On September 15, 2004, we indirectly acquired certain petroleum and natural gas
properties and related assets from Anadarko Canada Corporation (the "ACQUIRED
ASSETS") for total consideration of approximately $186 million before closing
adjustments (the "ASSET ACQUISITION"). The Asset Acquisition has an effective
date of July 1, 2004. The Business Acquisition Report in respect of the Asset
Acquisition, dated September 30, 2004, was filed in accordance with Part 8 of
National Instrument 51-102 Continuous Disclosure Obligations ("NI 51-102") and
is incorporated herein by reference.
9
ANTICIPATED CHANGES IN THE BUSINESS
As at the date hereof, we do not anticipate that any material change in our
business shall occur during the balance of the 2005 financial year.
RECENT DEVELOPMENTS
On February 9, 2005, we completed an issue, by way of short form prospectus, of
5,250,000 Trust Units at $21.65 per Trust Unit for gross proceeds of
$113,662,500. We initially used the net proceeds of the offering to repay a
portion of our indebtedness under our credit facilities incurred in connection
with, among other things, the Defiant Acquisition. The net proceeds will
ultimately be used for our 2005 capital expenditure program and for general
purposes. As at the closing of the offering, 56,575,489 Trust Units were issued
and outstanding.
DESCRIPTION OF OUR BUSINESS AND OPERATIONS
ADVANTAGE ENERGY INCOME FUND
We are a limited purpose trust and are 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 our behalf or using any of our assets or
property which are defined as "foreign property" under subsection
206(1) of the INCOME TAX ACT (Canada) ("TAX ACT") or are a "small
business security" as that expression is used in Part LI of the
Regulations to the Tax Act or would result in us 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 us 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
ours 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
we 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, we will make cash
distributions to our Unitholders of the interest income earned from the Long
Term 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".
10
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.
We employ 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 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
our 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, the issuance of additional
Trust Units from treasury and the issuance of subordinated convertible
debentures, maintaining prudent leverage.
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 of AOG 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 assist in executive decisions which conform
to the general policies and general principles previously established by the
board of directors. The Manager is entitled to designate two directors to serve
on the board of directors. The Manager also provides executive officers to AOG,
subject to the approval of the board of directors of AOG.
STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION
The report of management and directors on oil and gas disclosure in Form
51-101F3 and the report on reserves data by Sproule Associates Limited
("SPROULE") in Form 51-101F2 are attached as Schedules "A" and "B" to this
renewal annual information form, which forms are incorporated herein by
reference.
The statement of reserves data and other oil and gas information set forth below
(the "STATEMENT") is dated December 31, 2004. The effective date of the
Statement is December 31, 2004 and the preparation date of the Statement is
February 17, 2005.
DISCLOSURE OF RESERVES DATA
The reserves data set forth below (the "RESERVES DATA") is based upon an
evaluation by Sproule with an effective date of December 31, 2004 contained in a
report of Sproule dated February 17, 2005 (the "SPROULE REPORT"). The Reserves
Data summarizes our oil, liquids and natural gas reserves 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 our 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 OUR 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.
11
RESERVES DATA (CONSTANT PRICES AND COSTS)
SUMMARY OF OIL AND GAS RESERVES
AND NET PRESENT VALUES OF FUTURE NET REVENUE
as of December 31, 2004
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 11,880.9 10,400.1 1,456.2 1,300.2 189,026 159,160 2,628.9 1,945.4
Developed Non-Producing 491.0 398.7 0.0 0.0 9,497 7,703 134.8 98.6
Undeveloped 3,271.1 2,900.4 0.0 0.0 15,813 12,334 376.5 275.8
Total Proved 15,643.0 13,699.2 1,456.2 1,300.2 214,335 179,197 3,140.2 2,319.8
-------- -------- ------- ------- ------- ------- ------- -------
Probable 11,501.6 10,042.8 597.1 536.8 85,562 69,139 1,897.7 1,391.1
-------- -------- ------- ------- ------- ------- ------- -------
Total Proved Plus Probable 27,144.6 23,742.0 2,053.3 1,837.0 299,897 248,335 5,037.9 3,710.9
======== ======== ======= ======= ======= ======= ======= =======
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 1,146,393 843,443 684,199 584,120 514,455 1,146,393 843,443 684,199 584,120 514,455
Developed Non- 47,966 37,858 31,125 26,314 22,708 47,966 37,858 31,125 26,314 22,708
Producing
Undeveloped 112,906 79,814 56,660 40,864 29,626 112,906 79,814 56,660 40,864 29,626
Total Proved 1,307,266 961,114 771,984 651,299 566,788 1,307,266 961,114 771,984 651,299 566,788
--------- --------- --------- ------- ------- --------- --------- --------- ------- -------
Probable 654,920 361,057 240,149 176,219 136,995 654,920 361,057 240,149 176,219 136,995
--------- --------- --------- ------- ------- --------- --------- --------- ------- -------
Total Proved Plus
Probable 1,962,185 1,322,172 1,012,134 827,519 703,783 1,962,185 1,322,172 1,012,134 827,519 703,783
========= ========= ========= ======= ======= ========= ========= ========= ======= =======
TOTAL FUTURE NET REVENUE
(UNDISCOUNTED)
as of December 31, 2004
CONSTANT PRICES AND COSTS
($000's)
Future Net Future Net
Well Sask. Revenue Revenue
Reserves Operating Development Abandonment Corp. Before Income Income After Income
Category Revenue Royalties Costs Costs Costs Capital Tax Taxes Taxes Taxes
-------- ------- --------- ----- ----- ----- ----------- ----- ----- -----
Proved 2,249,881 357,089 485,710 65,829 29,524 4,463 1,307,266 0 1,307,266
Proved Plus
Probable 3,394,537 555,981 741,478 96,565 30,576 7,753 1,962,185 0 1,962,185
12
FUTURE NET REVENUE
BY PRODUCTION GROUP
as of December 31, 2004
CONSTANT PRICES AND COSTS
Future Net Revenue Before
Income Taxes (Discounted At
Reserves Category Production Group 10%/Year)
----------------- ---------------- ---------
($000's)
Proved Light and Medium Crude Oil (including solution gas and other 245,588
by-products)
Heavy Oil (including solution gas and other by-products) 4,504
Natural Gas (including by-products but excluding solution gas 513,826
from oil wells)
Proved Plus Probable Light and Medium Crude Oil (including solution gas and other 364,482
by-products)
Heavy Oil (including solution gas and other by-products) 7,333
Natural Gas (including by-products but excluding solution gas 631,877
from oil wells)
RESERVES DATA (FORECAST PRICES AND COSTS)
SUMMARY OF OIL AND GAS RESERVES
AND NET PRESENT VALUES OF FUTURE NET REVENUE
as of December 31, 2004
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 11,714.2 10,292.0 1,562.4 1,359.8 186,137 156,849 2,601.3 1,928.6
Developed Non-Producing 490.8 399.5 0.0 0.0 9,494 7,701 134.8 98.7
Undeveloped 3,262.6 2,903.6 0.0 0.0 15,764 12,292 376.7 276.1
Total Proved 15,467.6 13,595.1 1,562.4 1,359.8 211,395 176,841 3,112.8 2,303.5
-------- -------- ------- ------- ------- ------- ------- -------
Probable 11,318.6 9,953.6 624.1 539.7 82,552 66,598 1,874.1 1,378.5
-------- -------- ------- ------- ------- ------- ------- -------
Total Proved Plus Probable 26,786.2 23,548.7 2,186.5 1,899.5 293,946 243,439 4,986.9 3,682.0
======== ======== ======= ======= ======= ======= ======= =======
Net Present Values Of Future Net Revenue
------------------------------------------------------------------------------------------------
Before Income Taxed 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 984,488 739,592 613,438 534,063 478,300 984,488 739,592 613,438 534,063 478,300
Producing
Developed 38,209 30,840 25,880 22,283 19,543 38,209 30,840 25,880 22,283 19,543
Non-Producing
Undeveloped 83,899 62,321 44,808 32,454 23,510 83,899 62,321 44,808 32,454 23,510
Total Proved 1,106,596 832,752 684,126 588,800 521,354 1,106,596 832,752 684,126 588,800 521,354
--------- --------- ------- ------- ------- --------- --------- ------- ------- -------
Probable 563,511 302,458 200,968 148,757 117,031 563,511 302,458 200,968 148,757 117,031
--------- --------- ------- ------- ------- --------- --------- ------- ------- -------
Total Proved Plus
Probable 1,670,108 1,135,209 885,094 737,557 638,385 1,670,108 1,135,209 885,094 737,557 638,385
========= ========= ======= ======= ======= ========= ========= ======= ======= =======
13
TOTAL FUTURE NET REVENUE
(UNDISCOUNTED)
as of December 31, 2004
FORECAST PRICES AND COSTS
($000's)
Future Net Future Net
Well Revenue Revenue
Reserves Operating Development Abandonment Sask. Corp. Before Income After Income
Category Revenue Royalties Costs Costs Costs Capital Tax Income Taxes Taxes Taxes
-------- ------- --------- ----- ----- ----- ----------- ------------ ----- -----
Proved 2,097,734 325,069 556,424 66,184 38,527 4,936 1,106,596 0 1,106,596
Proved Plus
Probable 3,198,813 504,336 875,288 97,277 43,451 8,371 1,670,108 0 1,670,108
FUTURE NET REVENUE
BY PRODUCTION GROUP
as of December 31, 2004
FORECAST PRICES AND COSTS
Future Net Revenue Before
Income Taxes (Discounted At
Reserves Category Production Group 10%/Year)
----------------- ---------------- ---------
($000's)
Proved Light and Medium Crude Oil (including solution gas and other 222,377
by-products)
Heavy Oil (including solution gas and other by-products) 9,750
Natural Gas (including by-products but excluding solution gas 444,090
from oil wells)
Proved Plus Probable Light and Medium Crude Oil (including solution gas and other 323,969
by-products)
Heavy Oil (including solution gas and other by-products) 13,500
Natural Gas (including by-products but excluding solution gas 539,228
from oil wells)
PRICING ASSUMPTIONS
The following tables set forth the benchmark reference prices, as at December
31, 2004, reflected in the Reserves Data. These price assumptions were provided
to us by Sproule and were Sproule's then current forecasts at the date of the
Sproule Report.
SUMMARY OF PRICING ASSUMPTIONS
as of December 31, 2004
CONSTANT PRICES AND COSTS
Oil(1)
-----------------------------------------------------
Natural
Gas(1)
WTI Edmonton Hardisty AECO Gas Pentanes Propanes
Cushing Par Price Heavy Cromer Medium Price Plus Fob Butanes Fob Fob Field Exchange
Oklahoma 40(degree)API 12(degree)API 29.3(degree)API ($Cdn/ Field Gate Field Gate Gate Rate(2)
Year ($US/bbl) ($Cdn/bbl) ($Cdn/bbl) ($Cdn/bbl) MMBtu) ($Cdn/bbl) ($Cdn/bbl) ($Cdn/bbl) ($US/$Cdn)
- ---- --------- ---------- ---------- ---------- ------ ---------- ---------- ---------- ----------
Historical (3)
2004 44.04 46.51 15.26 32.10 6.78 51.80 39.78 36.11 0.8319
Notes:
(1) This summary table identifies benchmark reference pricing schedules
that might apply to a REPORTING ISSUER.
(2) The exchange rate used to generate the benchmark reference prices in
this table.
(3) As at December 31.
