EXHIBIT 99.1
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ADVANTAGE ENERGY INCOME FUND
ANNUAL INFORMATION FORM
YEAR ENDED DECEMBER 31, 2005
MARCH 7, 2006
TABLE OF CONTENTS
PAGE
GLOSSARY OF TERMS.............................................................1
ABBREVIATIONS.................................................................4
CONVERSION....................................................................4
ADVANTAGE ENERGY INCOME FUND..................................................6
GENERAL DEVELOPMENT OF THE BUSINESS...........................................7
DESCRIPTION OF OUR BUSINESS AND OPERATIONS....................................8
STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION..................9
ADDITIONAL INFORMATION RESPECTING ADVANTAGE ENERGY INCOME FUND...............29
ADDITIONAL INFORMATION RESPECTING ADVANTAGE OIL & GAS LTD....................35
ADDITIONAL INFORMATION RESPECTING ADVANTAGE INVESTMENT MANAGEMENT LTD........41
MARKET FOR SECURITIES........................................................48
ESCROWED SECURITIES..........................................................50
LEGAL PROCEEDINGS............................................................50
INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS...................50
MATERIAL CONTRACTS...........................................................51
INTEREST OF EXPERTS..........................................................51
AUDITORS, TRANSFER AGENT AND REGISTRAR.......................................51
AUDIT COMMITTEE INFORMATION..................................................51
AUDIT COMMITTEE CHARTER......................................................53
AUDIT SERVICE FEES...........................................................57
RISK FACTORS.................................................................57
DISCLOSURE PURSUANT TO THE REQUIREMENTS OF THE NEW YORK STOCK EXCHANGE.......68
ADDITIONAL INFORMATION.......................................................68
SCHEDULES
"A" - REPORT OF MANAGEMENT AND DIRECTORS ON RESERVES DATA AND OTHER INFORMATION
"B" - REPORT ON RESERVES DATA
GLOSSARY OF TERMS
"10% DEBENTURES" means convertible unsecured subordinated debentures of the
Trust due on November 1, 2007 and convertible into Trust Units at a price of
$13.30 per Trust Unit;
"AOG BOARD OF DIRECTORS" or "BOARD OF DIRECTORS" means the board of directors
of Advantage Oil & Gas Ltd.;
"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 December 30, 2005 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;
"NOON BUYING RATE" means the noon buying rate in New York City for cable
transfers in Canadian dollars as certified for customs purposes by the Federal
Reserve Bank of New York;
"NOTE INDENTURES" means, collectively, the Long Term Note Indenture and the
Medium Term Note Indenture;
2
"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;
"NYSE" means the New York Stock Exchange;
"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;
"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 AOG Board of Directors from time to time):
(i) obligations issued or guaranteed by the government of Canada or any
province of Canada or any agency or instrumentality thereof; (ii) term
deposits, guaranteed investment certificates, certificates of deposit or
bankers' acceptances of or guaranteed by any Canadian chartered bank or other
financial institutions (including the Trustee and any affiliate of the
Trustee) the short-term debt or deposits of which have been rated at least A
or the equivalent by Standard & Poor's Corporation, Moody's Investors Service,
Inc. or Dominion Bond Rating Service Limited; (iii) commercial paper rated at
least A or the equivalent by Dominion Bond Rating Service Limited, in each
case maturing within 180 days after the date of acquisition; and (iv) trust
units and limited partnership units in trusts and limited partnerships which
invest in energy related assets including all types of petroleum and natural
gas and energy related assets, and including, without limitation, facilities
of any kind, oil sands interests, coal, electricity or power generating
assets, and pipeline, gathering, processing and transportation assets;
"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;
3
"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;
"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,
May 26, 2004, April 27, 2005 and December 13, 2005, pursuant to which
Advantage was formed, as the same may be further amended, restated or replaced
from time to time;
"TRUSTEE" means Computershare Trust Company of Canada or its successor or
successors as trustee under the Trust Indenture;
"TSX" means the Toronto Stock Exchange;
"UNIT MARKET PRICE" of the Trust Units at any date means the weighted average
of the trading price per Trust Unit for such Trust Units for the ten (10)
consecutive trading days immediately preceding such date and the ten (10)
consecutive trading days from and including such date, on the TSX and the NYSE
(with the Canadian dollar equivalent of trades occurring on the NYSE being
determined based on the Noon Buying Rate for each such trading day) or, if on
such date the Trust Units are not listed on the TSX or NYSE, on the principal
stock exchanges 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 AOG Board of Directors;
"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; and
"U.S." means the United States of America.
Words importing the singular number only include the plural, and VICE VERSA,
and words importing any gender include all genders. All dollar amounts set
forth in this annual information form are in Canadian dollars, except where
otherwise indicated.
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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 annual information form, and in certain
documents incorporated by reference into this 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 annual
information form should not be unduly relied upon. These statements speak only
as of the date of this annual information form or as of the date specified in
the documents incorporated by reference into this annual information form, as
the case may be.
In particular, this annual information form, and the documents incorporated by
reference, contain forward-looking statements pertaining to the following:
o 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 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 annual information form and the documents incorporated by
reference herein are expressly qualified by this cautionary statement. Except
as required by law, 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 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 our wholly-owned oil and natural gas
exploitation and development company. 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 company
wholly-owned by us. Search and AcquisitionCo amalgamated and continued as
"Search Energy Corp.". On July 26, 2001, Search acquired all of the issued and
outstanding shares of Due West Resources Inc. ("DUE WEST"). Effective August
1, 2001, Search and Due West 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"), after
which Best Pacific assigned all of its assets to AOG and dissolved. On
December 2, 2003, AOG acquired all of the issued and outstanding shares of
MarkWest Resources Canada Corp. ("MARKWEST"). MarkWest 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.
Effective February 1, 2006, Advantage ExchangeCo Ltd. amalgamated with AOG.
In accordance with the Management Agreement, Advantage Investment Management
Ltd. (the "MANAGER") agreed to act as manager of the Trust and of 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 of 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.
7
OUR ORGANIZATIONAL STRUCTURE
The following diagram sets forth our organizational structure as at the date
hereof.
[GRAPHIC OMITTED]
[ORGANIZATIONAL CHART]
----------------------------------------
Trust Unitholders(1)(2)
----------------------------------------
Cash Distribution(2) ^ |
| ^ | Trust Units(100%)
| | Income from Permitted |
| | Investment |
| | | ---------------------
| | | Exchangeable
| | | Shareholders
| | | ---------------------
| | v | |
--------------------------------------------- | |
Advantage Energy |Exchangeable |Exchange
-----------> Income Fund |Shares |Rights
| (Alberta) <| | |
| --------------------------------------------- | | |
| ^ | |---|-------| |
| | | | | |
| |Interest and Pricipal | Royalty,| | |
Management Services |Payments, Royalty Payments | Notes | 100% |
| |and Dividends on Common | 100% | common |
| |Shares | Common | shares |
| | | Shares | | |
| | v v v v
- ----------------------------------- -------------------------------- -------------------------------
<------
Advantage Investment Management Ltd. Fees Advantage Oil & Gas Ltd. Advantage ExchangeCo (II) Ltd.
(Alberta) (Alberta) (Alberta)
-------->
- ----------------------------------- Mangement ------------------------ -------------------------------
Services
Notes:
(1) The Unitholders own 100% of the Trust.
(2) Cash distributions are made to Unitholders monthly based upon our cash
flow.
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 (the "AOG BOARD OF DIRECTORS") and the Manager
has the right to designate two of such directors.
GENERAL DEVELOPMENT OF THE BUSINESS
2003
On July 8, 2003, we completed the issue, by way of short form prospectus, of
$30,000,000 aggregate 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 2, 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 8.25%
convertible unsecured subordinated debentures, which debentures mature on
February 1, 2009 and are convertible into Trust Units at $16.50 per Trust Unit
(the "8.25% 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.
8
2004
On September 15, 2004, we completed an issue, by way of short form prospectus,
of 3,500,000 Trust Units and $75,000,000 aggregate principal amount of 7.50%
convertible unsecured subordinated debentures (the "7.50% DEBENTURES") and
$50,000,000 aggregate principal amount of 7.75% convertible unsecured
subordinated debentures (the "7.75% DEBENTURES") to partially finance the
$186,000,000 (before closing adjustments) acquisition of certain petroleum and
natural gas properties and related assets (the "ACQUIRED ASSETS") from
Anadarko (the "ASSET ACQUISITION"). The 7.50% Debentures mature on October 1,
2009 and are convertible into Trust Units at a price of $20.25 per Trust Unit.
The 7.75% Debentures mature on December 1, 2011 and are convertible into Trust
Units at a price of $21.00 per Trust Unit. 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.
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. As a result of this transaction, we paid
total cash consideration of $34,000,000, issued 3,666,286 Trust Units and
issued 1,450,030 AOG exchangeable shares.