14
SUMMARY OF PRICING AND INFLATION RATE ASSUMPTIONS
as of December 31, 2004
FORECAST PRICES AND COSTS
Oil(1)
-----------------------------------------------------
Natural Pentanes Propane
Gas(1) Plus Fob Butanes Fob
WTI Edmonton Hardisty Cromer Aeco Gas Field Fob Field
Cushing Par Price Heavy Medium Price Gate Field Gate Inflation Exchange
Oklahoma 40(degree)API 12(degree)API 29.3(degree)API ($Cdn/ ($Cdn/ Gate ($Cdn/ Rates(2) Rate(3)
Year ($US/Bbl) ($Cdn/Bbl) ($Cdn/Bbl) ($Cdn/Bbl) MMbtu) Bbl) ($Cdn/Bbl) bbl) %/Year ($US/$Cdn)
- ---- --------- ---------- ---------- ---------- ------ ---- ---------- ---- ------ ----------
Forecast
2005 44.29 51.25 28.91 44.53 6.97 52.49 38.20 32.09 2.5 0.840
2006 41.60 48.03 28.12 41.87 6.66 49.19 34.01 30.07 2.5 0.840
2007 37.09 42.64 26.19 37.27 6.21 43.67 30.20 26.70 2.5 0.840
2008 33.46 38.31 25.06 33.43 5.73 39.23 27.13 23.98 2.5 0.840
2009 31.84 36.36 23.60 31.70 5.37 37.24 25.75 22.76 1.5 0.840
2010 32.32 36.91 24.12 32.22 5.47 37.80 26.13 23.11 1.5 0.840
2011 32.80 37.47 24.64 32.75 5.57 38.37 26.53 23.46 1.5 0.840
2012 33.30 38.03 25.17 33.29 5.67 38.95 26.93 23.81 1.5 0.840
2013 33.79 38.61 25.71 33.83 5.77 39.54 27.34 24.17 1.5 0.840
2014 34.30 39.19 26.26 34.38 5.87 40.14 27.75 24.53 1.5 0.840
Thereafter 1.5% 1.5% 1.5% 1.5% 1.5% 1.5% 1.5% 1.5% 1.5 0.840
Notes:
(1) This summary table identifies benchmark reference pricing schedules
that might apply to a REPORTING ISSUER.
(2) Inflation rates for forecasting prices and costs.
(3) Exchange rates used to generate the benchmark reference prices in this
table.
Weighted average historical prices realized by us for the year ended December
31, 2004, were $6.43/Mcf for natural gas, $47.62/bbl for crude oil, $41.91/bbl
for natural gas liquids.
15
RECONCILIATIONS OF CHANGES IN RESERVES AND FUTURE NET REVENUE
RECONCILIATION OF
TRUST NET RESERVES
BY PRINCIPAL PRODUCT TYPE
FORECAST PRICES AND COSTS
Light And Medium Oil Heavy Oil Natural Gas Liquids
------------------------------ -------------------------------- --------------------------------
Net Net Net
Proved Proved Proved
Net Net Plus Net Plus Net Net Plus
Proved Probable Probable Net Proved Probable Probable Proved Probable Probable
--------- --------- --------- ---------- --------- --------- --------- ---------- ---------
FACTORS (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl)
December 31, 2003 5,790 4,058 9,848 4 1 5 1,380 593 1,973
Extensions 1,794 1,050 2,844 0 0 0 318 234 552
Improved Recovery 0 0 0 0 0 0 0 0 0
Technical Revisions 637 (153) 484 318 301 619 98 146 244
Discoveries 0 0 0 0 0 0 0 0 0
Acquisitions 6,750 5,202 11,952 1,149 238 1,387 726 405 1,131
Dispositions (187) (237) (424) 0 0 0 (5) (7) (12)
Economic Factors 137 34 171 0 0 0 8 7 15
Production (1)(2) (1,326) 0 (1,326) (111) 0 (111) (221) 0 (221)
------ ----- ------ ----- --- ----- ----- ----- -----
December 31, 2004 13,595 9,954 23,549 1,360 540 1,900 2,304 1,378 3,682
====== ===== ====== ===== === ===== ===== ===== =====
Associated and Non-Associated Gas Solution Gas
--------------------------------- --------------------------------
Net Net
Proved Proved
Net Net Plus Net Net Plus
Proved Probable Probable Proved Probable Probable
--------- ---------- --------- --------- ---------- ---------
FACTORS (mmcf) (mmcf) (mmcf) (mmcf) (mmcf) (mmcf)
December 31, 2003 152,850 40,074 192,924 5,010 3,906 8,916
Extensions 219 197 416 5,414 3,960 9,374
Improved Recovery 0 0 0 0 0 0
Technical Revisions 1,794 (379) 1,415 527 288 815
Discoveries 0 0 0 0 0 0
Acquisitions 27,986 14,348 42,334 8,285 3,683 11,968
Dispositions 0 0 0 (60) (99) (159)
Economic Factors 1,197 534 1,731 220 86 306
Production (1)(2) (25,575) 0 (25,575) (1,026) 0 (1,026)
------- ------ ------- ------ ------ ------
December 31, 2004 158,471 54,774 213,245 18,370 11,824 30,194
======= ====== ======= ====== ====== ======
Note:
(1) Includes production from the Anadarko properties from September 15 -
December 31, 2004.
(2) Includes Defiant production from December 21 - December 31, 2004.
16
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 2004
- ----------------------------------------------------------------------------------------- --------
Estimated Future Net Revenue at Beginning of Year 520,226
Sales and Transfers of Oil and Gas Produced, Net of Production Costs and Royalties (154,631)
Net Change in Prices, Production Costs and Royalties Related to Future Production 33,225
Actual Development Costs Incurred During the Period 107,893
Changes in Estimated Future Development Costs (54,083)
Extensions and Improved Recovery 39,407
Discoveries 0
Acquisitions of Reserves 245,905
Dispositions of Reserves (4,342)
Net Change Resulting from Revisions in Quantity Estimates 20,074
Accretion of Discount 18,310
Net Change in Income Taxes 0
-
Estimated Future Net Revenue at End of Year 771,984
=======
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 2005. The following tables set forth the
proved undeveloped reserves and the probable undeveloped reserves, each by
product type, attributed to us in the most recent financial year.
PROVED UNDEVELOPED RESERVES
Light and Medium Oil Heavy Oil Natural Gas Natural Gas Liquids
Year (Mbbl) (Mbbl) (MMcf) (Mbbl) Mboe
- ---- ------ ------ ------ ------ ----
2004 3,263 0 15,765 377 6,267
PROBABLE UNDEVELOPED RESERVES
Light and Medium Oil Heavy Oil Natural Gas Natural Gas Liquids
Year (Mbbl) (Mbbl) (MMcf) (Mbbl) Mboe
- ---- ------ ------ ------ ------ ----
2004 5,757 35 15,685 579 8,985
SIGNIFICANT FACTORS OR UNCERTAINTIES
High operating costs substantially reduce our netback, which in turn reduces the
amount of cash available for reinvestment in drilling opportunities. This
becomes most relevant during periods of low commodity prices when profits are
more significantly impacted by high costs.
FUTURE DEVELOPMENT COSTS
The following table sets forth development costs deducted in the estimation of
our future net revenue attributable to the reserve categories noted below.
17
Constant Prices and Costs
Forecast Prices and Costs ($000's) ($000's)
-------------------------------------------------------- -------------------------
Year Proved Reserves Proved Plus Probable Reserves Proved Reserves
- ---- --------------- ----------------------------- ---------------
0% 10% 0% 10% 0% 10%
-- --- -- --- -- ---
2005 56,467 54,715 81,205 78,187 56,467 54,715
2006 6,408 5,554 12,219 10,591 6,252 5,421
2007 2,158 1,701 2,267 1,786 2,054 1,621
2008 811 581 822 589 753 539
Additional years 340 179 764 371 303 160
Total 66,184 62,730 97,277 91,524 65,829 62,456
To fund our capital program, including future development costs, we have many
financing alternatives available including partial retention of cash flow from
operations, bank debt financing, issuance of additional Trust Units, and
convertible debentures. We evaluate the appropriate financing alternatives
closely and have made use of all these options dependent on the given investment
situation and the capital markets. We maintain a capital structure that is
similar to our industry peer group and that will maximize the investment return
to Unitholders as compared to the cost of financing. We expect to continue using
all financing alternatives available to continue pursuing our oil and gas
development strategy. The assorted financing instruments have certain inherent
costs which we consider in the economic evaluation of pursuing any development
opportunity.
OTHER OIL AND GAS INFORMATION
OIL AND GAS PROPERTIES
The following is a description of our principal oil and natural gas properties
on production or under development as at January 1, 2005. The term "net", when
used to describe our share of production, means the total of our working
interest share before deduction of royalties owned by others. Reserve amounts
are stated, before deduction of royalties, at December 31, 2004, based upon
forecast cost and price assumptions (gross) as evaluated in the Sproule Report.
Unless otherwise specified, gross and net acres and well count information are
as at January 1, 2005. Information in respect of current production is 2004 exit
production, net to us, except where otherwise indicated.
MEDICINE HAT, ALBERTA
The Medicine Hat (Bowmanton) property is located 20 km northeast of the City of
Medicine Hat in the heart of the southeastern shallow gas area. We have a 100%
working interest in 24 sections of land from which production is taken from all
of the main shallow gas producing formations including the Medicine Hat "A", "C"
and "D" sands, as well as both the Upper and Lower Milk River 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. Late in 2003 an additional 57 wells were drilled and
completed in 2004. In 2004 a further 68 wells were drilled and completed. As a
result, in January 2005 this property was producing 21.2 MMcf/d from
approximately 380 wells. Compression capacity was increased in late 2003 by
approximately 10 MMcf/d to accommodate added production from the drilling
programs. No additional compression was added in 2004.
Sproule evaluated our reserves in the area and assigned 65.6 bcf of proved
natural gas reserves and 8.2 bcf of probable reserves. As such, this property is
our largest property on an assigned reserves basis.
NEVIS, ALBERTA
The Nevis property is situated 50 km east of Red Deer. Nevis consists of
approximately 35 sections of land with an average working interest over 75% and
is 90% operated. Natural gas production occurs from numerous shallow depth
horizons including the Edmonton, Belly River and Viking formations. Oil and
natural gas is produced from the slightly deeper reservoirs (1,200 m) of the
Glauconite, Ostacod and Ellerslie formations within the Mannville Group. The
main zone of interest however occurs at 1,600 meters in Devonian aged carbonates
of the Big Valley Member of the Wabamun Formation. In 2004, Wabamun oil was
principally targeted, although gas was also drilled in both the Wabamun and
shallower horizons. Development of the oil is being accomplished by horizontal
drilling into the average 3 meter thick
18
carbonate. Completion of wells is accomplished with selective acid squeezes over
the main porous intervals. Crude quality is exceptional ranging in the most part
between 36 and 42o API. Natural gas is gathered through AOG owned pipelines and
processed at a third party plant. Oil is trucked from single well batteries.
In 2004, 16 horizontal wells and 5 vertical wells were drilled. We currently
have on production, or awaiting imminent tie-in, 14 horizontal wells, which were
all drilled prior to year end of 2004. Production at the end of January 2005 is
2,039 boe/d. An additional 12 wells have been drilled in 2005 to the end of
February. Currently the pool is spaced to allow for 4 wells per section.
Drilling continues at the current spacing; however, the property is being
reviewed for down spacing to 8 wells per section in the second half of 2005. In
addition a study is underway to evaluate the potential waterflood of this
reservoir to increase future recoveries.
The Sproule Report assigns 13 bcf of proven natural gas reserves and 3,314 Mbbls
of proven crude oil and NGL reserves to this property. In addition, 8.4 bcf of
probable natural gas reserves and 2,445 Mbbls of risked probable crude oil and
NGL reserves have been assigned to this property.
BANTRY, ALBERTA
Bantry is located immediately east of the town of Brooks straddling the
TransCanada Highway. The property consists of 86 sections of land ranging
between 50% and 100% working interest. Since the acquisition of this property in
November 2003, 48 (gross) new wells were drilled. Production occurs primarily
from Basal Colorado Formation channel sandstones and various sandstones within
the Bow Island Formation. Drilling depth is shallow with average wells less than
1,000 meters.
Natural gas is gathered into our operated compression and dehydration
facilities. Current net production from this area is approximately 1.6 Mboe/d.
Additional compression capacity was added in the first quarter of 2004 to handle
incremental volumes. The property was last drilled in June 2004 and all
productive wells have been completed and tied-in, however it is being reviewed
for additional drilling with 5 to 6 new wells possible in late 2005 or into
2006.
The Sproule Report assigns 17.1 bcf of proven natural gas reserves and 28 Mbbls
of proven NGL reserves to this property. In addition, 6.9 bcf of probable
natural gas reserves and 11 Mbbls of probable NGL reserves have been assigned to
this property.
CHIP LAKE, ALBERTA
The Chip Lake property is located 125 km west of Edmonton. It produces light oil
(37oAPI) from the Jurassic aged Rock Creek Formation, with some associated
natural gas. This property was acquired in December 2004 with the Defiant
Acquisition. Currently the property produces 250 bbls/d and 300 mcf/d. One well
drilled in the 4th quarter of 2004 has been completed and is being equipped for
production. Additional drilling will occur after regulatory approval of the
facility and waterflood has been received. Defiant had essentially built the oil
facility and water handling facilities but had not received approval to commence
operations. We are currently working through the process with the EUB and expect
to have the property fully operational in the second half of 2005. Production is
however occurring by the use of single well batteries. In addition to the
existing pool, we also acquired some additional undeveloped land with the
Defiant Acquisition and has seismically identified stepout opportunities.
The Sproule Report assigns 1.5 bcf of proven natural gas reserves and 2,300
Mbbls of proven crude oil and NGL reserves to this property. In addition, 1.7
bcf of probable natural gas reserves and 2,441 Mbbls of risked probable crude
oil and NGL reserves have been assigned to this property.
SUNSET-VALLEYVIEW AREA, ALBERTA
This area is located approximately 100 km east of the city of Grande Prairie,
just north of the town of Valleyview. It consists of a group of three main
producing properties: Sunset A, Sunset B, and Valleyview. All three properties
produce from the Triassic Montney Formation, with some production from younger
Cretaceous reservoirs such as the Gething. These properties came with the
Defiant Acquisition in December 2004.
19
SUNSET A- Montney production in these reservoirs is both oil and gas and occurs
from progressively younger stratigraphic traps beneath the Jurassic
unconformity. The youngest sand is preserved the furthest downdip at the Sunset
A pool and production is predominantly oil at 32oAPI. This pool is unitized and
we have a 70% interest in the unit and operate. Development plans include the
drilling of three wells spaced across the unit which will evaluate the viability
of moving the full pool onto a downspaced basis. In addition, a pipeline and
accompanying compression is planned to gather solution gas and transport it to
the Sunset B facility to the north. Gas is currently being flared. Current net
production from the Sunset A unit is 158 bbls/d and 160 mcf/d. The Sunset A pool
was discovered in 1960 and has a long history of stable low decline production.
It is one of our longest life reservoirs.
SUNSET B - Production from this Montney reservoir is predominantly gas although
there is a thin oil column. Oil gravity is light at 33oAPI. Defiant began
operations at Sunset B in mid 2000 and commissioned a sour gas processing plant
and gathering system late that year. The plant and gathering system were
expanded in December 2003, increasing total throughput capacity to 12 MMcf/d.
There is potential to add further compression and upgrades in modular increments
to increase throughput capacity to approximately 20 MMcf/d. Current production
from Sunset B is 3,000 Mcf/d and 100 bbls/d. A small amount of gas is produced
as well from the Cretaceous and Bluesky reservoirs. Sunset B has a long
production history and long reserve life. The original discovery well, Defiant
Sunset 2-14-70-20 W5M, has been on production for 28 years, and has recovered
350 Mboe to date and still produces 12 bbls/d and 85 mcf/d.
VALLEYVIEW - The Sunset B and Valleyview properties are in close proximity to
each other, with the Valleyview property connected to the Sunset B gas
processing plant by a twelve kilometre pipeline where natural gas, NGL and light
oil from both properties are processed. Production at Valleyview is from three
separate sands all older than those at Sunset A or B. Additional drilling
locations exist and seismic re-interpretation is underway to confirm these.
Production at Valleyview is essentially all natural gas with current rates of
5.1 MMcf/d. All wells require fracture stimulation to bring them on production
and cost about $750,000 drilled, completed and tied-in.
For the three properties, Sunset A, Sunset B and Valleyview, the Sproule Report
assigns 25.2 bcf of proven natural gas reserves and 1,537 Mbbls of proven crude
oil and NGL reserves to this property. In addition, 9.8 bcf of probable natural
gas reserves and 1,034 Mbbls of probable crude oil and NGL reserves have been
assigned to this property.
SHOULDICE, ALBERTA
The Shouldice area of southern Alberta is located approximately 45 km southeast
of the city of Calgary. We have an average working interest of more than 85% in
34 sections of land and operate in excess of 90% of our production. Much of this
acreage is downspaced to accommodate additional drilling. In January 2005,
natural gas production of 5,521 MMcf/d was produced on a co-mingled basis from
the Medicine Hat sand with various Belly River Formation sands. In addition to
natural gas, we also produce 42 bbls/d of medium gravity (33(degree) API) crude
oil from the deeper, Mannville Group, Basal Quartz Formation.
During 2003, 20 net wells were added to the existing 70 producers. Both natural
gas and crude oil are produced and gathered through AOG owned facilities of
varying working interests. An additional 4 MMcf/d of new compression capacity
was added in 2004 to handle additional production. Four additional sections of
land have been assembled and the project is under review for additional drilling
later in 2005.
The Sproule Report assigns 12.2 bcf of proven natural gas reserves and 79 Mbbls
of proven crude oil and NGLs to this property. In addition, 2.7 bcf of probable
natural gas reserves and 19 Mbbls of probable crude oil and NGL reserves have
been assigned to this property.
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, is low cost and requires minimal capital expenditures. We own an
interest in 30 producing wells (22 net) in the area. We operate approximately
80% of the natural gas production and have a 40% working interest in the oil
production. The area includes 12,000 gross (9,176
20
net) acres of undeveloped land. Current production from this area is 5 MMcf/d of
natural gas and 140 bbls/d of light oil and NGLs.
Sproule evaluated our proved reserves in the area and assigned 11.1 bcf of
natural gas and 466 Mbbls of crude oil and NGLs. In addition, 4.1 bcf of
probable natural gas reserves and 227 Mbbls of probable crude oil and NGLs
reserves have been assigned to this property.
WAINWRIGHT, ALBERTA
This property, which has varying working interests averaging more than 80% in
approximately 175 sections of land, is located in east central Alberta,
approximately 40 kilometers northwest of Wainwright, Alberta. Current net
production from the property is 5,000 Mcf/d natural gas, 30 bbl/d NGLs and crude
oil. In 2002, we swapped out virtually all of our heavy oil assets in this area
for producing natural gas assets in our adjacent area of Vermilion. Natural gas
production occurs from the Manville Group and Viking Formations at shallow
depths of between 450 and 700 meters. We operate 95% of our production in this
area as well as own and operate a majority interest in an extensive gas
gathering system tied into three Advantage-operated gas compression facilities.
In 2003, 23.3 net wells were drilled for a combination of Viking and Upper
Mannville zones.
Sproule evaluated our proved reserves in the Wainwright area and assigned 9.3
bcf of natural gas. Probable reserves in this area were evaluated by Sproule at
5.6 bcf of natural gas.
BRAZEAU RIVER, ALBERTA
The Brazeau River property is located approximately 50 km west of the town of
Drayton Valley, Alberta. The property produces sour light oil and natural gas
primarily from Devonian aged Nisku pinnacle reefs. The majority of the
production is from a non-operated 50% working interest in the Nisku C, D and E
pools and a 17% working interest in the Nisku A unit. The property was acquired
in the package of assets purchased from Anadarko in 2004. Sweet natural gas is
also produced from eight natural gas wells out of reservoirs in either of the
Cretaceous aged Cardium, Viking or Lower Mannville Formations. Major facility
interests include a 25.7% working interest in the West Pembina Sour Gas Plant
and a 31.6% working interest in the Brazeau River Gas Plant. Current net
production from the property is 4,000 Mcf/d natural gas and 310 bbl/d NGLs and
crude oil.
Sproule evaluated our proved reserves in the Brazeau River area and assigned 3.8
bcf of natural gas and 323 Mbbls of crude oil and NGLs. Probable reserves in
this area were evaluated by Sproule at 2.3 bcf of natural gas and 288 Mbbls of
crude oil and NGLs.
OPEN LAKE, ALBERTA
The Open Lake property is located approximately 35 km north of the town of Rocky
Mountain House, Alberta. The property was acquired in the package of assets
purchased from Anadarko in 2004. We operate and have a 100% working interest in
the Open Lake property. Oil and natural gas production from this property is
multi-zoned from various Cretaceous and Jurassic reservoirs including the Rock
Creek, Ellerslie, Ostracod, Viking, Second White Specks and Belly River
Formations. We have recently re-entered an existing wellbore and completed a
Glauconite zone which has production tested gas rates in excess of 1 MMcf/d. The
well is expected to be tied-in by the end of the 1st quarter 2005. Additional
re-completion opportunities exist in several offsetting wells and we are
actively engaged in re-completing and evaluating these. Net current production
from the property is 2,648 Mcf/d natural gas and 283 bbl/d NGLs and crude oil.
Sproule evaluated our proved reserves in the Open Lake area and assigned 3.4 bcf
of natural gas and 341 Mbbls of crude oil and NGLs. Probable reserves in this
area were evaluated by Sproule at 2.3 bcf of natural gas and 247 Mbbls of crude
oil and NGLs.
21
OIL AND GAS WELLS
The following table sets forth the number and status of wells as at December 31,
2004 in which we have a working interest.
Oil Wells Natural Gas Wells
------------------------------------------ ----------------------------------------
Producing Non-Producing Producing Non-Producing
--------- ------------- --------- -------------
Gross Net Gross Net Gross Net Gross Net
----- --- ----- --- ----- --- ----- ---
Alberta 564 355.9 391 222.4 1,090 934.7 211 120.5
British Columbia 1 0.4 5 2.3 64 37.3 15 6.2
Saskatchewan 187 140.5 86 62.8 - - - -
Manitoba 85 5.1 - - - - - -
--- ----- --- ----- ----- ----- --- -----
Total 837 501.9 482 287.5 1,154 972.0 226 126.7
=== ===== === ===== ===== ===== === =====
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 our developed and undeveloped land holdings as at
December 31, 2004.
Developed Acres Undeveloped Acres Total Acres
------------------------ ------------------------ ------------------------
Gross Net Gross Net Gross Net
----- --- ----- --- ----- ---
Alberta 680,245 334,110 469,438 253,338 1,149,683 587,448
British Columbia 96,934 18,821 24,344 7,335 121,278 26,156
Saskatchewan 30,077 21,466 142,374 124,070 172,451 145,536
------- ------- ------- ------- --------- -------
Total 807,256 374,397 636,156 384,743 1,443,412 759,140
======= ======= ======= ======= ========= =======
We expect that rights to explore, develop and exploit 117,205 net acres of our
undeveloped land holdings will expire by December 31, 2005. The land expirations
do not consider our 2005 exploitation and development program that may result in
extending or eliminating such potential expirations. We closely monitor land
expirations as compared to our development program with the strategy of
minimizing undeveloped land expirations relating to significant identified
opportunities.
22
FORWARD CONTRACTS
We currently have the following hedge contracts in place:
DESCRIPTION OF HEDGE AND TERM VOLUME AVERAGE PRICE
- ----------------------------- ------ -------------
NATURAL GAS - AECO
Fixed Price January to March 2005 10,450 mcf/d $6.30 Cdn/mcf
Fixed Price April to October 2005 34,123 mcf/d $7.45 Cdn/mcf
Collar April to October 2005 11,374 mcf/d Floor $6.86 Cdn/mcf
Ceiling $8.18 Cdn/mcf
Collar April to October 2005 11,374 mcf/d Floor $7.02 Cdn/mcf
Ceiling $8.02 Cdn/mcf
CRUDE OIL - WTI
Fixed Price April to September 2005 1,750 bbls/d $52.11 US/bbl
Collar April to October 2005 1,750 bbls/d Floor $47.00 US/bbl
Ceiling $56.75 US/bbl
ADDITIONAL INFORMATION CONCERNING ABANDONMENT AND RECLAMATION COSTS
We estimate the costs to abandon and reclaim all our shut-in and producing
wells, facilities, gas plants, pipelines, batteries and satellites. No estimate
of salvage value is netted against the estimated cost. Our 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 we hold. 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.
We estimate that we will incur reclamation and abandonment costs on 1,888.1 net
producing and non-producing wells. Costs to abandon and reclaim the producing
wells totals $43.5 million ($10.7 million discounted at 10%) and are included in
the estimate of future net revenue. The additional liability associated with
non-producing wells, pipelines and facilities reclamation costs was estimated to
be $14 million ($2.8 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 our 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 2005, $1.2 million in 2006 and $1.3
million in 2007.
TAX HORIZON
In 2004, we did not pay any income related taxes. However, we did pay capital
taxes that are determined based on the debt and equity levels of the Trust at
the end of a given year. As a result of new legislation in 2003, capital taxes
are to be gradually eliminated over the next four years.