2005
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. The net proceeds of the offering were used to pay down debt
incurred in the Defiant Acquisition, for our 2005 capital expenditure program
and for general corporate purposes.
On December 9, 2005, the Trust Units were listed and posted for trading on the
New York Stock Exchange (the "NYSE") under the trading symbol "AAV". We
believe the listing on the NYSE will result in improved liquidity for all
Unitholders, greater access to the U.S. capital markets, and improved cost of
capital for future acquisitions.
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 2006 financial year.
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;
9
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 and Medium Terms Notes and principal repayments, royalty income
earned on the Royalty, dividends (if any) received on, and amounts, if any,
received on redemption of, Common Shares and Preferred Shares, and income and
distributions received from any Permitted Investments after expenses and
capital expenditures, any cash redemptions of Trust Units, and other
expenditures. See "Additional Information Respecting Advantage Energy Income
Fund - Cash Distributions".
ADVANTAGE OIL & GAS LTD.
AOG is actively engaged in the business of oil and gas exploration,
development, acquisition and production in the provinces of Alberta, British
Columbia and Saskatchewan.
We employ a strategy to maintain production from AOG's existing production
base while focusing capital expenditures on low-risk development
opportunities. As a practice, AOG may manage the risk associated with changes
in commodity prices by entering into oil or natural gas hedges related only to
specific acquisition or project economics. 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 AOG Board of Directors has retained the Manager to
provide comprehensive management services and has delegated certain authority
to the Manager to assist in the administration and regulation of the
day-to-day operations of the Trust and AOG and 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 AOG Board of
Directors.
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
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, 2005. The effective date of the
Statement is December 31, 2005 and the preparation date of the Statement is
February 21, 2006.
10
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, 2005 contained in
a report of Sproule dated February 21, 2006 (the "SPROULE REPORT"). The
Reserves Data summarizes our oil, natural gas 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. We 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. IN CERTAIN OF THE TABLES SET FORTH BELOW, THE
COLUMNS MAY NOT ADD DUE TO ROUNDING.
RESERVES DATA (CONSTANT PRICES AND COSTS)
SUMMARY OF OIL AND GAS RESERVES
AND NET PRESENT VALUES OF FUTURE NET REVENUE
as of December 31, 2005
CONSTANT PRICES AND COSTS
Reserves
-----------------------------------------------------------------------------------------
Light And Medium Oil Heavy Oil Natural Gas 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 13,003 11,382 1,676 1,497 167,529 140,575 3,285 2,427
Developed Non-Producing 356 302 1 1 13,760 11,268 189 135
Undeveloped 2,389 2,008 48 41 17,270 14,068 309 210
Total Proved 15,748 13,693 1,726 1,539 198,560 165,911 3,783 2,772
Probable 12,058 10,124 962 835 89,097 72,030 2,228 1,573
Total Proved Plus Probable 27,806 23,817 2,687 2,374 287,657 237,941 6,010 4,345
11
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 1,736,694 1,295,126 1,051,957 895,090 784,429 1,736,694 1,295,126 1,051,957 895,090 784,429
Producing
Developed 102,011 82,136 68,304 58,159 50,419 102,011 82,136 68,304 58,159 50,419
Non-Producing
Undeveloped 164,983 123,709 95,979 76,392 61,947 164,983 123,709 95,979 76,392 61,947
Total Proved 2,003,688 1,500,970 1,216,240 1,029,642 896,795 2,003,688 1,500,970 1,216,240 1,029,642 896,795
Probable 1,127,351 637,719 425,254 309,948 238,782 1,127,351 637,719 425,254 309,948 238,782
Total Proved
Plus Probable 3,131,039 2,138,690 1,641,493 1,339,589 1,135,578 3,131,039 2,138,690 1,641,493 1,339,589 1,135,578
TOTAL FUTURE NET REVENUE
(UNDISCOUNTED)
as of December 31, 2005
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 3,265,917 517,010 622,812 86,466 31,779 4,162 2,003,688 0 2,003,688
Proved Plus
Probable 5,094,638 859,684 935,360 127,308 33,610 7,637 3,131,039 0 3,131,039
FUTURE NET REVENUE
BY PRODUCTION GROUP
as of December 31, 2005
CONSTANT PRICES AND COSTS
Future Net Revenue Before
Income Taxes (Discounted At
10%/Year)
Reserves Category Production Group ($000's)
----------------- ---------------- --------
Proved Light and Medium Crude Oil (including solution gas and other 426,348
by-products)
Heavy Oil (including solution gas and other by-products) 22,520
Natural Gas (including by-products but excluding solution gas 752,758
from oil wells)
Proved Plus Probable Light and Medium Crude Oil (including solution gas and other 620,623
by-products)
Heavy Oil (including solution gas and other by-products) 32,733
Natural Gas (including by-products but excluding solution gas 972,457
from oil wells)
12
RESERVES DATA (FORECAST PRICES AND COSTS)
SUMMARY OF OIL AND GAS RESERVES
AND NET PRESENT VALUES OF FUTURE NET REVENUE
as of December 31, 2005
FORECAST PRICES AND COSTS
Reserves
-------------------------------------------------------------------------------------------
Light And Medium Oil Heavy Oil Natural Gas 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 12,827 11,246 1,669 1,483 164,552 137,991 3,250 2,404
Developed Non-Producing 354 302 2 2 13,723 11,238 188 135
Undeveloped 2,377 2,014 48 40 17,260 14,058 308 210
Total Proved 15,558 13,562 1,720 1,525 195,534 163,288 3,747 2,749
Probable 11,912 10,072 957 828 88,012 71,082 2,207 1,561
Total Proved Plus Probable 27,470 23,634 2,677 2,352 283,546 234,371 5,953 4,310
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 1,470,814 1,127,704 941,410 820,304 733,603 1,470,814 1,127,704 941,410 820,304 733,603
Producing
Developed Non- 83,554 68,812 58,394 50,631 44,615 83,554 68,812 58,394 50,631 44,615
Producing
Undeveloped 126,922 99,007 78,696 63,828 52,608 126,922 99,007 78,696 63,828 52,608
Total Proved 1,681,290 1,295,522 1,078,500 934,763 830,826 1,681,290 1,295,522 1,078,500 934,763 830,826
Probable 945,519 518,637 344,071 251,914 195,680 945,519 518,637 344,071 251,914 195,680
Total Proved Plus
Probable 2,626,807 1,814,160 1,422,573 1,186,677 1,026,506 2,626,807 1,814,160 1,422,573 1,186,677 1,026,506
TOTAL FUTURE NET REVENUE
(UNDISCOUNTED)
as of December 31, 2005
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 2,994,529 477,346 703,884 87,843 40,048 4,118 1,681,290 0 1,681,290
Proved Plus 4,699,708 786,785 1,102,678 130,210 45,646 7,581 2,626,807 0 2,626,807
Probable
13
FUTURE NET REVENUE
BY PRODUCTION GROUP
as of December 31, 2005
FORECAST PRICES AND COSTS
Future Net Revenue Before
Income Taxes (Discounted At
10%/Year)
Reserves Category Production Group ($000's)
- ---------------------- ------------------------------------------------------------ ---------------------------
Proved Light and Medium Crude Oil (including solution gas and other 371,898
by-products)
Heavy Oil (including solution gas and other by-products) 26,214
Natural Gas (including by-products but excluding solution gas 665,831
from oil wells)
Proved Plus Probable Light and Medium Crude Oil (including solution gas and other 534,972
by-products)
Heavy Oil (including solution gas and other by-products) 37,124
Natural Gas (including by-products but excluding solution gas 834,783
from oil wells)
PRICING ASSUMPTIONS
The following tables set forth the benchmark reference prices, as at December
31, 2005, reflected in the Reserves Data. These price assumptions were
provided to us by Sproule and were Sproule's then current forecasts at the
date of the Sproule Report.
SUMMARY OF PRICING ASSUMPTIONS(1)
as of December 31, 2005
CONSTANT PRICES AND COSTS
Oil
------------------------------------------------------
Natural Gas
WTI Edmonton Hardisty AECO Gas Pentanes Propanes
Cushing Par Price Heavy Cromer Medium Price Plus Fob Butanes Fob Fob Field Exchange
Oklahoma 40(degree)API 12(degree)API 29.3(degree)API ($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/$Cdn)
- ---- --------- ---------- ---------- ------------- ------ ---------- ---------- ---------- ----------
Historical (3)
2005 61.04 68.12 30.86 52.28 9.99 71.35 59.32 51.90 0.86
Notes:
(1) This summary table identifies benchmark reference pricing schedules
that might apply to a REPORTING ISSUER.
(2) The exchange rate used to generate the benchmark reference prices in
this table.
(3) As at December 31.
14
SUMMARY OF PRICING AND INFLATION RATE ASSUMPTIONS(1)
as of December 31, 2005
FORECAST PRICES AND COSTS
Oil
--------------------------------------------------------
Natural Pentanes Butanes Propane
Gas(1) Plus Fob Fob Fob
WTI Edmonton Hardisty Cromer AECO Gas Field Field Field
Cushing Par Price Heavy Medium Price Gate Gate Gate Inflation Exchange
Oklahoma 40(degree)API 12(degree)API 29.3(degree)API ($Cdn/ ($Cdn/ ($Cdn/ ($Cdn/ Rates(2) Rate(3)
Year ($US/bbl) ($Cdn/bbl) ($Cdn/bbl) ($Cdn/bbl) MMbtu) bbl) bbl) bbl) %/Year ($US/$Cdn)
- ---- --------- ---------- ---------- ---------- ------ ---- ---- ---- ------ ----------
Forecast
2006 60.81 70.07 37.07 59.62 11.58 71.77 47.01 39.25 2.5 0.85
2007 61.61 70.99 37.29 60.39 10.84 72.71 47.62 39.76 2.5 0.85
2008 54.60 62.73 34.23 53.48 8.95 64.25 42.08 35.14 2.5 0.85
2009 50.19 57.53 32.27 49.18 7.87 58.92 38.59 32.22 1.5 0.85
2010 47.76 54.65 31.15 46.75 7.57 55.97 36.66 30.61 1.5 0.85
2011 48.48 55.47 31.94 47.54 7.70 56.81 37.21 31.07 1.5 0.85
2012 49.20 56.31 32.74 48.35 7.83 57.67 37.77 31.54 1.5 0.85
2013 49.94 57.16 33.56 49.17 7.96 58.54 38.34 32.01 1.5 0.85
2014 50.69 58.02 34.39 50.00 8.09 59.42 38.92 32.50 1.5 0.85
Thereafter 1.5% 1.5% 1.5% 1.5% 1.5% 1.5% 1.5% 1.5% 1.5 0.85
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, including hedging, realized by us for the
year ended December 31, 2005, were $7.98/Mcf for natural gas, $59.20/bbl for
crude oil, $49.54/bbl for natural gas liquids.
15
RECONCILIATIONS OF CHANGES IN RESERVES AND FUTURE NET REVENUE
RECONCILIATION OF
NET RESERVES
BY PRINCIPAL PRODUCT TYPE
CONSTANT 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, 2004 13,699 10,043 23,742 1,300 537 1,837 2,320 1,391 3,711
Extensions 381 223 604 14 3 17 178 293 471
Improved Recovery 752 1,323 2,075 248 110 358 61 8 69
Technical Revisions 200 (1,639) (1,439) 68 138 206 514 (130) 384
Discoveries 75 26 101 0 0 0 12 4 16
Acquisitions 0 0 0 0 0 0 0 0 0
Dispositions (2) 0 (2) 0 0 0 (3) 0 (3)
Economic Factors 192 148 340 142 47 189 7 7 14
Production (1,604) 0 (1,604) (233) 0 (233) (317) 0 (317)
------- - ------- ----- - ----- ----- - -----
December 31, 2005 13,693 10,124 23,817 1,539 835 2,374 2,772 1,573 4,345
====== ====== ====== ===== === ===== ===== ===== =====
Natural Gas Oil Equivalent
-------------------------------- --------------------------------
Net Net
Proved Proved
Net Net Plus Net Net Plus
Proved Probable Probable Proved Probable Probable
FACTORS (mmcf) (mmcf) (mmcf) (Mboe) (Mboe) (Mboe)
- ------------------- --------- ---------- --------- --------- ---------- ---------
December 31, 2004 179,197 69,138 248,335 47,185 23,494 70,679
Extensions 10,791 9,931 20,722 2,372 2,174 4,546
Improved Recovery 2,053 1,293 3,346 1,403 1,657 3,060
Technical Revisions (3,521) (9,032) (12,553) 195 (3,135) (2,940)
Discoveries 153 51 204 113 38 151
Acquisitions 0 0 0 0 0 0
Dispositions (254) (115) (369) (47) (21) (68)
Economic Factors 1,292 764 2,056 556 330 886
Production (23,800) 0 (23,800) (6,121) 0 (6,121)
-------- - -------- ------- - -------
December 31, 2005 165,911 72,030 237,941 45,656 24,537 70,193
======= ====== ======= ====== ====== ======
16
RECONCILIATION OF
WORKING INTEREST RESERVES
BY PRINCIPAL PRODUCT TYPE
FORECAST PRICES AND COSTS
Light And Medium Oil Heavy Oil Natural Gas Liquids
---------------------------- ------------------------------- -------------------------------
WI WI WI
Proved Proved Proved
WI WI Plus WI WI Plus WI WI Plus
Proved Probable Probable Probable Probable Probable Proved Probable Probable
FACTORS (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl)
- -------------------- ------- --------- ------- -------- --------- --------- --------- ---------- ---------
December 31, 2004 15,468 11,318 26,786 1,562 624 2,186 3,113 1,874 4,987
Extensions 445 265 710 15 11 26 268 419 687
Improved Recovery 871 1,808 2,679 275 127 402 82 12 94
Technical Revisions 126 (1,876) (1,750) 42 149 191 671 (127) 544
Discoveries 83 28 111 0 0 0 17 6 23
Acquisitions 0 0 0 0 0 0 0 0 0
Dispositions (3) 0 (3) 0 0 0 (4) (2) (6)
Economic Factors 433 370 803 97 46 143 29 24 53
Production (1,865) 0 (1,865) (271) 0 (271) (429) 0 (429)
------- - ------- ----- - ----- ----- - -----
December 31, 2005 15,558 11,913 27,471 1,720 957 2,677 3,747 2,206 5,953
====== ====== ====== ===== === ===== ===== ===== =====
Natural Gas Oil Equivalent
--------------------------------
WI WI
Proved Proved
WI WI Plus WI WI Plus
Proved Probable Probable Proved Probable Probable
FACTORS (mmcf) (mmcf) (mmcf) (mmcf) (mmcf) (mmcf)
- ------------------- --------- ---------- --------- --------- ---------- ---------
December 31, 2004 211,395 82,552 293,947 55,375 27,576 82,951
Extensions 13,469 12,038 25,507 2,973 2,701 5,674
Improved Recovery 2,597 1,631 4,228 1,661 2,219 3,880
Technical Revisions (6,424) (11,300) (17,724) (233) (3,739) (3,972)
Discoveries 218 73 291 136 47 183
Acquisitions 0 0 0 0 0 0
Dispositions (308) (147) (455) (58) (27) (85)
Economic Factors 3,262 3,166 6,428 1,103 968 2,071
Production (28,675) 0 (28,675) (7,344) 0 (7,344)
-------- - -------- ------- - -------
December 31, 2005 195,534 88,013 283,547 53,613 29,745 83,358
======= ====== ======= ====== ====== ======
17
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 2005
- ------------------------------------------------------------------------------------- ------------
Estimated Future Net Revenue at Beginning of Year 771,984
Sales and Transfers of Oil and Gas Produced, Net of Production Costs and Royalties (244,341)
Net Change in Prices, Production Costs and Royalties Related to Future Production 535,525
Actual Development Costs Incurred During the Period 56,467
Changes in Estimated Future Development Costs (78,533)
Extensions and Improved Recovery 109,068
Discoveries 3,240
Acquisitions of Reserves 0
Dispositions of Reserves (1,969)
Net Change Resulting from Revisions in Quantity Estimates 5,400
Accretion of Discount 59,399
Net Change in Income Taxes 0
-
Estimated Future Net Revenue at End of Year 1,216,240
=========
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. 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 1,053 0 1,733 181 1,523
2005 319 0 2,529 30 771
PROBABLE UNDEVELOPED RESERVES
Light and Medium Oil Heavy Oil Natural Gas Natural Gas Liquids
Year (Mbbl) (Mbbl) (MMcf) (Mbbl) Mboe
- ---- -------------------- ------------------ ----------------- ---------------------- ----------
2004 265 0 1,945 126 715
2005 764 0 11,109 320 2,936
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.
18
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.
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%
-- --- -- --- -- ---
2006 50,135 48,910 60,891 58,897 50,135 48,910
2007 24,628 21,842 41,412 36,414 24,027 21,309
2008 7,857 6,335 13,471 10,768 7,479 6,030
2009 4,814 3,528 7,208 5,238 4,470 3,276
Additional years 409 197 7,228 4,288 355 173
Total 87,843 80,812 130,210 115,606 86,466 79,698
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
issuance of 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
Our properties are spread geographically throughout the Western Canadian
Sedimentary Basin. This sedimentary basin covers a large portion of the 4
western Canadian provinces, with the majority of our properties concentrated
in Alberta, along with a few in northeast British Columbia and also southeast
Saskatchewan. These properties produce from a variety of various aged
geological formations and reservoirs. We have managed our portfolio so that we
now operate more than 85% of our properties. This allows us to control the
nature and timing of the capital investments necessary to maximize the
potential in developing these assets.
Our properties can be divided on the broad basis of commodity and of
production type. Light or medium gravity oil accounts for 35% of our
production and 33% of our reserves. A further 65% of production and 67% of
reserves are natural gas.