In the Fund's structure, the operating company utilizes available tax pools to
significantly reduce taxable income and makes other required payments to the
Trust transferring both income and associated tax liability to the Unitholders.
Therefore, it is expected, based on current legislation that no cash income
taxes are to be paid by the operating company in the future and it is our intent
to continue with the current arrangement. For the 2004 distributions, 38.33%
were taxable to the Unitholders and 61.67% were deemed a return of capital.
23
CAPITAL EXPENDITURES
The following tables summarize capital expenditures (including capitalized
general and administrative expenses) related to our activities for the year
ended December 31, 2004:
CAPITAL EXPENDITURES ($ THOUSANDS) 2004
- ----------------------------------------------------------------------------- ----------------------
Land and seismic $ 3,034
Drilling, completions and workovers 68,327
Well equipping and facilities 35,655
Other 877
- ----------------------------------------------------------------------------- ----------------------
$107,893
Acquisition of Anadarko Properties 179,115
Acquisition of Defiant Energy Corporation(1) 200,291
Property acquisitions 1,530
Property dispositions (6,539)
- ----------------------------------------------------------------------------- ----------------------
TOTAL CAPITAL EXPENDITURES $482,290
- ----------------------------------------------------------------------------- ----------------------
Note:
(1) Represents consideration of $144.1 million plus net debt assumed of
$56.2 million.
EXPLORATION AND DEVELOPMENT ACTIVITIES
The following table sets forth the gross and net wells in which we participated
during the year ended December 31, 2004:
Exploratory Development Total
------------------- ------------------- ------------------
Gross Net Gross Net Gross Net
Oil wells 10 7.0 30 14.3 40 21.3
Gas wells 5 2.8 147 126.8 152 129.6
Dry holes 4 4.0 15 10.8 19 14.8
Total 19 13.8 192 151.9 211 165.7
In 2005, we plan to drill, complete and tie-in 70 net wells including 32 net
wells in Nevis, 5 net wells in Chain, with the remaining activity occurring
throughout the various areas.
24
PRODUCTION ESTIMATES
The following table sets out the volume of our production estimated for the year
ended December 31, 2005 reflected in the estimate of future net revenue
disclosed in the tables contained under "Disclosure of Reserves Data".
Light and Natural Gas
Medium Oil Heavy Oil Natural Gas Liquids BOE
(bbls/d) (bbls/d) (Mcf/d) (bbls/d) (boe/d)
-------- -------- ------- -------- -------
Proved
Developed Producing 4,839 699 81,419 1,279 20,387
Developed Non-Producing 328 - 2,219 46 745
Undeveloped 799 - 4,028 66 1,535
Total Proved 5,966 699 87,666 1,391 22,667
Probable 720 27 5,463 106 1,763
Total Proved Plus Probable 6,686 726 93,129 1,497 24,430
PRODUCTION HISTORY
The following tables summarize certain information in respect of production,
prices received, royalties paid, operating expenses and resulting netback for
the periods indicated below:
Quarter Ended
--------------------------------------------------------------------
2004
--------------------------------------------------------------------
Dec. 31 Sept. 30 Jun. 30 Mar. 31
------- -------- ------- -------
Average Daily Production(1)
Crude oil and NGLs (bbls/d) 6,815 3,550 3,106 2,841
Natural gas (Mcf/d) 84,336 75,425 73,283 75,649
Combined (boe/d) 20,871 16,121 15,320 15,449
Average Net Prices Received(2)
Crude oil and NGLs ($/bbl) 47.05 51.20 45.36 40.93
Natural gas ($/Mcf) 6.09 5.76 6.20 6.28
Royalties(3)(5)
Crude oil and NGLs ($/bbl) 8.28 8.15 7.22 6.10
Natural gas ($/Mcf) 1.34 1.22 1.28 1.30
Combined ($/boe) 8.12 7.49 7.59 7.51
Operating Expenses(4)(5)
Crude oil and NGLs ($/bbl) 8.87 8.33 6.59 7.57
Natural gas ($/Mcf) 0.97 0.93 0.95 0.92
Combined ($/boe) 6.81 6.19 5.90 5.92
Netback Received(6)
Crude oil and NGLs ($/bbl) 29.90 34.72 31.55 27.26
Natural gas ($/Mcf) 3.78 3.61 3.97 4.06
Combined ($/boe) 25.03 24.56 25.38 24.86
Notes:
(1) Before deduction of royalties.
(2) Production prices are net of costs to transport the product to market
and net of realized hedging gains and losses.
(3) Royalties are net of ARC.
(4) This figure includes all field operating expenses.
25
(5) We do 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 and natural gas
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 our approximate exit daily production from our
important fields at December 31, 2004:
Natural Gas Crude Oil & NGLs Total
Properties (Mcf/d) (bbls/d) (boe/d)
- ------------------------------------------------------------------------------
Medicine Hat 22,296 - 3,716
Sunset 8,196 400 1,766
Bantry 9,540 50 1,640
Nevis 3,540 960 1,550
Shouldice 5,790 60 1,025
Brazeau River 4,218 320 1,023
- ------------------------------------------------------------------------------
Major Properties 53,580 1,790 10,720
Other 39,420 5,710 12,280
- ------------------------------------------------------------------------------
TOTAL 93,000 7,500 23,000
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 Sproule Report are based on 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.
"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:
26
(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 our interest in production and reserves, our
"Trust gross reserves", which are our 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 we
have an interest; and
(c) in relation to properties, the total area of properties in
which we have an interest.
"NET" means:
(a) in relation to our interest in production and reserves, our
interest (operating and non-operating) share after deduction
of royalties obligations, plus our royalty interest in
production or reserves;
(b) in relation to wells, the number of wells obtained by
aggregating our working interest in each of our gross wells;
and
(c) in relation to our interest in a property, the total area in
which we have an interest multiplied by the working interest
owned by us.
RESERVE CATEGORIES
Reserves are estimated remaining quantities of oil and natural gas and related
substances anticipated to be recoverable from known accumulations, from a given
date forward, based on:
o analysis of drilling, geological, geophysical and engineering data;
o the use of established technology; and
o specified economic conditions.
Reserves are classified according to the degree of certainty associated with the
estimates.
(a) PROVED RESERVES are those reserves that can be estimated with
a high degree of certainty to be recoverable. It is likely
that the actual remaining quantities recovered will exceed the
estimated proved reserves.
(b) PROBABLE RESERVES are those additional reserves that are less
certain to be recovered than proved reserves. It is equally
likely that the actual remaining quantities recovered will be
greater or less than the sum of the estimated proved plus
probable reserves.
Other criteria that must also be met for the categorization of reserves are
provided in the COGE Handbook.
27
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.
MARKETING
Our crude oil and natural gas production is primarily sold through marketing
companies at current market prices. These contracts are generally for less than
a year and are cancellable on 30 days notice. Approximately 23% of our natural
gas production is sold to aggregators who accumulate production from various
producers and market the gas on behalf of the group. Such contracts are reserve
specific and continue for the life of production from the specified reserves.
CYCLICAL AND SEASONAL IMPACT OF INDUSTRY
Our operational results and financial condition will be dependent on the prices
received for oil and natural gas production. Oil and natural gas prices have
fluctuated widely during recent years and are determined by supply and demand
factors, including weather and general economic conditions, as well as
conditions in other oil and natural gas regions. Any decline in oil and natural
gas prices could have an adverse effect on our financial condition. We mitigate
such price risk through closely monitoring the various commodity markets and
establishing hedging programs, as deemed necessary, to provide stability to
Unitholders' cash distributions and lock-in high netbacks on production volumes.
See "Other Oil and Gas Information - Forward Contracts" for our current hedging
program.
28
RENEGOTIATION OR TERMINATION OF CONTRACTS
As at the date hereof, we do not anticipate that any aspect of our business will
be materially affected in the remainder of 2005 by the renegotiation or
termination of contracts or subcontracts.
ENVIRONMENTAL CONSIDERATIONS
We are pro-active in our approach to environment concerns. Procedures are in
place to ensure that the utmost care is taken in the day-to-day management of
our oil and gas properties. All government regulations and procedures are
followed in strict adherence to the law. We believe in well abandonment and site
restoration in a timely manner to ensure minimal damage to the environment and
lower overall costs to us.
COMPETITIVE CONDITIONS
We are a member of the petroleum industry, which is highly competitive at all
levels. We compete with other companies for all of our business inputs,
including exploitation and development prospects, access to commodity markets,
acquisition opportunities, available capital and staffing.
We strive to be competitive by maintaining a strong financial condition and by
utilizing current technologies to enhance exploitation, development and
operational activities.
HUMAN RESOURCES
As at December 31, 2004, we employ 77 full-time employees, all of which are
located in the head office and 15 consultants.
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 December 31, 2004, 49,674,783 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 two classes, as follows: (i) 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) "special voting
units", which shall be issued to a trustee and which are entitled to such number
of votes at meetings of 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 AOG's board of
directors. As at the date hereof there is one special voting unit outstanding.
The special voting unit gives 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 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 on liquidation,
is fully paid and non assessable and entitles the holder thereof to one vote at
all meetings of Unitholders for each Trust Unit held.
The Trust Units do not represent a traditional investment and should not be
viewed by investors as "shares" in either AOG or the Trust. Corporate law does
not govern the Trust and the rights of Unitholders. As holders of Trust Units in
the Trust, the 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 rights of Unitholders
are specifically set forth in the Trust Indenture. In addition, trusts are not
defined as recognized entities within the definitions of legislation such as the
Bankruptcy and Insolvency Act (Canada) and the Companies' Creditors Arrangement
Act (Canada). As a result, in the event of an insolvency or restructuring, a
Unitholder's position as such may be quite different than that of a shareholder
of a corporation.
29
The price per Trust Unit is a function of anticipated distributable income from
AOG and the combined ability of AOG's board of directors and the Manager 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, commodity prices and our ability to acquire
additional assets. Changes in market conditions may adversely affect the trading
price of the Trust Units.
A return on an investment in the Trust is not comparable to the return on an
investment in a fixed-income security. The recovery of an initial investment in
the Trust is at risk, and the anticipated return on such investment is based on
many performance assumptions. Although the Trust intends to make distributions
of its available cash to holders of Trust Units, these cash distributions may be
reduced or suspended. The actual amount distributed will depend on numerous
factors including: the financial performance of AOG, debt obligations, working
capital requirements and future capital requirements. In addition, the market
value of the Trust Units may decline if the Trust's cash distributions decline
in the future, and that market value decline may be material.
It is important for an investor to consider the particular risk factors that may
affect the industry in which it is investing, and therefore the stability of the
distributions that it receives. See "Risk Factors".
The after-tax return from an investment in Trust Units to Unitholders subject to
Canadian income tax can be made up of both a return on capital and a return of
capital. That composition may change over time, thus affecting an investor's
after-tax return. Returns on capital are generally taxed as ordinary income in
the hands of a Unitholder. Returns of capital are generally tax-deferred (and
reduce the Unitholder's cost base in the Trust Unit for tax purposes).
EXCHANGEABLE SHARES
As at December 31, 2004, AOG had 1,450,030 Exchangeable Shares outstanding. The
Exchangeable Shares were issued in connection with our acquisition of Defiant.
Each Exchangeable Share is exchangeable for Trust Units at any time (subject to
the provisions of the Voting and Exchange Trust Agreement), on the basis of the
applicable exchange ratio in effect at that time, in accordance with the share
provisions applicable to such shares and the terms and provisions of the Voting
and Exchange Trust Agreement. The exchange ratio was initially equal to one upon
issuance of the Exchangeable Shares and will increase on each date that a
distribution is paid by us on the Trust Units. The exchange ratio will decrease
on each record date for the payment of dividends on the Exchangeable Shares. The
holders of Exchangeable Shares are not entitled to any vote at meetings of
shareholders of AOG but are, through the Special Voting Unit of Advantage held
by the Trustee as trustee under the Voting and Exchange Trust Agreement,
entitled to vote (on the basis of the number of votes equal to the number of
Trust Units into which the Exchangeable Shares are then exchangeable) with the
holders of Trust Units as a class. In addition, holders are provided with all
information sent by us to Unitholders. Holders of Exchangeable Shares will be
entitled to receive, as and when declared by the board of directors of AOG in
its sole discretion from time to time, such cash dividends as may be declared
thereon by the board of directors. It is not anticipated that dividends will be
declared or paid on the Exchangeable Shares. The Exchangeable Shares will be
redeemable by AOG, in certain circumstances, and will be retractable by holders
of Exchangeable Shares, in certain circumstances. Exchangeable Shares not
previously redeemed or retracted will be redeemed by AOG or purchased by us on
January 15, 2008.