SHALLOW GAS PROPERTIES
A significant portion of our production comes from shallow gas properties at
Medicine Hat, Bantry, Shouldice and Wainwright. These projects are all located
in southern Alberta and occur between 500 and 1,200 meters of depth. Typical
of shallow gas, these properties are resource plays which require a large
number of wells to extract the very large in place reserves at relatively low
per well production rates. As a result, they have a long production life (long
reserve life index or RLI). These reservoirs consist of low permeability
strata, requiring fracture stimulation to enhance and induce productivity. The
wells are gathered by an extensive network of low pressure pipelines which
feed into large central gas compression facilities. All of these properties
have been downspaced to allow for multiple gas wells per section, ranging from
just 2 per section at Wainwright to the current 16 per section at Medicine
Hat.
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 approximately 5.2 MMcf/d of natural gas. In 2002 and 2003, several
recompletions along with an additional 164 wells were
19
drilled. Late in 2003 an additional 57 wells were drilled and completed in
2004. In 2004 a further 68 wells were drilled and completed. Late in 2005 and
early in 2006, 30 low production rate wells were recompleted. As a result,
current production from this property is 15.3 MMcf/d from approximately 385
wells. No new wells were added in 2005. 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 or 2005.
Sproule evaluated our reserves in the area and assigned 58.7 bcf of proved
natural gas reserves and 9.9 bcf of probable reserves. As such, this property
is our largest property on an assigned reserves basis.
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. This property was acquired in November
2003. During 2004 we drilled 48 (gross) wells. An additional 5 (gross) wells
were drilled during 2005. Of these 5 wells, one has been abandoned. 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 1,286
boe/d. Additional compression capacity was added in the first quarter of 2004
to handle incremental volumes. In 2005, a rationalization of compression
facilities was undertaken to reduce future operating costs and free up capital
from surplus compression equipment.
The Sproule Report assigns 11.7 bcf of proven natural gas reserves and 18.7
Mbbls of proven NGL reserves to this property. In addition, 6.6 bcf of
probable natural gas reserves and 10.6 Mbbls of probable NGL reserves have
been assigned to this property.
SHOULDICE, ALBERTA
The Shouldice area of southern Alberta is located approximately 50 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
in the area. Much of this acreage is downspaced to accommodate additional
drilling. Current natural gas production of approximately 4.1 MMcf/d is
produced on a co-mingled basis from the Medicine Hat Formation sands with
various Belly River Formation sands.
During 2003, 20 net wells were added to the existing 70 producing wells. Both
natural gas and crude oil are produced and gathered through our facilities of
varying working interests. An additional 4 MMcf/d of new compression capacity
was added in 2004 to handle additional production. In 2005, one new well was
drilled and produces at an approximate rate of 500 Mcf/d. Additional drilling,
potentially up to 10 wells, is planned on this property in 2006.
The Sproule Report assigns 9.1 bcf of proven natural gas reserves and 90 Mbbls
of proven crude oil and NGLs to this property. In addition, 3.8 bcf of
probable natural gas reserves and 39 Mbbls of probable crude oil and NGL
reserves have been assigned to this property.
WAINWRIGHT, ALBERTA
The Wainwright property is located approximately 175 kilometres southeast of
the City of Edmonton. We have varying working interests in this property
averaging 85% in approximately 175 sections of land. Current net production
from the property is approximately 4.3 MMcf/d natural gas and 24 bbls/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. No drilling occurred on this property in
2004 and 2005.
20
Sproule evaluated our proved reserves in the Wainwright area and assigned 8.1
bcf of natural gas. Probable reserves in this area were evaluated by Sproule
at 2.3 bcf of natural gas.
CONVENTIONAL OIL AND NATURAL GAS PROPERTIES
Conventionally produced oil and gas properties constitute the majority of our
property portfolio. Some of these properties produce only natural gas or,
occasionally, only oil. In most instances both products co-exist in the
production and we operate in excess of 80% of these properties. In 2005 the
bulk of our capital expenditures occurred on these properties, and was
significantly spread out amongst many individual projects.
NEVIS, ALBERTA
The Nevis property is situated 60 km east of Red Deer. Nevis consists of
approximately 55 sections of land with an average working interest over 80%
and is 95% 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. Crude oil quality to date has been exceptional ranging
for the most part between 35o and 42o API. Natural gas is gathered through our
pipelines and processed at a third party plant. Oil is trucked from single
well batteries.
In 2005, 13 horizontal wells and 4 vertical wells were drilled. Current
production is approximately 2,000 boe/d. Currently the pool is spaced to allow
for 4 wells per section. Currently, the property is being reviewed to evaluate
the potential waterflood of this reservoir to increase future recoveries and
to evaluate future downspacing.
The Sproule Report assigns 17.6 bcf of proven natural gas reserves and 3,693
Mbbls of proven crude oil and NGL reserves to this property. In addition, 5.5
bcf of probable natural gas reserves and 1,285 Mbbls of probable crude oil and
NGL reserves have been assigned to this property.
CHIP LAKE, ALBERTA
The Chip Lake property is located 125 kilometers west of the City of Edmonton.
The property produces light crude oil (37o API) with associated gas.
Production at the end of 2005 is approximately 490 boe/d. This property was
acquired in December 2004. Prior to the acquisition, the previous owner had
constructed a central sour oil and water handling facility without appropriate
Energy Utilities Board ("EUB") approval. We are involved in extensive
discussion with the EUB and public stakeholders to resolve this issue in 2006.
Currently the property will continue to produce from single well batteries
under maximum rate limitation allowables until the issues are resolved.
The Sproule Report has assigned proved reserves for this property of 2,128
Mbbls of crude oil and NGL's and 1.9 Bcf of natural gas. In addition, 2,648
Mbbls of probable crude oil and NGL's and 1.8 Bcf of probable natural gas
reserves have been assigned to the property.
SUNSET/VALLEYVIEW, 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 were acquired in
December 2004 by virtue of the acquisition of Defiant.
SUNSET A - Production is predominantly oil at approximately 32oAPI to date.
This pool is unitized and we have a 70% working interest in the unit which we
also operate. During 2005, two wells were drilled and spaced across the unit
which evaluated the viability of moving the full pool onto a downspaced basis.
Plans are to drill an additional 14 wells in 2006. Current net production from
the Sunset A unit is 240 bbls/d of crude oil and 240 Mcf/d of natural gas. 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.
21
SUNSET B - Production from this Montney reservoir is predominantly natural gas
although there is a thin oil column. Oil gravity is light at 33oAPI. We have a
100% interest in this pool. 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 1.9
MMcf/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. No wells were drilled in 2005 and plans
for 2006 are being investigated.
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, NGLs and
light oil from both properties are processed. We have a 93% average working
interest in the pool. One new well was drilled in 2005 and there are plans to
drill 2 new wells in 2006. Production at Valleyview is essentially all natural
gas with current rates of approximately 3.0 MMcf/d. All wells require fracture
stimulation to bring them on production and cost approximately $750,000
drilled, completed and tied-in.
For the three properties, Sunset A, Sunset B and Valleyview, the Sproule
Report assigns 19.8 bcf of proven natural gas reserves and 2,096 Mbbls of
proven crude oil and NGL reserves to this property. In addition, 13.2 bcf of
probable natural gas reserves and 2,274 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 just west 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. Historically, 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 North Pine Charlie Lake oil pool. The area includes 12,000
gross (9,176 net) acres of undeveloped land. Current production from this area
is 3.2 MMcf/d of natural gas and 177 bbls/d of light oil and NGLs.
Sproule evaluated our proved reserves in the area and assigned 10.9 bcf of
natural gas and 561 Mbbls of crude oil and NGLs. In addition, 4.2 bcf of
probable natural gas reserves and 265 Mbbls of probable crude oil and NGLs
reserves have been assigned to this property.
SOUTHEAST SASKATCHEWAN
This area consists of a host of individual properties all within the Williston
Sedimentary Basin in the southeast corner of Saskatchewan. We operate the
majority of this production at 100% which comes principally from the major
properties being the Ordovician Red River Formation oil at Midale, Hardy and
Froude, Devonian Winnipegosis Formation oil at Steelman and oil from
Mississippian Midale/Frobisher Formations at Steelman, Weyburn and Workman. We
drilled two multi-leg horizontal Frobisher wells at Steelman in 2005. Also one
vertical Red River oil well and a vertical Mannville water injector well were
drilled at Froude. Numerous well re-activations and re-entries were undertaken
in 2005 in several pools. Production from Saskatchewan, all light crude oil,
was 1,720 bbls/d. Southeast Saskatchewan will continue to be an active area
for us with additional drilling and/or side track re-entries planned in 2006
at Hardy, Midale and Steelman. The Workman property is being reviewed for
unitization and waterflood.
Sproule evaluated our reserves in the area and assigned 3,556 Mbbls of proven
crude oil. Probable reserves in this area were evaluated by Sproule at 2,940
Mbbls of crude oil.
BRAZEAU RIVER, ALBERTA
The Brazeau River property is located approximately 50 km west of the town of
Drayton Valley. 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
22
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. In 2005, this property experienced numerous production issues
related to various delays in servicing the wells by the operator. These issues
have been resolved and production has been restored. Current net production
from the property is approximately 2.5 MMcf/d natural gas and 310 bbls/d NGLs
and crude oil.
Sproule evaluated our proved reserves in the Brazeau River area and assigned
3.0 bcf of natural gas and 329 Mbbls of crude oil and NGLs. Probable reserves
in this area were evaluated by Sproule at 2.5 bcf of natural gas and 220 Mbbls
of crude oil and NGLs.
OPEN LAKE (WILLESDEN GREEN), ALBERTA
The Willesden Green property is located approximately 35 km north of the Town
of Rocky Mountain House. The property was acquired in the package of assets
purchased from Anadarko in 2004. We operate and have in excess of a 90%
working interest in the Willesden Green 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. Net current production from
the property is approximately 3.2 mmcf/d natural gas and 432 bbls/d NGLs and
crude oil.
Sproule evaluated our proved reserves in the Willesden Green area and assigned
5.5 bcf of natural gas and 660 Mbbls of crude oil and NGLs. Probable reserves
in this area were evaluated by Sproule at 2.4 bcf of natural gas and 335 Mbbls
of crude oil and NGLs.
OIL AND GAS WELLS
The following table sets forth the number and status of wells as at December
31, 2005 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 607.0 377.2 390.2 220.4 1155.0 965.6 210.0 113.6
British Columbia 1.0 0.4 5.0 2.3 64.0 37.3 15.0 6.2
Saskatchewan 192.0 145.5 86.0 62.7 0.0 0.0 0.0 0.0
Manitoba 85.0 5.1 0.0 0.0 0.0 0.0 0.0 0.0
----- ----- ----- ----- ------ ------ ----- -----
Total 885.0 528.2 481.2 285.4 1219.0 1002.9 225.0 119.8
===== ===== ===== ===== ====== ====== ===== =====
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.
23
PROPERTIES WITH NO ATTRIBUTED RESERVES
The following table sets out our developed and undeveloped land holdings as at
December 31, 2005.
Developed Acres Undeveloped Acres Total Acres
------------------------ ------------------------ ------------------------
Gross Net Gross Net Gross Net
----- --- ----- --- ----- ---
Alberta 695,129 333,500 372,556 160,107 1,067,685 493,607
British Columbia 97,419 18,855 23,851 5,715 121,270 24,570
Saskatchewan 30,718 21,940 108,860 91,758 139,578 113,698
------- ------- ------- ------- --------- -------
Total 823,266 374,295 505,267 257,580 1,328,533 631,875
======= ======= ======= ======= ========= =======
We expect that rights to explore, develop and exploit 85,227 net acres of our
undeveloped land holdings will expire by December 31, 2006. The land
expirations do not consider our 2006 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.
FORWARD CONTRACTS
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 in recent years. Such prices are primarily determined
by economic, and in the case of oil prices, political factors. Supply and
demand factors, as well as weather, general economic conditions, and
conditions in other oil and natural gas regions of the world also impact
prices. Any upward or downward movement in oil and natural gas prices could
have an effect on our financial condition, thus impacting the cash
distributions made to Unitholders.
In the past, we have entered into short term hedging agreements which have
limited the risk associated with downward changes in commodity prices.
However, these agreements have also meant that we have foregone the benefit of
any price increases. As a future practice, we may manage the risk associated
with changes in commodity prices by entering into oil or natural gas price
hedges. These hedging activities could expose us to losses or gains. However,
such oil or natural gas price hedges will only be entered into on specific
acquisitions and projects. To the extent that we engage in risk management
activities related to commodity prices, we will be subject to credit risk
associated with the parties with which we contract. This credit risk will be
mitigated by entering into contracts with only stable and creditworthy parties
and through the frequent review of our exposure to these entities entities.
We currently do not have any hedge contracts or forward commitments in place.
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 2,433
(gross) producing and non-producing wells. Costs to abandon and reclaim the
producing wells totals $45.8 million ($11.6 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 $48.2 million ($3.5 million discounted at 10%), and
was not deducted in estimating future net revenue. Facility reclamation costs
are scheduled to be incurred in the year following the end of the reserve life
of our associated reserves under the assumption that decommissioning of
plant/facilities are mobile assets with a long useful life.
24
Abandonment and reclamation costs included in the estimate of future net
revenue for the next three years are $0.6 million in 2006, $0.8 million in
2007 and $1.3 million in 2008.
TAX HORIZON
In 2005, we did not pay any income related taxes. However, we did pay capital
taxes that are determined based on the debt and equity levels of the Trust at
the end of a given taxation year. As a result of legislation in 2003, capital
taxes are to be gradually eliminated over the next four years.
In our structure, the operating company utilizes available tax pools to
significantly reduce taxable income and makes other required payments to the
Trust transferring both income and associated tax liability to the
Unitholders. Therefore, it is expected, based on current legislation that no
cash income taxes are to be paid by the operating company in the future and it
is our intent to continue with the current arrangement. For the 2005
distributions, 40% were taxable to the Canadian Unitholders and 60% were
deemed a return of capital. For U.S. Unitholders, 2005 distributions were 44%
taxable and 56% were deemed a return of capital.
CAPITAL EXPENDITURES
The following tables summarize capital expenditures (including capitalized
general and administrative expenses) related to our activities for the year
ended December 31, 2005:
CAPITAL EXPENDITURES ($ THOUSANDS) 2005
- -------------------------------------------------------------------------------
Land and seismic 3,860
Drilling, completions and workovers 77,794
Well equipping and facilities 20,322
Other 1,253
- -------------------------------------------------------------------------------
103,229
- -------------------------------------------------------------------------------
Property, acquisitions and purchase price adjustments 308
Property dispositions (3,379)
- -------------------------------------------------------------------------------
TOTAL CAPITAL EXPENDITURES $100,158
- -------------------------------------------------------------------------------
EXPLORATION AND DEVELOPMENT ACTIVITIES
The following table sets forth the gross and net wells in which we
participated during the year ended December 31, 2005:
Exploratory Development Total
----------------------- ---------------------- ----------------------
Gross Net Gross Net Gross Net
----- --- ----- --- ----- ---
Oil wells 3 2.0 42 22.4 45 24.4
Gas wells 13 8.1 39 18.2 52 26.3
Dry holes 1 1.0 4 1.9 5 2.9
-- ---- -- ---- --- ----
Total 17 11.1 85 42.5 102 53.6
== ==== == ==== === ====
Subject to, among other things, the availability of drilling rigs and weather
that permits access to drill sites, in 2006, we plan to drill, complete and
tie-in 96.2 net wells and recomplete an additional 52.0 net wells.
Approximately 30 net wells will be drilled at Medicine Hat, 14 net wells at
Nevis, 10 net wells at Sunset and 7 net wells in the Red Deer Area. The well
recompletions will be focussed in Medicine Hat, Wainwright and SE
Saskatchewan.
25
PRODUCTION ESTIMATES
The following table sets out the volume of our production estimated for the
year ended December 31, 2006 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 4,409 750 68,986 1,285 17,942
Developed Non-Producing 57 0 3,542 54 701
Undeveloped 573 35 3,165 58 1,193
----- --- ------ ----- ------
Total Proved 5,039 785 75,693 1,397 19,836
Probable 461 47 3,307 99 1,159
----- --- ------ ----- ------
Total Proved Plus Probable 5,500 832 79,000 1,496 20,995
===== === ====== ===== ======
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
--------------------------------------------------------
2005
--------------------------------------------------------
Dec. 31 Sept. 30 Jun. 30 Mar. 31
------- -------- ------- -------
Average Daily Production(1)
Crude oil and NGLs (bbls/d) 7,106 7,340 6,772 6,892
Natural gas (Mcf/d) 72,587 75,994 79,492 86,350
Combined (boe/d) 19,204 20,006 20,021 21,284
Average Net Prices Received(2)
Crude oil and NGLs ($/bbl) 59.53 61.10 56.24 53.02
Natural gas ($/Mcf) 10.67 7.79 7.30 6.47
Royalties(3)(5)
Crude oil and NGLs ($/bbl) 13.81 11.91 10.75 10.46
Natural gas ($/Mcf) 2.13 1.47 1.34 1.27
Combined ($/boe) 13.18 9.97 8.94 8.54
Operating Expenses(4)(5)
Crude oil and NGLs ($/bbl) 11.41 9.44 8.88 8.74
Natural gas ($/Mcf) 1.49 1.12 1.09 0.98
Combined ($/boe) 9.84 7.72 7.31 6.80
Netback Received(6)
Crude oil and NGLs ($/bbl) 34.31 39.75 36.61 33.82
Natural gas ($/Mcf) 7.05 5.20 4.87 4.22
Combined ($/boe) 39.33 34.32 31.75 28.09
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.