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 our 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 our assets. Pursuant to
the Trust Indenture, we 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 us must contain a provision to the effect that such obligation will not be
binding upon our Unitholders personally. Notwithstanding the terms of the Trust
Indenture, Unitholders may not be protected from our liabilities 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
30
possibly certain other statutory liabilities. The possibility of any personal
liability to Unitholders of this nature arising is considered unlikely in view
of the fact that our sole business activity 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.
Our business and that of our 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 our Unitholders for claims
against us, including obtaining appropriate insurance, where available, for the
operations of AOG and having written agreements, signed by or on our behalf,
include a provision that such obligations are not binding upon our 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 of AOG determines. The Trust
Indenture also provides that immediately after any PRO RATA distribution of
Trust Units to all 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.
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 Notes, royalty income from the Royalty,
dividends on or in respect of shares of AOG received by us and income from the
Permitted Investments; less: (i) our administrative expenses and other
obligations; and (ii) amounts which may be paid by us 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 us 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 we do 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.
We derive interest income from our holdings of the Notes. It is expected that
our 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 of AOG intends for the Trust to make monthly cash
distributions. Cash distributions will be made monthly to the 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 us of the certificate or certificates representing such Trust Units,
accompanied by a duly completed and properly executed notice requesting
redemption. Upon our receipt of the redemption request, 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.
31
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.
The aggregate Redemption Price payable by us 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 Unitholders to receive cash upon the redemption of their
Trust Units is subject to the limitations that: (i) the total amount payable by
us 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 Long Term 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 Long Term Notes
will be distributed and where the number of Long Term Notes to be received by a
Trust Unitholder includes a fraction, such number shall be rounded to the next
lowest whole number. We shall be entitled to all interest paid, or accrued and
unpaid, on the Long Term Notes on or before the date of the distribution IN
SPECIE. If we do not hold Long Term Notes having a sufficient principal amount
outstanding to effect such payment, we will be entitled to create and, subject
to any applicable regulatory approvals, issue in satisfaction of the Redemption
Price our own debt securities (the "REDEMPTION NOTES") having terms and
conditions substantially the same as the Long Term Notes, and with recourse of
the holder limited to our assets. Holders of such Long Term 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". Long Term 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. Long Term Notes or
Redemption Notes which may be distributed IN SPECIE to Unitholders in connection
with a redemption will not be listed on any stock exchange and no market is
expected to develop in such Long Term Notes or Redemption Notes.
MEETINGS OF UNITHOLDERS
The Trust Indenture provides that meetings of Unitholders must be called and
held for, among other matters, the election or removal of the Trustee, the
appointment or removal of our auditors, 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
our assets in their entirety or substantially in their entirety (other than as
part of an internal
32
reorganization), the termination of the Trust and the direction of the Trustee
as to the selection of the directors of AOG. Meetings of Unitholders will be
called and held annually for, among other things, the election of the Trustee,
the appointment of our auditors, and the direction of the Trustee as to the
selection of the directors of AOG. A resolution appointing or removing a
Trustee, our auditors, 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
Unitholders. The balance of the foregoing matters must be passed by at least
66?% of the votes cast at a meeting of Unitholders called for such purpose.
A meeting of 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.
Unitholders may attend and vote at all meetings of 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 Unitholders.
The next annual and special meeting of Unitholders is scheduled for April 27,
2005.
INFORMATION AND REPORTS
We will furnish to 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 Unitholders' tax returns under the Tax Act and equivalent provincial
legislation.
Prior to each meeting of Unitholders, the Trustee will provide the 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 of AOG will ensure that AOG provides us with proper
disclosure as to its business and financial operations and sufficient
information and materials on a timely basis to allow us to meet our public
reporting requirements. With respect to material changes, the board of directors
of AOG will ensure that AOG provides timely disclosure to us 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
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 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 Unitholders. The Trustee is reappointed or changed every year as may be
determined by a majority of the votes cast at a meeting of our Unitholders. The
Trustee may resign upon 60 days' notice to us. The Trustee may also be removed
by special resolution of our Unitholders. Such resignation or removal becomes
effective upon the acceptance or appointment of a successor trustee.
33
DELEGATION OF AUTHORITY, ADMINISTRATION AND TRUST GOVERNANCE
The board of directors of AOG has generally been delegated our significant
management decisions 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 of AOG responsibility for any and all matters relating to, among
other things: (a) any offering of our securities, 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) our
acquisition of Permitted Investments and Subsequent Investments and the
negotiation of agreements respecting Subsequent Investments; (g) maintaining our
books and records and providing timely reports to Unitholders; (h) our financial
statements and the financial statements of AOG; (i) the continued listing of our
Trust Units on any exchange and to maintain our 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. Unitholders are entitled to elect a majority
of the board of directors of AOG pursuant to the terms of the Shareholder
Agreement. Subject to the ultimate authority of the board of directors of AOG,
AOG and the Trust will be managed by the Manager. For more information as to the
board of directors of AOG, see "Additional Information Respecting Advantage Oil
& Gas Ltd. - Management of AOG".
DECISION-MAKING
Although the Manager will provide certain advisory and management services to us
pursuant to the Management Agreement, the board of directors of AOG will
supervise the management of our business and affairs, including our business and
affairs 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 of AOG. In addition, the Trustee has delegated certain matters to
the board of directors of AOG, 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 we are a
party will require the approval of the board of directors of AOG on our behalf.
The board of directors of AOG 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
34
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 our Unitholders called for such purpose.
The Trustee may, without the approval of the 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 we 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 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 Unitholders;
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.
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 our
assets in their entirety or substantially in their entirety, except as part of
an internal reorganization of the our assets as approved by the board of
directors of AOG, requires approval by at least 66?% of the votes cast at a
meeting of the 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 us which
represents more than 51% of the Trust Fund, except as part of a reorganization
of AOG and any one or more of our directly or indirectly owned subsidiaries
without the approval of at least 66?% of the votes cast at a meeting of the
Unitholders called for such purpose.
ADDITIONAL INFORMATION RESPECTING ADVANTAGE OIL & GAS LTD.
MANAGEMENT OF AOG
Pursuant to the Shareholder Agreement, the board of directors of AOG ("BOARD OF
DIRECTORS") is comprised of not more than nine nor less than five members.
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.
35
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.
Number of Trust
Units Beneficially
Position Held and Owned or
Name and Period Served as Controlled as at
Municipality of Residence a Director(4)(5) Principal Occupations During Past Five Years February 15, 2005
- ------------------------- ---------------- ---------------------------------------------------------- -----------------
Gary F. Bourgeois Vice President, Vice President, Corporate Development of AOG since 373,774 (0.66%)
Toronto, Ontario Corporate May 24, 2001. Vice President of the Manager since March
Development and 2001. Prior thereto, Managing Director of the EnerPlus
Director since Group of Companies, which companies specialize in
May 24, 2001 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 President, Chief President and Chief Executive Officer of AOG since 582,375 (1.02%)
Calgary, Alberta Executive Officer May 24, 2001. President of the Manager since March
and Director 2001. Prior thereto, Senior Vice President (1997-2001)
since May 24, 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(2)(3) Director since Chairman of Navigo Energy Inc. since December 2003. As 38,811 (0.07%)
Calgary, Alberta September 25, of December 29, 2003, Navigo Energy Inc. became a
1998(6) 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 Since May 24, 2001, a self-employed businessman. Prior 316,101 (0.56%)
Victoria, British Columbia December 31, thereto, Vice President, Business Development of Search
1996(6) Energy Corp.
Carol Pennycook(2) Director since Partner at the Toronto office of Davies Ward Phillips & 3,000 (0.01%)
Toronto, Ontario May 26, 2004 Vineberg, LLP, a national law firm.
36
Number of Trust
Units Beneficially
Position Held and Owned or
Name and Period Served as Controlled as at
Municipality of Residence a Director(4)(5) Principal Occupations During Past Five Years February 15, 2005
- ------------------------- ---------------- ---------------------------------------------------------- -----------------
Steven Sharpe(1)(2) Director since Managing Partner of Blair Franklin Capital Partners Inc., 8,225 (0.01%)
Toronto, Ontario May 24, 2001 and an investment banking firm since May, 2003. Prior
Non-Executive thereto, Mr. Sharpe was the Managing Director of The EBS
Chairman since Corporation, a management and strategic consulting firm,
May 26, 2004 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)(7) Director since President of Tourigny Management Ltd., a private oil and Nil
Calgary, Alberta December 31, gas consulting company.
1996(6)
Lamont Tolley(1)(3) Director since President and Chief Executive Officer of Rally Energy Nil
Calgary, Alberta May 24, 2001 Corp. since July 27, 2004. Prior thereto, independent
businessman who has been active in the oil and gas
industry for 20 years. He is also 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 Senior Vice President of AOG since June 2001. Vice 373,085 (0.66%)
Calgary, Alberta President President 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 Chief Financial Officer of AOG since January 2003. Prior 69,495 (0.12%)
Calgary, Alberta Officer and thereto, Controller of AOG since December 1999. Prior
Controller thereto, Manager of Financial Reporting with Numac Energy
Inc.
Richard Mazurkewich Vice President, Vice President, Operations of AOG since August 2001. 182,814 (0.32%)
Calgary, Alberta Operations Prior thereto, Manager, Production and Facilities of AOG
since March 1998. Prior thereto, Production Engineer
with Canadian Natural Resources Limited.
Weldon Kary Vice President, Vice President, Exploitation since February 14, 2005. 78,514 (0.14%)
Calgary, Alberta Exploitation Prior thereto, with AOG since May 23, 2001, most
recently as Manager, Geology and Geophysics. Prior
thereto, Exploration Manager at Palliser Energy Corp.
when Palliser was purchased by Search Energy Corp, the
predecessor entity of AOG.
37
Number of Trust
Units Beneficially
Position Held and Owned or
Name and Period Served as Controlled as at
Municipality of Residence a Director(4)(5) Principal Occupations During Past Five Years February 15, 2005
- ------------------------- ---------------- ---------------------------------------------------------- -----------------
Anthony Coombs Controller Controller since September 1, 2004. Prior thereto with 7,258 (0.01%)
Calgary, Alberta AOG since May 23, 2001, most recently as Chief
Accountant. Prior thereto, Chief Accountant for Search
Energy Corp., the predecessor entity of Advantage.
Jay P. Reid Corporate Partner, Burnet, Duckworth & Palmer LLP, a Calgary-based 6,000 (0.01%)
Calgary, Alberta Secretary law firm.
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) 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.
(6) 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 these directors were appointed directors of
post-Reorganization Search on May 24, 2001.
(7) 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.
As at February 15, 2005, the directors and executive officers of AOG, as a
group, beneficially owned, directly or indirectly, or exercised control or
direction over, 2,039,452 Trust Units, or approximately 3.6% of the issued and
outstanding Trust Units.
CEASE TRADE ORDERS, BANKRUPTCIES, PENALTIES OR SANCTIONS
Except as disclosed above, no director or officer of Advantage, or a shareholder
holding a sufficient number of securities of Advantage to affect materially the
control of Advantage is, or within the last ten years has been, a director or
officer of any reporting issuer that, while such person was acting in that
capacity, was the subject of a cease trade or similar order or an order that
denied us access to any statutory exemption for a period of more than 30
consecutive days or, within a year of such person ceasing to act in that
capacity or within the 10 years prior to the date hereof, become bankrupt, made
a proposal under any legislation relating to bankruptcy or insolvency or was
subject to or instituted any proceedings, arrangement or compromise with
creditors or had a receiver, receiver manager or trustee appointed to hold the
assets of that person.
No director or officer of Advantage, or a shareholder holding a sufficient
number of securities of Advantage to affect materially the control of Advantage,
has been subject to any penalties or sanctions under securities legislation or
by a
38
securities regulatory authority or has entered into a settlement agreement
with a securities regulatory authority or any other penalties or sanctions
imposed by a court or regulatory body that would likely be considered important
to a reasonable investor in making an investment decision.