26
(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, 2005:
Natural Gas Crude Oil & NGLs Total
Properties (Mcf/d) (bbls/d) (boe/d)
- ------------------------------------------------------------------------------
Medicine Hat 15,300 - 2,550
Sunset/Valleyview 5,140 361 1,218
Bantry 7,650 11 1,286
Nevis 4,793 1,201 2,000
Shouldice 3,930 30 685
Willesden Green 3,198 432 965
- ------------------------------------------------------------------------------
Major Properties 40,011 2,035 8,704
Other 32,589 5,065 10,496
- ------------------------------------------------------------------------------
TOTAL 72,600 7,100 19,200
DEFINITIONS AND OTHER NOTES
1. Columns set forth above 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:
27
(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:
(f) 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;
(g) in relation to wells, the total number of wells in which we have an
interest; and
(h) in relation to properties, the total area of properties in which we
have an interest.
"NET" means:
(i) 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;
(j) in relation to wells, the number of wells obtained by aggregating
our working interest in each of our gross wells; and
(k) 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.
28
Each of the reserve categories (proved and probable) may be divided into
developed and undeveloped categories:
(c) 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.
(d) 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 15% 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.
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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 2006 by the renegotiation or
termination of contracts or subcontracts.
ENVIRONMENTAL CONSIDERATIONS
We are pro-active in our approach to environmental 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, 2005, we employ 80 full-time employees, 68 of which are
located in the head office and 12 of which are located in the field. We also
employ 9 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, 2005, 57,846,324 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 the AOG 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.
The price per Trust Unit is a function of anticipated distributable income
from AOG and the combined ability of the AOG Board of Directors and the
Manager to effect long term growth in the value of the Trust. The market price
of the Trust Units
30
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, 2005, AOG had 104,672 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
AOG Board of Directors in its sole discretion from time to time, such cash
dividends as may be declared thereon by the AOG 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
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.
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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 AOG Board of Directors 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 AOG Board of Directors 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.
Pursuant to the provisions of the Trust Indenture all income earned by the
Trust in a fiscal year, not previously distributed in that fiscal year, must
be distributed to Unitholders of record on December 31. This excess income, if
any, will be allocated to Unitholders of record at December 31 but the right
to receive this income, if the amount if not determined and declared payable
at December 31, will trade with the Trust Units until determined and declared
payable in accordance with the rules of the Toronto Stock Exchange. To the
extent that a Unitholder trades Trust Units in this period they will be
allocated such income but will dispose of their right to receive such
distribution.
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
32
redemption (the "REDEMPTION DATE"); and (ii) the "closing market price" on the
principal market on which the Trust Units are quoted for trading on the
Redemption Date.
For the purposes of this calculation, "market price" is an amount equal to the
simple average of the closing price of the Trust Units for each of the trading
days on which there was a closing price, provided that, if the applicable
exchange or market does not provide a closing price but only provides the
highest and lowest prices of the Trust Units traded on a particular day, the
market price shall be an amount equal to the simple average of the highest and
lowest prices for each of the trading days on which there was a trade, and
provided further that if there was trading on the applicable exchange or
market for fewer than five of the 10 trading days, the market price shall be
the simple average of the following prices established for each of the 10
trading days: the average of the last bid and last ask prices for each day on
which there was no trading; the closing price of the Trust Units for each day
that there was trading if the exchange or market provides a closing price; and
the average of the highest and lowest prices of the Trust Units for each day
that there was trading, if the market provides only the highest and lowest
prices of Trust Units traded on a particular day. The "closing market price"
shall be: an amount equal to the closing price of the Trust Units if there was
a trade on the date; an amount equal to the average of the highest and lowest
prices of the Trust Units if there was trading and the exchange or other
market provides only the highest and lowest prices of Trust Units traded on a
particular day; and the average of the last bid and last ask prices if there
was no trading on the date.
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.
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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 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 26,
2006.
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 AOG Board of Directors 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 AOG Board of
Directors 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 was 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
34
resign upon providing 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.
DELEGATION OF AUTHORITY, ADMINISTRATION AND TRUST GOVERNANCE
The AOG Board of Directors 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 AOG
Board of Directors 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 AOG
Board of Directors pursuant to the terms of the Shareholder Agreement. Subject
to the ultimate authority of the AOG Board of Directors, AOG and the Trust
will be managed by the Manager. For more information as to the AOG Board of
Directors, 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 AOG Board of Directors 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 AOG Board of Directors. In addition, the Trustee has delegated
certain matters to the AOG Board of Directors, including making all decisions
relating to: (i) issuance of additional Trust Units; and (ii) the
determination of the amount of distributable income. Any amendment to any
material contract to which we are a party will require the approval of the AOG
Board of Directors on our behalf. The AOG Board of Directors generally intends
to hold regularly scheduled meetings to review the business and affairs of the
Trust and AOG and to make any necessary decisions relating thereto.
LIABILITY OF THE TRUSTEE
The Trustee, its directors, officers, employees, shareholders and agents shall
not be liable to any Trust Unitholder or any other person, in tort, contract
or otherwise, in connection with any matter pertaining to the Trust or the
Trust Fund, arising from the exercise by the Trustee of any powers,
authorities or discretion conferred under the Trust Indenture, including,
without limitation, any action taken or not taken in good faith in reliance
upon any documents that are, PRIMA FACIE, properly executed, any depreciation
of, or loss to, the Trust Fund incurred by reason of the sale of any asset,
any inaccuracy in any evaluation provided by the Manager or any other
appropriately qualified person, any reliance upon any such evaluation, any
action or failure to act of the Manager, AOG, or any other person to whom the
Trustee has, with the consent of AOG, delegated any of its duties hereunder,
or any other action or failure to act (including failure to compel in any way
any former trustee to redress any breach of trust or any failure by the
Manager or AOG to perform its duties under or delegated to it under the Trust
Indenture or any material contract), unless such liabilities arise out of the
gross negligence, wilful default or fraud of the Trustee or any of its
directors, officers, employees, shareholders or agents. If the Trustee has
retained an appropriate expert, adviser or legal counsel with respect to any
matter connected with its duties under the Trust Indenture or any material
contract, the Trustee may act or refuse to act based upon the advice of such
expert, adviser or legal counsel, and the Trustee shall not be liable for and
shall be fully protected from any loss or liability occasioned by any action
or refusal to act based upon the advice of any such expert, adviser or legal
counsel. In the exercise of the powers, authorities or discretion
35
conferred upon the Trustee under the Trust Indenture, the Trustee is and shall
be conclusively deemed to be acting as Trustee of the assets of the Trust and
shall not be subject to any personal liability for any debts, liabilities,
obligations, claims, demands, judgments, costs, charges or expenses against or
with respect to the Trust or the Trust Fund. In addition, the Trust Indenture
contains other customary provisions limiting the liability of the Trustee.
AMENDMENTS TO THE TRUST INDENTURE
The Trust Indenture may be amended or altered, from time to time, by at least
66 2/3% 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 AOG
Board of Directors, 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 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
36
directors to the AOG Board of Directors. The directors of AOG that were
appointed by the Manager are Kelly Drader and Gary Bourgeois. Unitholders will
always be entitled to select the majority of the Board of Directors. In
addition, a majority of the AOG 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 AOG Board of Directors must be a director
elected by the Unitholders. The following table sets forth certain information
respecting AOG's directors and executive officers.
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Position Held and
Name, Province and Country Period Served as
of Residence a Director(4)(5) Principal Occupations During Past Five Years
- --------------------------------------------------------------------------------------------------------------------------------
Gary F. Bourgeois Vice President, Vice President, Corporate Development of AOG since May 24, 2001. Vice
Ontario, Canada Corporate President of the Manager since March 2001. Prior thereto, Managing
Development and Director of the EnerPlus Group of Companies, which companies specialize
Director since in management of oil and gas income funds and royalty trusts
May 24, 2001 (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 May 24, 2001. President
Alberta, Canada Executive Officer of the Manager since March 2001. Prior thereto, Senior Vice President
and Director (1997-2001) and Vice President, Finance and Chief Financial Officer
since May 24, (1990-1997) of EnerPlus Group of Companies, which companies specialize in
2001 the management of oil and gas income funds and royalty trusts.
Ronald A. McIntosh(1)(2)(3) Director since Chairman of Navigo Energy Inc. since December 2003. As of December 29,
Alberta, Canada September 25, 2003, Navigo Energy Inc. became a wholly-owned subsidiary of NAV Energy
1998(6) 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 thereto, Vice
British Columbia, Canada December 31, President, Business Development of Search Energy Corp.
1996(6)
Carol Pennycook(2) Director since Partner at the Toronto office of Davies Ward Phillips & Vineberg, LLP, a
Ontario, Canada May 26, 2004 national law firm.
Steven Sharpe(1)(2) Director since Managing Partner of Blair Franklin Capital Partners Inc., an investment
Ontario, Canada May 24, 2001 and banking firm since May, 2003. Prior thereto, Mr. Sharpe was the Managing
Non-Executive Director of The EBS Corporation, a management and strategic consulting
Chairman since firm, since June 2001. From July 1998 to June 2001, Executive Vice
May 26, 2004 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 gas consulting
Alberta, Canada December 31, company.
1996(6)
37
- --------------------------------------------------------------------------------------------------------------------------------
Position Held and
Name, Province and Country Period Served as
of Residence a Director(4)(5) Principal Occupations During Past Five Years
- --------------------------------------------------------------------------------------------------------------------------------
Lamont Tolley(1)(3)(8) Director since President of Genex Energy Inc., a private oil and gas company and former
Alberta, Canada May 24, 2001 President and Chief Executive Officer of Rally Energy Corp. Prior
thereto, an independent businessman who has been active in the oil and
gas industry for 20 years. 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 President of the
Alberta, Canada President 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 Vice President Chief Financial Officer of AOG since January 2003. Prior thereto,
Alberta, Canada Finance and Controller of AOG since December 1999. Prior thereto, Manager of
Chief Financial Financial Reporting with Numac Energy Inc.
Officer
Richard Mazurkewich Vice President, Vice President, Operations of AOG since August 2001. Prior thereto,
Alberta, Canada Operations 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. Prior thereto, with
Alberta, Canada Exploitation 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.
Anthony Coombs Controller Controller since September 1, 2004. Prior thereto with AOG since May 23,
Alberta, Canada 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 law firm.
Alberta, Canada Secretary
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.
38
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.
(8) Not standing for re-election at the upcoming meeting of Unitholders.
As at March 1, 2006, the directors and executive officers of AOG, as a group,
beneficially owned, directly or indirectly, or exercised control or direction
over, 2,108,797 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 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 received 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. AOG is the sole holder of
the issued and outstanding Common Shares. There are no Non-Voting Shares or
Preferred Shares issued and outstanding. AOG is also the sole holder of the
outstanding Notes.
The following is a description of the rights attaching to the Common Shares,
Non-Voting Shares, Preferred Shares, 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 AOG Board of Directors
and subject to applicable legal restrictions, entitled to receive any
dividends declared by the AOG 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.
39
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
AOG 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, 2005, AOG had 104,672 Exchangeable Shares outstanding. The
Exchangeable Shares were issued in connection with our acquisition of Defiant.
See "Additional Information Respecting Advantage Energy Income Fund -
Exchangeable Shares".
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.
40
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 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, 2005 was
$540,140,328. 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 AOG 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, 2005 was $200,664,757. The Medium Term Notes
consist of a series of notes, which as of December 31, 2005, 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, 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
41
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)).
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, approval of the AOG 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 AOG 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 AOG 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 AOG Board of
Directors. Under the terms of the Shareholder Agreement, the Manager has the
right to designate two directors to be elected to the AOG 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 AOG Board of Directors has retained the
Manager to provide comprehensive management services and has delegated certain
authority to the Manager to assist in the administration and regulation of the
day-to-day operations of us and of AOG and to assist in making executive
decisions which conform to the general policies and general principles
previously established by the AOG Board of Directors. The Manager will provide
executive officers to AOG, subject to the approval of the AOG Board of
Directors.
42
MANAGEMENT OF THE MANAGER
The following table outlines the names and provinces of residence and
principal occupations of the officers of the Manager who will be responsible
for the provision of such executive services.
- ----------------------------------------------------------------------------------------------------------------------------------
Name, Province and
County 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
Alberta, Canada 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
Ontario, Canada 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
Alberta, Canada 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 AOG Board
of Directors, prepare all production, capital and expense budgets
and business plans in connection with the Properties and also
provide quarterly progress reports to the AOG Board of Directors;
(g) provide or cause to be provided to AOG any services or analysis
reasonably necessary for AOG to be able to consider or participate
in any acquisition, development or disposition by AOG of an interest
in the Properties or other interests in assets;
(h) provide or arrange for such additional administrative services as
AOG may reasonably request in connection with the Properties,
including services relating to the administration of credit
facilities obtained by AOG;
(i) review opportunities to acquire additional Properties which, acting
reasonably, it believes AOG might reasonably be interested in
acquiring and, from time to time, to present AOG with opportunities
to acquire Properties consistent with the investment criteria of
AOG;
(j) conduct negotiations for the acquisition of Properties, provide
lease and land services related to such acquisitions (including
examination and evaluation of any title documents) and arrange for
examination and preparation of legal documents or such other
services required in connection with such acquisitions, provided
that the Manager shall be deemed not to make any warranty of title
with respect to any Properties acquired by AOG;
(k) provide or arrange for all necessary exploitation, development and
other services in respect of acting as operator of any of the
Properties;
(l) review all data, information, notices and requests tendered by any
third party operator, advise AOG as to the appropriate action to be
taken and provide or arrange for any required expertise on behalf of
AOG to facilitate the proper conduct of operations in respect
thereof;
(m) arrange for and negotiate, on behalf of and in the name of AOG, all
contracts with third parties for the proper management and
operations of the Properties;
(n) supervise the disposition and marketing of Petroleum Substances from
the Properties, invoice third parties as required and effect the
collection of receivables relating thereto;
(o) ensure that AOG complies with all material regulations, statutes and
reporting requirements in connection with the Properties;
(p) carry out the functions and obligations of AOG contained in the
Royalty Agreement with respect to operation of the Properties; and
(q) negotiate all borrowings required by AOG to purchase Properties or
to fund capital expenditures;
2. to 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 AOG Board of Directors 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 AOG Board of Directors.
The Manager and the Trust are responsible for ensuring compliance with the
continuous disclosure obligations under all applicable securities legislation.
The Manager has been indemnified by AOG and the Trust in respect of damages
suffered relating to the performance of services under the Management
Agreement provided that the Manager is in compliance with the standard of care
described below, and any of its directors, officers or employees have been
indemnified by AOG and the Trust provided that such person shall not be found
to be liable for or guilty of wilful misfeasance, bad faith, gross negligence
or reckless disregard of his or her duty to AOG or the Trust.
In exercising its powers and discharging its duties under the Management
Agreement, the Manager is required to exercise that degree of care, diligence
and skill that a reasonably-prudent operator and manager in respect of oil and
gas properties in western 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
45
expenditures are focused on development activity as opposed to exploration.
Exploration properties are generally sold, farmed out or developed using third
party resources. Reserve replacement and additions are achieved through
development activity and acquisitions.
In addition, as part of the services to be provided by the Manager to AOG and
the Trust, the Manager may recommend that AOG enter into agreements to dispose
of Oil and Natural Gas Properties and make farmouts and other dispositions of
such properties. Approval by the AOG Board of Directors of any acquisitions or
dispositions is required where the properties being acquired or disposed of
have a purchase price or proceeds in excess of $2,000,000.
COMPENSATION AND TERM
In its role under the Management Agreement as manager and administrator of 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 60th 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 AOG Board of Directors) for acting in such
capacity.
The Manager does not receive any acquisition or disposition fees.
It is the intention of the Manager that the management fees referred to in
paragraphs 1 and 2 above (collectively, the "MANAGEMENT FEES") will fund all
employee bonuses and incentive plans. Effective December 30, 2005, such fees
are allocated by the Manager, subject to the discretion of the Manager, on the
following basis:
Manager
Operating Fee 60%
Termination Fee 60%
Performance Fee 40%
Employees of AOG
Operating Fee 40%
Termination Fee 40%
Performance Fee 60%
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 AOG Board of Directors.
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 AOG Board
of Directors has not provided notice to the Manager prior to any such renewal
that such renewal shall not occur. In all instances of termination (except
where the Management Agreement terminates at the end of the term), a
termination fee ("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 AOG Board of Directors of the fact and substance of any
particular conflict of interest, if one should occur, and to use all
reasonable efforts to resolve such conflict of interest in a manner which will
treat 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 AOG Board of Directors of the nature and extent of
their interest in such activities and a description of such activities and
unless, in each case, the consent of the AOG Board of Directors 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 AOG Board of Directors, make investments in or
acquire oil and gas assets or income funds, royalty trusts or companies
owning oil and gas assets, except for the purchase of securities of
public oil and gas companies, income funds or royalty trusts on a
recognized stock exchange for investment purposes. Such shareholding in
each such investment shall not exceed 10% of the issued and outstanding
securities of any such issuer; and
3. they will not, without prior approval of us and AOG, acting reasonably,
as determined by the AOG Board of Directors, conduct any other business
activities relating to Canadian resource properties or rendering services
or acting as advisor or manager to any other person or entity that may
have investment or business interests similar to those of 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.
47
CASH DISTRIBUTIONS
The following is a summary of the distributions made by us for each of the
three most recently completed financial years.