DISTRIBUTION POLICY
It is anticipated that income we receive 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 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, Preferred Shares and Exchangeable Shares. We are the sole holder of the
issued and outstanding Common Shares. There are no Non-Voting Shares or
Preferred Shares issued and outstanding. We are 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, Exchangeable 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.
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.
EXCHANGEABLE SHARES
As at December 31, 2004, AOG had 1,450,030 Exchangeable Shares outstanding. The
Exchangeable Shares were issued in connection with our acquisition of Defiant.
Each Exchangeable Share is exchangeable for Trust Units at any time (subject to
the provisions of the Voting and Exchange Trust Agreement), on the basis of the
applicable exchange ratio in effect at that time, in accordance with the share
provisions applicable to such shares and the terms and provisions of the Voting
and Exchange Trust Agreement. The exchange ratio was initially equal to one upon
issuance of the Exchangeable
39
Shares and will increase on each date that a distribution is paid by us on the
Trust Units. The exchange ratio will decrease on each record date for the
payment of dividends on the Exchangeable Shares. The holders of Exchangeable
Shares are not entitled to any vote at meetings of shareholders of AOG but are,
through the Special Voting Unit of Advantage held by the Trustee as trustee
under the Voting and Exchange Trust Agreement, entitled to vote (on the basis of
the number of votes equal to the number of Trust Units into which the
Exchangeable Shares are then exchangeable) with the holders of Trust Units as a
class. In addition, holders are provided with all information sent by us to
Unitholders. Holders of Exchangeable Shares will be entitled to receive, as and
when declared by the board of directors of AOG in its sole discretion from time
to time, such cash dividends as may be declared thereon by the board of
directors. It is not anticipated that dividends will be declared or paid on the
Exchangeable Shares. The Exchangeable Shares will be redeemable by AOG, in
certain circumstances, and will be retractable by holders of Exchangeable
Shares, in certain circumstances. Exchangeable Shares not previously redeemed or
retracted will be redeemed by AOG or purchased by us on January 15, 2008.
NOTES
The following is a summary of the material attributes and characteristics of the
Notes. This summary does not purport to be complete and is qualified in its
entirety by reference to the provisions of the Note Indentures, pursuant to
which the Notes are issued.
PAYMENT UPON MATURITY
On maturity and subject to any applicable subordination restrictions, AOG will
repay the indebtedness represented by the Notes by paying to the Note Trustee,
in lawful money of Canada, an amount equal to the principal amount of the
outstanding Notes, together with accrued and unpaid interest thereon.
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 Notes will be subordinated in right of
payment, as set forth in the Note Indentures, 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 Note Indentures; 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 Note Indentures; 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 Notes. The Note Indentures
provide 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
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.
In the event of any creditor proceedings, the indebtedness represented by the
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 Notes in respect of any restructuring or
arrangement proposal regarding AOG.
DEFAULT
The Note Indentures provides that any of the following shall constitute an
"Event of Default": (i) default in payment of the principal of the Notes when
the same becomes due; (ii) the failure to pay the interest obligations of the
Notes for a period of 12 months; (iii) default on any indebtedness exceeding
$10,000,000; (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
40
condition of the 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 the Note Indentures, 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 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 Notes (or other
securities of AOG) agrees to be bound by the provisions of the subordination
agreements.
LONG TERM NOTES
The aggregate principal amount of Long Term Notes as at December 31, 2004 was
$475,312,732. The Long Term Notes mature on December 31, 2031. The Long Term
Notes consist of a series of notes, which as at the date hereof, includes Long
Term Notes bearing interest at a rate of 14% and 12.5% 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 Long Term Notes are payable in lawful money of
Canada. The Long Term Notes are issuable only as fully-registered notes in
minimum denominations of $100.00 and integral multiples of $1.00.
REDEMPTION OF LONG TERM NOTES
The Long Term 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 Long Term Note Indenture, where the Board of Directors believe the
indebtedness represented by the Long Term 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.
MEDIUM TERM NOTES
The original aggregate principal amount of Medium Term Notes was $259,200,000
("ORIGINAL PRINCIPAL AMOUNT") and the aggregate principal amount of the Medium
Term Notes as at December 31, 2004 was $207,624,757. The Medium Term Notes
consist of a series of notes, which as of December 31, 2004, includes Medium
Term Notes bearing interest at rates between 7.75% and 10.375% per annum,
payable twice annually, and maturing between December 31, 2012 and December 21,
2015. The principal and interest on the Medium Term Notes are payable in lawful
money of Canada. The Medium Term Notes are issuable only as fully-registered
notes in minimum denominations of $100.00 and integral multiples of $1.00.
PRINCIPAL REPAYMENTS AND REDEMPTION OF MEDIUM TERM NOTES
From time to time and in any event not less frequently than each anniversary of
December 31, 2004, AOG shall make principal repayments on the Notes in an
aggregate amount equal to not less than 5% of the Original Principal Amount
(and, if applicable, the aggregate principal amount of any additional Notes
issued under the Medium Term Note Indenture in excess of the Original Principal
Amount (the "SUPPLEMENTAL PRINCIPAL AMOUNT")), provided, however that during the
period commencing on September 30, 2004 and ending on December 31 of the year
ended five years before the Maturity Date, AOG shall make, in aggregate,
principal payments on the Notes in an amount equal to not less than 50% of the
Original Principal Amount. In the event that, at any time during the term of
this Indenture, a Supplemental Principal Amount is outstanding, during the
period commencing with the issue date of the Notes relating to the Supplemental
Principal Amount and ending five years from such issue date, AOG shall make
principal payments on the Notes relating to the Supplemental Principal Amount in
an aggregate amount equal to not less than 50% of the Supplemental Principal
Amount. In the event that AOG makes principal repayments on the Notes pursuant
to this section of the Medium Note Indenture and there is more than one holder
thereof, such principal prepayments shall be made as near as may be pro rata as
between the holders and without discrimination or preference, based upon the
aggregate principal amount of Notes held by them (rounded, if necessary, to the
nearest One Dollar ($1.00)).
41
THE ROYALTY AGREEMENT
Pursuant to the Royalty Agreement, AOG has granted to us 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 we are not entitled to take our share of production in kind or to separately
sell or market our 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 us and our 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 $2 million, AOG's board of directors is required to approve such
disposition.
SHAREHOLDER AGREEMENT
Pursuant to the Shareholder Agreement, prior to us voting our shares in AOG,
each Unitholder shall be entitled to vote in respect of the matter on the basis
of one vote per Trust Unit held and we shall be required to vote our shares in
AOG in accordance with the result of the vote of 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 our auditors. In addition, Unitholders will be entitled to direct us
as to how to vote our 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. We will not be entitled, without the
direction of Unitholders, to exercise our 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
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 our
manager and as manager of AOG. The board of directors of AOG 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 us and of AOG and to assist in making executive
decisions which conform to the general policies and general principles
previously established by the board of directors of AOG. The Manager will
provide executive officers to AOG, subject to the approval of the board of
directors of AOG.
42
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 the
Toronto, Ontario 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 since
Calgary, Alberta and Secretary 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.
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 us and AOG,
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;
(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;
43
(f) at least annually, and at other times as requested by the
board of directors of AOG, 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 of AOG;
(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 us:
(a) ensure we comply with our legal obligations, including our
continuous disclosure obligations under all applicable
securities legislation;
(b) provide investor relations services;
(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;
44
(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 of AOG will supervise the management of
the business and affairs of AOG, including our business and affairs delegated to
AOG, and, in particular:
1. significant operational decisions in respect of AOG as identified by
the Manager, acting reasonably; and
2. 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 our 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 our behalf, 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 of AOG.
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 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
45
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 AOG 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 us
and AOG, 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 45th 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.
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 of AOG) 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. Effective October 4, 2004, such fees are
allocated by the Manager, subject to the discretion of the Manager, on the
following basis:
Manager
Operating Fee 66 2/3%
Termination Fee 66 2/3%
Performance Fee 60%
Employees of AOG
Operating Fee 33 1/3%
Termination Fee 33 1/3%
Performance Fee 40%
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 of AOG.
The initial term of the Management Agreement was for 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 of AOG 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 ("TERMINATION FEES") equal to the Management Fees paid for the
immediately-prior 2 1/2 years shall be payable.
46
In addition, the Manager is entitled to reimbursement, by us 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 AOG 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 us 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 us and
AOG 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 they will not do any of the following activities except with
prior disclosure to the board of directors of AOG 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 of AOG is first
obtained:
1. they will not manage another oil and gas income fund or royalty trust;
2. they will not, without prior approval of us and AOG, acting reasonably,
as determined by the board of directors of AOG, 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 us and AOG, acting reasonably,
as determined by the board of directors of AOG, 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 us or AOG.
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.
CASH DISTRIBUTIONS
The following is a summary of the distributions made by us from our inception in
May of 2001 to December 31, 2004.
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
47
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
For the 2004 Period Ended Distributions per Unit Payment Date
- ------------------------- ---------------------- ------------------
January 31 $0.23 February 17, 2004
February 29 0.23 March 15, 2004
March 31 0.23 April 15, 2004
April 30 0.23 May 17, 2004
May 31 0.23 June 15, 2004
June 30 0.23 July 15, 2004
July 31 0.23 August 16, 2004
August 31 0.23 September 15, 2004
September 30 0.23 October 15, 2004
October 31 0.25 November 15, 2004
November 30 0.25 December 15, 2004
December 31 0.25 January 17, 2005
----
TOTAL $2.82
Note:
(1) We announced on January 12, 2005 that a distribution of $0.28 per Trust
Unit will be paid on February 15, 2005 to Unitholders of record on the
close of business on January 31, 2005.
48
MARKET FOR SECURITIES
Our 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.
Period High Low Volume
------------------- ------ ----- ---------
2003
----
First Quarter 15.59 11.80 7,622,480
Second Quarter 16.95 14.15 7,995,072
Third Quarter 17.15 14.92 8,001,055
Fourth Quarter 17.95 15.65 9,684,205
2004
----
January 18.42 16.80 2,919,734
February 17.90 16.01 3,020,709
March 19.00 17.69 1,726,037
April 19.84 18.80 4,120,250
May 20.08 19.05 3,367,746
June 19.37 17.80 3,169,079
July 19.65 18.63 2,095,637
August 19.70 18.51 3,648,664
September 21.50 19.47 4,872,670
October 22.35 20.46 5,644,564
November 22.05 20.36 7,372,495
December 22.54 20.61 4,164,232
Our 10% Convertible Debentures are listed for trading on the TSX under the
symbol "AVN.DB". The following table sets forth the high and low closing trading
prices and the aggregate trading volume of the 10% Convertible Debentures as
reported by the TSX for the periods indicated.
Period High Low Volume
------------------- ------ ----- ---------
2003
----
First Quarter 116.00 102.30 142,516
Second Quarter 126.25 108.00 109,300
Third Quarter 128.22 115.50 44,200
Fourth Quarter 133.01 112.00 35,110
2004
----
January 136.75 129.50 13,210
February 136.00 121.14 3,380
March 141.00 133.65 1,960
April 147.52 141.53 4,220
May 148.89 141.76 3,100
June 145.00 135.13 3,080
July 147.00 143.54 4,545
August 145.59 139.30 1,971
September 160.00 145.00 6,756
October 166.09 155.02 6,950
November 164.74 156.91 3,565
December 162.39 155.55 290
49
Our 9% Convertible Debentures are listed for trading on the TSX under the symbol
"AVN.DB.A". The following table sets forth the high and low closing trading
prices and the aggregate trading volume of the 9% Convertible Debentures as
reported by the TSX for the periods indicated.
Period High Low Volume
------------------- ------ ----- ---------
2003
----
Third Quarter 107.00 102.25 95,305
Fourth Quarter 108.00 101.00 13,160
2004
----
January 111.00 108.00 9,510
February 110.00 108.50 2,430
March 111.50 109.00 9,720
April 115.50 111.00 56,010
May 118.00 112.07 20,590
June 113.00 101.00 5,870
July 115.00 110.24 5,655
August 114.75 109.00 7,350
September 126.16 115.00 24,200
October 130.35 121.89 8,540
November 128.25 120.00 5,750
December 132.00 113.03 3,870
Our 8.25% Convertible Debentures are listed for trading on the TSX under the
symbol "AVN.DB.B". The following table sets forth the high and low closing
trading prices and the aggregate trading volume of the 8.25% Convertible
Debentures as reported by the TSX for the periods indicated.
Period High Low Volume
------------------- ------ ----- ---------
2003
----
Fourth Quarter 108.50 101.50 219,180
2004
----
January 111.01 107.01 59,740
February 109.25 106.00 21,030
March 112.09 108.25 16,180
April 120.00 113.00 124,940
May 121.25 115.11 53,510
June 117.00 110.12 7,850
July 118.00 114.51 39,390
August 118.70 111.50 28,280
September 130.00 118.35 60,930
October 134.61 125.00 22,680
November 133.00 126.10 34,040
December 135.20 127.00 20,240
50
Our 7.5% Convertible Debentures are listed for trading on the TSX under the
symbol "AVN.DB.C". The following table sets forth the high and low closing
trading prices and the aggregate trading volume of the 7.5% Convertible
Debentures as reported by the TSX for the periods indicated.
Period High Low Volume
------------------- ------ ----- ---------
2004
----
September 105.50 101.75 151,840
October 110.00 102.85 64,720
November 109.00 103.55 33,070
December 111.00 105.50 35,990
Our 7.75% Convertible Debentures are listed for trading on the TSX under the
symbol "AVN.DB.D". The following table sets forth the high and low closing
trading prices and the aggregate trading volume of the 7.75% Convertible
Debentures as reported by the TSX for the periods indicated.
Period High Low Volume
------------------- ------ ----- ---------
2004
----
September 105.00 101.05 172,990
October 107.00 103.00 35,970
November 107.99 104.25 23,670
December 109.50 104.60 15,550
ESCROWED SECURITIES
As at the date hereof, none of our securities are subject to escrow.
PAST PROMOTER
Advantage Investment Management Ltd. could be considered the promoter of the
Trust for the years 2001 and 2002. The Manager holds Nil Trust Units or Nil% of
the issued and outstanding Trust Units as at February 15, 2005. 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 our current asset value to which we are a party or in respect of which any of
our 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 2004 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 2004,
and (ii) as disclosed herein.
MATERIAL CONTRACTS
Except for contracts entered into by us in the ordinary course of business or
otherwise disclosed herein, the only material contracts we entered into 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
51
Indenture and Management Agreement, in addition to Documents Affecting the
Rights of Securityholders, are available on our SEDAR profile at WWW.SEDAR.COM.
INTEREST OF EXPERTS
There is no person or company whose profession or business gives authority to a
statement made by such person or company and who is named as having prepared or
certified a statement, report or valuation described or included in a filing, or
referred to in a filing, made under National Instrument 51-102 by us during, or
related to, our most recently completed financial year other than Sproule
Associates Limited, our independent engineering evaluator and KPMG LLP, our
auditors. As at the date hereof, none of the principals of Sproule Associates
Limited had any registered or beneficial interests, direct or indirect, in any
securities or other property of the Corporation or of our associates or
affiliates either at the time they prepared the statement, report or valuation
prepared by it, at any time thereafter or to be received by them. As at March
15, 2005 KPMG LLP and its partners did not hold any registered or beneficial
ownership interest, directly or indirectly, in the securities of the Corporation
or its associates or 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 associate or affiliate of the Trust except for Mr. Jay
Reid, the Corporate Secretary of AOG, who is a partner of Burnet, Duckworth &
Palmer LLP, which law firm provides the Trust, AOG and the Manager with legal
services.
AUDITORS, TRANSFER AGENT AND REGISTRAR
Our auditors 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
and Debentures.
AUDIT COMMITTEE INFORMATION
COMPOSITION OF THE AUDIT COMMITTEE
The audit committee of the Company (the "AUDIT COMMITTEE") is comprised of
Messrs. Steven Sharpe, Rodger A. Tourigny and Lamont Tolley. The following chart
sets out the assessment of each Audit Committee member's independence, financial
literacy and relevant educational background and experience supporting such
financial literacy.
52
NAME AND MUNICIPALITY OF FINANCIALLY
RESIDENT INDEPENDENT LITERATE RELEVANT EDUCATION AND EXPERIENCE
- ----------------------------- ----------- ----------- ---------------------------------------------------------
Steven Sharpe Yes Yes Mr. Sharpe has an LLB and is currently Managing Partner
Toronto, Ontario of Blair Franklin Capital Partners, an investment bank,
with Limited Market Dealer and Portfolio Manager
registrations. Mr. Sharpe has served as Chairman of the
Audit Committee of Altamira Investment Services Ltd. and
as a member of the Audit Committee of Foamex
International Ltd. and of a number of private
not-for-profit companies. Mr. Sharpe practiced law in the
area of work-outs and financial restructurings, and
advised lenders, bondholders and boards of directors on
financial matters.
Rodger A. Tourigny Yes Yes Mr. Tourigny has a Bachelor of Commerce and is a
Calgary, Alberta Chartered Accountant. He is a director and President of
Tourigny Management Ltd., a private company through
which he provides consulting services. Mr. Tourigny is
also a Corporate Director and Chairman of the Audit
Committee of NAV Energy Trust and is a director and
member of the Audit Committee of Burmis Energy Inc. and
of Caribou Energy Inc., a private oil and gas company.
Lamont Tolley Yes Yes Mr. Tolley holds an MBA and is currently President and
Calgary, Alberta CEO of Rally Energy Corp. and is serving as a director
and member of the Audit Committee of Delphi Energy Corp.
He served as an equity analyst and equity portfolio
manager for the Sun Life Investment Group, managed two
energy royalty trusts, Starcor Energy Royalty Fund and
Orion Energy Trust, and has served as an Audit Committee
member of several public issuers and private companies.
PRE-APPROVAL OF POLICIES AND PROCEDURES
We have adopted polices and procedures with respect to the pre-approval of audit
and permitted non-audit services to be provided by KPMG LLP as set forth in item
15 of the Audit Committee charter, which is reproduced below under the heading
"Audit Committee Charter". The Audit Committee has approved the provision of a
specified list of audit and permitted non-audit services that the audit
committee believes to be typical, reoccurring or otherwise likely to be provided
by KPMG LLP during the current fiscal year. The list of services is sufficiently
detailed as to the particular services to be provided to ensure that the audit
committee knows precisely what services it is being asked to pre-approve and it
is not necessary for any member of management to make a judgment as to whether a
proposed service fits within pre-approved services.
AUDIT COMMITTEE CHARTER
The following is a summary of our Audit Committee charter which was originally
approved by the board of directors of AOG on April 30, 2002 and amended in April
2003 and April 2004:
53
PURPOSE
The primary function of the Audit Committee is to assist the Board of Directors
(the "BOARD OF DIRECTORS" or "BOARD") of Advantage Oil & Gas Ltd. in fulfilling
its responsibilities by reviewing: the financial reports and other financial
information provided by Advantage Energy Income Fund to any governmental body or
the public; the Trust's systems of internal controls regarding finance,
accounting, legal compliance and ethics that management and the Board have
established; and the Trust's auditing, accounting and financial reporting
processes generally. Consistent with this function, the Audit Committee should
endeavor to encourage continuous improvement of, and should endeavor to foster
adherence to, the Trust's policies, procedures and practices at all levels. The
Audit Committee's primary objectives are to:
1. To assist directors meet their responsibilities (especially for
accountability) in respect of the preparation and disclosure of the
financial statements of the Trust and related matters;
2. To provide better communication between directors and external
auditors;
3. To enhance the external auditor's independence;
4. To increase the credibility and objectivity of financial reports; and
5. To strengthen the role of the outside directors by facilitating
discussions between directors on the Audit Committee, management and
external auditors.
COMPOSITION
The Audit Committee shall be comprised of three or more directors as determined
by the Board of Directors, none of whom are members of management of AOG, the
Trust or Advantage Investment Management Ltd. and all of whom are "unrelated
directors" (as such term is used in the Report of the Toronto Stock Exchange on
Corporate Governance in Canada) and "independent" (as such term is used in
Multilateral Instrument 52-110 -- Audit Committees ("MI 52-110"). All of the
members of the Audit Committee shall be "financially literate". The Board of
Directors has adopted the definition for "FINANCIAL LITERACY" used in MI 52-110
which means "the ability to read and understand a set of financial statements
that present a breadth and level of complexity of accounting issues that are
generally comparable to the breadth and complexity of the issues that can
reasonably be expected to be raised by the issuer's financial statements". Audit
Committee members may enhance their familiarity with finance and accounting by
participating in educational programs conducted by the Trust or an outside
consultant.
The members of the Audit Committee shall be elected by the Board of Directors at
the annual organizational meeting of the Board of Directors and remain as
members of the Audit Committee until their successors shall be duly elected and
qualified. Unless a Chair is elected by the full Board of Directors, the members
of the Audit Committee may designate a Chair by majority vote of the full Audit
Committee membership.
MEETINGS
The Audit Committee shall meet at least four times annually, or more frequently
as circumstances dictate. As part of its job to foster open communication, the
Audit Committee should meet at least annually with management and the
independent auditors in separate executive sessions to discuss any matters that
the Audit Committee or each of these groups believe should be discussed
privately. In addition, the Audit Committee or at least its Chair should meet
with the independent auditors and management quarterly to review the Trust's
financials consistent with item 4 below.
A quorum for meetings of the Audit Committee shall be a majority of its members,
and the rules for calling, holding, conducting and adjourning meetings of the
Audit Committee shall be the same as those governing the Board.
RESPONSIBILITIES AND DUTIES
To fulfill its responsibilities and duties, the Audit Committee shall endeavor
to:
54
DOCUMENTS/REPORTS REVIEW
1. Review and update this Charter periodically, at least annually, as
conditions dictate.
2. Review the organization's annual and interim financial statements,
MD&A, earnings press releases and any reports or other financial
information submitted to any governmental body or the public, including
any certification, report, opinion or review rendered by the
independent auditors.
3. Review the reports to management prepared by the independent auditors
and management's responses.
4. Review with financial management and the independent auditors the
quarterly financial statements prior to their filing or prior to the
release of earnings. The Chair of the Audit Committee may represent the
entire Audit Committee for purposes of this review.
5. Review of significant findings during the year, including the status of
previous significant audit recommendations.
6. Periodically assess the adequacy of procedures for the review of
corporate disclosure that is derived or extracted from the financial
statements.
INDEPENDENT AUDITORS
7. Recommend to the Board the external auditors to be nominated for
appointment by the unitholders.
8. Recommend to the Board the compensation of the external auditors
9. On an annual basis, the Audit Committee should review and discuss with
the auditors all significant relationships the auditors have with the
Trust to determine the auditors' independence.
10. Review any material disagreements between management and the
independent auditors and review, consider and make a recommendation to
the Board regarding any proposed discharge of the auditors when
circumstances warrant.
11. When there is to be a change in auditors, review the issues related to
the change and the information to be included in the required notice to
securities regulators of such change
12. Periodically consult with the independent auditors, without the
presence of management, about internal controls and the fullness and
accuracy of the organization's financial statements.
13. Review the audit scope and plan of the independent auditor.
14. Oversee the work of the external auditors engaged for the purpose of
preparing or issuing an auditor's report or performing other audit,
review or attest services for the Trust.
15. Pre-approve the completion of any non-audit services by the external
auditors and determine which non-audit services the external auditor is
prohibited from providing. The Audit Committee may delegate to one or
more members of the Audit Committee authority to pre-approve non-audit
services in satisfaction of this requirement and if such delegation
occurs, the pre-approval of non-audit services by the Audit Committee
member to whom authority has been delegated must be presented to the
Audit Committee at its first scheduled meeting following such
pre-approval. The Audit Committee shall be entitled to adopt specific
policies and procedures for the engagement of non-audit services if:
(a) the pre-approval policies and procedures are detailed as to
the particular service;
(b) the Audit Committee is informed of each non-audit service; and
55
(c) the procedures do not include delegation of the Audit
Committee's responsibilities to management.
The Audit Committee will satisfy the pre-approval requirement set forth
in this paragraph 15 if::
(a) the aggregate amount of all non-audit services that were not
pre-approved is reasonably expected to constitute no more than
5% of the total amount of fees paid by the Trust and its
subsidiary entities to the auditors during the fiscal year in
which the services are provided;
(b) the Trust or the subsidiary entity, as the case may be, did
not recognize the services as non-audit services at the time
of the engagement; and
16. the services are promptly brought to the attention of the Audit
Committee and approved, prior to completion of the audit, by the Audit
Committee or by one or more of its members to whom authority to grant
such approvals has been delegated by the Audit Committee.
FINANCIAL REPORTING PROCESSES
17. In consultation with the independent auditors, annually review the
integrity of the organization's financial reporting processes, both
internal and external.
18. In consultation with the independent auditors, consider annually the
quality and appropriateness of the Corporation's accounting principles
as applied in its financial reporting.
19. Consider and approve, if appropriate, major changes to the Trust's
auditing and accounting principles and practices as suggested by the
independent auditors or management.
20. Review risk management policies and procedures of the Trust and AOG
(i.e., litigation and insurance).
PROCESS IMPROVEMENT
21. Request reporting to the Audit Committee by each of management and the
independent auditors of any significant judgments made in the
management's preparation of the financial statements and the view of
each group as to appropriateness of such judgments.
22. Following completion of the annual audit, review separately with each
of management and the independent auditors any significant difficulties
encountered during the course of the audit, including any restrictions
on the scope of work or access to required information.
23. Review any significant disagreements among management and the
independent auditors in connection with the preparation of the
financial statements.
24. Review with the independent auditors and management the extent to which
changes or improvements in financial or accounting practices, as
approved by the Audit Committee, have been implemented. (This review
should be conducted at an appropriate time subsequent to implementation
of changes or improvements, as decided by the Audit Committee.)
25. Conduct and authorize investigations into any matters brought to the
Audit Committee's attention and within the Audit Committee's scope of
responsibilities. The Audit Committee shall be empowered to retain and
to approve compensation for any independent counsel and other
professionals to assist in the conduct of any investigation.
26. Review the systems that identify and manage principal business risks.
27. Establish a procedure for:
o the receipt, retention and treatment of complaints received by the
Trust and AOG regarding accounting, internal accounting controls
or auditing matters; and
56
o the confidential, anonymous submission by employees of the Trust
and AOG of concerns regarding questionable accounting or auditing
matters.
ETHICAL AND LEGAL COMPLIANCE
28. Establish, review and update periodically a Code of Ethical Conduct and
ensure that management has established a system to enforce this code.
29. Review management's monitoring of the Trust's compliance with the
organization's Ethical Code.
30. In consultation with the auditors, consider the review system
established by management regarding the Corporation's financial
statements, reports and other financial information disseminated to
governmental organizations and the public in the context of the
applicable legal requirements.
31. On at least an annual basis, review with the Trust's auditors or
counsel, as appropriate, any legal matters that could have a
significant impact on the organization's financial statements, the
Trust's compliance with applicable laws and regulations and inquiries
received from regulators or government agencies.
32. Review with the organization's counsel legal compliance matters
including the trading policies of securities.
33. Perform any other activities consistent with this Charter, the Trust's
and AOG's by-laws and governing law, as the Audit Committee or the
Board of Directors deems necessary or appropriate.
AUDIT SERVICE FEES
AUDITOR SERVICES FEES
The following table discloses fees billed to us by our auditors, KPMG LLP.
TYPE OF SERVICE PROVIDED 2004
- ------------------------------------------------------------------ ---------
Audit Fees (these services included prospectus
work and audit or review of financials forming part of $ 244,500
such prospectus)
Audit-Related Fees (these services included French translation in
connection with 2004 prospectus $ 51,000
offering)
Tax Fees (these services included review/completion of tax returns
and general tax consultations) $ 26,497
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 renewal
annual information form.
DEPENDENCE ON AOG
We are an open-ended, limited purpose trust which will be entirely dependent
upon the operations and assets of AOG through our ownership of the Common
Shares, the Notes and the Royalty. Accordingly, the cash distributions to our
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 us may
be adversely affected.
57
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 we have 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 us to improve our 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
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 our management are currently focused on
conventional oil and gas production and development in the Western Canadian
Sedimentary Basin. In the future, we may acquire oil and gas properties outside
this geographic area. In addition, the Trust Indenture does not limit our
activities to oil and gas production and development, and we 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 our future operational and financial conditions being
adversely affected.
OIL AND NATURAL GAS PRICES
The monthly cash distributions we pay 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 us 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.
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Declines in oil or natural gas prices will have an adverse effect upon our
operations, financial condition, reserves and ultimately on our ability to pay
distributions to Unitholders.
We may manage the risk associated with changes in commodity prices by entering
into oil or natural gas price hedges. If we hedge our commodity price exposure,
we will forego the benefits it would otherwise experience if commodity prices
were to increase. In addition, commodity hedging activities could expose us to
losses. To the extent that we engage in risk management activities related to
commodity prices, we will be subject to credit risks associated with
counterparties with which we contract.
Oil prices were relatively high throughout 2004 averaging US$41.43 WTI as
compared to an average of US$31.06 WTI in 2003, an increase of 33%.
Monthly AECO prices averaged $6.79/Mcf in 2004 as compared to $6.67/Mcf in 2003,
an increase of 2%. The monthly AECO price in 2004 ranged from a high of
$8.00/Mcf in November to a low of $5.69/Mcf in October. The price of oil and
natural gas will fluctuate and price and demand are factors beyond our 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 we may acquire. As well,
cash distributions from us will be highly sensitive to the prevailing price of
crude oil and natural gas.
MARKETING
The marketability and price of oil and natural gas that may be acquired or
discovered by us will be affected by numerous factors beyond our 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 us and, as a consequence, the amount of
cash available to distribute to Unitholders. Therefore, distributions may be
reduced, or even eliminated, at times when significant capital or other
expenditures are made.
The board of directors of AOG 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 our 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 we use for our 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 us. Any such instance may offset the return on
and value of the Trust Units.
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CHANGES IN ACCOUNTING STANDARDS APPLICABLE TO CONVERTIBLE DEBENTURES
On November 3, 2003 the Accounting Standards Board of the Canadian Institute of
Chartered Accountants approved a change to the accounting standards applicable
to convertible debentures such as those issued by us. The new standard requires
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 are effective for fiscal
periods beginning on or after November 1, 2004.
DEBT SERVICE
AOG has credit facilities in the amount of $310,000,000. 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 us. 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 us or our
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.
PRIOR RANKING INDEBTEDNESS; ABSENCE OF COVENANT PROTECTION
The Debentures will be subordinate to all Senior Indebtedness and to any
indebtedness of our creditors. The payment of principal and interest on the
Debentures will be subordinated to the Senior Indebtedness of us and to
indebtedness of our trade creditors. The Debentures will also be effectively
subordinate to claims of creditors of our subsidiaries except to the extent we
are a creditor of such subsidiaries ranking at least pari passu with such other
creditors.
The Indentures will not limit the ability of us 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 our level of indebtedness, provides
operating investment guidelines, mandates the making of distributions and
specify the nature of our 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. We are unable to assess the effect, if any, that any
such claim would have on our 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 we 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
60
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 our 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 we 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, 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 $US/$Cdn exchange rate that may
fluctuate over time. A material increase in the value of the Canadian dollar,
which occurred in 2004, negatively impacted our net production revenue and may
affect the future value of our reserves as determined by independent evaluations
at this time. The impact is reduced to the extent that we have engaged in, or in
the future will engage in risk management activities related to commodity prices
and foreign exchange rates. We will be subject to unfavourable price changes and
credit risks associated with the counterparties with which it contracts. We have
not entered into any foreign exchange contracts at this time.
Variations in interest rates could result in a significant increase in the
amount we pay 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 our management team could have a
detrimental effect upon us. 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 our properties. Estimating reserves is inherently uncertain.
Ultimately, actual production, revenues and expenditures for our properties will
vary from estimates and those variations could be material. The reserve and cash
flow information contained in this renewal annual information form represent
estimates only. Reserves and estimated future net cash flow from our 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:
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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 our 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.
DEPLETION OF RESERVES
We have 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 we will be successful in developing or acquiring
additional reserves on terms that meet our 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. We currently operate properties that represent approximately 85% of
our total daily production. To the extent the operator fails to perform these
functions properly or becomes insolvent, revenue may be reduced.
ENFORCEMENT OF OPERATING AGREEMENTS
Operations of the wells on properties not operated by us 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
us or our Unitholders. As an owner of working interests in
62
properties we do not operate, we will generally have a cause of action for
damages arising from a breach of such duty. Although not established by
definitive legal precedent, it is unlikely that the Trust or Unitholders would
be entitled to bring suit against third-party operators to enforce the terms of
the operating agreements; thus, Unitholders will be dependent upon us, 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 Unitholders. If we cease 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 us and our Unitholders. Tax authorities having jurisdiction over the
Trust or the Unitholders may disagree with how we calculate our income for tax
purposes or could change administrative practises to the detriment of us or the
detriment of our Unitholders.
We expect that it will continue to qualify as a mutual fund trust for purposes
of the Tax Act. We 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 us and our
Unitholders. Some of the significant consequences of losing mutual fund trust
status are as follows:
o We would be taxed on certain types of income distributed to
Unitholders, including income generated by the royalties held by us.
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 We 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 our
registration revoked by the Canada Customs and Revenue Agency.
In addition, we may take certain measures in the future to the extent it
believes necessary to ensure that we maintain our status as a mutual fund trust.
These measures could be adverse to certain holders of Trust Units.
INVESTMENT ELIGIBILITY
We 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.
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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. Our 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 our
value. The market price of the Trust Units will be sensitive to a variety of
market conditions including, but not limited to, interest rates and our ability
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 our 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 our assets 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 our assets.
ADDITIONAL FINANCING
In the normal course of making capital investments to maintain and expand our
oil and gas reserves, 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 we issue 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, our ability and AOG's ability to make the
necessary capital investments to maintain or expand our 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
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return on investment through interest payments. Distributions represent a blend
of a return of Unitholders' initial investment and a return on Unitholders'
initial investment.
Unitholders have a limited right to require us 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 Unitholders to liquidate their investments. Long Term Notes or Redemption
Notes which may be distributed IN SPECIE to Unitholders in connection with a
redemption will not be listed on any stock exchange and no established market is
expected to develop for such Long Term Notes or Redemption Notes. Cash
redemptions are subject to limitations. See "Additional Information Respecting
Advantage Energy Income Fund - Redemption Right".
UNITHOLDER LIMITED LIABILITY
The Trust Indenture provides that no Trust Unitholder will be subject to any
liability in connection with us or our affairs or obligations and, in the event
that a court determines that 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 our assets.
The Trust Indenture provides that all written instruments signed by or on behalf
of us 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 us 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.
FUTURE DILUTION
One of our objectives is to continually add to our reserves through acquisitions
and through development, and because we does not reinvest our cash flow, our
success is in part dependent upon our 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
Our 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 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 our information
circular for the most recent annual meeting of shareholders that involved the
election of directors. Additional financial information is
65
provided in our financial statements and management's discussion and analysis
for the year ended December 31, 2004. Documents affecting the rights of
securityholders, along with additional information relating to Advantage, may be
found on SEDAR at www.sedar.com.
SCHEDULE "A"
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, 2004 using
forecast prices and costs; and
(ii) the related estimated future net revenue; and
(iii) proved and proved plus probable oil and gas
reserves estimated as at December 31, 2004 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 Vice President, Finance and Chief
Financial Officer
(signed) "RONALD A. MCINTOSH" (signed) "RODGER A. TOURIGNY"
Ronald A. McIntosh Rodger A. Tourigny
Director Director
March 21, 2005
SCHEDULE "B"
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, 2004.
The reserves data consist of the following:
(a) (i) proved and proved plus probable oil and gas reserves
estimated as at December 31, 2004 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, 2004 using constant prices and costs; and
(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
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, 2004, and identifies the respective portions thereof
that we have audited, evaluated and reviewed and reported on to the
Trust's board of directors:
Location of Net Present Value of Future Net Revenue
Independent Qualified Reserves (County (before income taxes, 10% discount rate (000's))
Reserves Evaluator or Description and Preparation or Foreign -------------------------------------------------
Auditor Date of Evaluation Report Geographic Area) Audited Evaluated Reviewed Total
- ------------------------ ---------------------------- ---------------- ------- --------- -------- -----
Sproule Associates Limited Evaluation of the P&NG Canada 75,820 809,274 0 885,094
Reserves of Advantage Energy
Income Fund as of December
31, 2004 prepared November
2004 to February 2005
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.
6. We have no responsibility to update our reports referred to in
paragraph 4 for events and circumstances occurring after its
preparation date.
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
February 17, 2005