- ------------------------------------------------------------------------------
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
48
- ------------------------------------------------------------------------------
For the 2005 Period Ended Distributions per Unit Payment Date
- ------------------------------------------------------------------------------
January 31 $0.28 February 15, 2005
February 29 0.28 March 15, 2005
March 31 0.28 April 15, 2005
April 30 0.28 May 16, 2005
May 31 0.25 June 15, 2005
June 30 0.25 July 15, 2005
July 31 0.25 August 15, 2005
August 31 0.25 September 15, 2005
September 30 0.25 October 17, 2005
October 31 0.25 November 15, 2005
November 30 0.25 December 15, 2005
December 31 0.25 January 16, 2006
TOTAL $3.12
Note:
(1) On February 15, 2006 a distribution of $0.25 per Trust Unit was paid to
Unitholders of Record on the close of business on January 31, 2006. We
announced on February 13, 2006 that a distribution of $0.25 per Trust
Unit will be payable on March 15, 2006 to Unitholders of record on the
close of business on February 28, 2006.
MARKET FOR SECURITIES
Our Trust Units are listed for trading on the TSX under the symbol "AVN.UN"
and, since December 9, 2005, on the NYSE under the symbol "AAV". The following
table sets forth the high and low closing trading prices and the aggregate
trading volume of the Trust Units as reported by the TSX for the periods
indicated.
- ------------------------------------------------------------------------------
Period High Low Volume
- ------------------------------------------------------------------------------
TSX TRADING 2005 ($) ($)
January 22.09 21.21 6,007,901
February 22.00 20.94 8,188,739
March 21.02 18.34 9,463,453
April 20.00 17.60 6,229,329
May 18.87 16.30 6,854,020
June 18.79 16.80 7,130,086
July 18.50 17.10 6,174,794
August 19.76 18.09 6,991,872
September 21.75 19.60 6,284,570
October 21.35 18.50 5,140,740
November 21.58 18.76 4,497,044
December 23.48 20.77 6,764,154
NYSE TRADING
December U.S. 20.28 U.S. 18.92 2,521,700
Our 10% Convertible Debentures are listed for trading on the TSX under the
symbol "AVN.DB". The following table sets forth the high and low closing
trading prices and the aggregate trading volume of the 10% Convertible
Debentures as reported by the TSX for the periods indicated.
49
- ------------------------------------------------------------------------------
Period High Low Volume
- ------------------------------------------------------------------------------
2005 ($) ($)
January 165.00 160.00 1,070
February 164.75 155.00 3,260
March 153.50 141.00 1,150
April 149.99 137.87 2,090
May 139.00 130.25 1,374
June 137.00 132.85 170
July 135.00 130.00 1,216
August 146.65 146.65 20
September 159.33 149.00 1,960
October 156.38 144.04 1,260
November 160.04 144.99 1,310
December 172.70 171.20 380
Our 9% Convertible Debentures are listed for trading on the TSX under the
symbol "AVN.DB.A". The following table sets forth the high and low closing
trading prices and the aggregate trading volume of the 9% Convertible
Debentures as reported by the TSX for the periods indicated.
- ------------------------------------------------------------------------------
Period High Low Volume
- ------------------------------------------------------------------------------
2005 ($) ($)
January 129.50 115.00 6,407
February 128.00 123.50 6,040
March 122.50 108.99 4,750
April 117.00 106.08 3,681
May 107.30 105.00 2,350
June 113.50 105.80 4,230
July 111.00 106.19 6,530
August 116.50 110.50 1,190
September 126.59 114.00 6,150
October 122.00 112.09 2,820
November 125.07 113.05 3,260
December 133.93 122.00 4,130
Our 8.25% Convertible Debentures are listed for trading on the TSX under the
symbol "AVN.DB.B". The following table sets forth the high and low closing
trading prices and the aggregate trading volume of the 8.25% Convertible
Debentures as reported by the TSX for the periods indicated.
- ------------------------------------------------------------------------------
Period High Low Volume
- ------------------------------------------------------------------------------
2005 ($) ($)
January 133.00 129.00 3,285
February 132.25 126.11 4,800
March 125.26 118.21 8,330
April 120.16 108.10 1,970
May 111.00 106.25 510
June 111.86 105.82 1,600
July 110.00 104.75 980
August 118.00 109.45 1,610
September 131.20 119.55 18,090
October 126.00 117.00 960
November 126.49 114.50 1,200
December 140.60 130.50 2,200
50
Our 7.5% Convertible Debentures are listed for trading on the TSX under the
symbol "AVN.DB.C". The following table sets forth the high and low closing
trading prices and the aggregate trading volume of the 7.5% Convertible
Debentures as reported by the TSX for the periods indicated.
- ------------------------------------------------------------------------------
Period High Low Volume
- ------------------------------------------------------------------------------
2005 ($) ($)
January 110.08 107.55 9,400
February 110.00 108.00 26,970
March 108.25 101.50 27,680
April 107.04 101.50 15,380
May 104.48 100.12 12,580
June 104.96 101.66 14,570
July 105.00 102.50 10,000
August 107.00 102.50 11,320
September 110.00 106.00 63,960
October 108.50 105.06 32,320
November 111.01 105.00 3,750
December 115.31 108.00 31,060
Our 7.75% Convertible Debentures are listed for trading on the TSX under the
symbol "AVN.DB.D". The following table sets forth the high and low closing
trading prices and the aggregate trading volume of the 7.75% Convertible
Debentures as reported by the TSX for the periods indicated.
- ------------------------------------------------------------------------------
Period High Low Volume
- ------------------------------------------------------------------------------
2005 ($) ($)
January 108.99 105.75 4,610
February 108.85 106.50 24,150
March 108.00 98.21 28,990
April 106.75 101.00 32,340
May 104.00 99.51 19,160
June 103.50 101.25 15,150
July 103.99 102.10 13,130
August 106.25 102.50 28,520
September 110.01 105.75 51,500
October 108.71 103.80 24,090
November 107.01 103.75 21,310
December 111.25 106.05 24,840
ESCROWED SECURITIES
As at the date hereof, none of our securities are subject to escrow.
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 MANAGEMENT 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 2005 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
2005, and (ii) as disclosed herein.
51
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 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 7, 2006 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 (the "AUDIT COMMITTEE") is comprised of Messrs. Steven
Sharpe, Rodger Tourigny, Ronald McIntosh 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, PROVINCE AND COUNTRY OF FINANCIALLY
RESIDENCE INDEPENDENT LITERATE RELEVANT EDUCATION AND EXPERIENCE
- ------------------------------------------------------------------------------------------------------------------------------
Steven Sharpe Yes Yes Mr. Sharpe has an LLB and is currently Managing Partner
Ontario, Canada 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
Alberta, Canada 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.
Ronald McIntosh Yes Yes Mr. McIntosh has a Bachelor of Engineering and a M.Sc.
Alberta, Canada in Geology. He serves as the Chairman of NAV Energy
Trust and Chairman of North American Energy Partners Inc.
He is Chairman and member of the Audit Committee of
Tasman Exploration Ltd. and director and member of the
Audit Committee of C1 Energy Ltd. He has served as
President and CEO of Navigo Energy, COO of Gulf Canada
Resources, VP Exploration and International for
Petro-Canada and Executive VP and COO of Amerada Hess
Canada.
Lamont Tolley(1) Yes Yes Mr. Tolley holds an MBA and is currently President of
Alberta, Canada Genex Energy Inc., a private oil and gas company. Mr.
Tolley is also serving as a director and member of the
Audit Committee of Delphi Energy Corp. and as a director
of Rally Energy Corp., having previously served as
President and Chief Executive Officer. He has 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 and
director of several public issuers and private companies.
Note:
(1) Not standing for re-election at the upcoming meeting of Unitholders.
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
53
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 AOG Board of Directors on April 30, 2002 and amended in April
2003, April 2004, June 2005, August 2005, October 2005 and March 2006:
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.
("AOG") in fulfilling its responsibilities by reviewing: the financial reports
and other financial information provided by Advantage Energy Income Fund (the
"Trust") 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 endeavour to encourage continuous
improvement of, and should endeavour to foster adherence to, the Trust's
policies, procedures and practices at all levels. In performing its duties,
the external auditor is to report directly to the Audit Committee. The Audit
Committee's primary objectives are:
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 assist the Board's oversight of the auditor's qualifications and
independence;
4. To assist the Board's oversight of the credibility, integrity and
objectivity of financial reports;
5. To strengthen the role of the outside directors by facilitating
discussions between directors on the Audit Committee, management and
external auditors;
6. To assist the Board's oversight of the performance of Corporation's
internal audit function and independent auditors; and
7. To assist the Board's oversight of the Corporation's compliance with
legal and regulatory requirements.
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
"independent" (as such term is defined in (a) Multilateral Instrument 52-110
- -- Audit Committees ("MI 52-110") and (b) Section 303A.02 of the Corporate
Governance Rules of the New York Stock Exchange). 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
definition is set forth in Schedule "A" attached hereto. Audit Committee
members may enhance their familiarity with finance and accounting by
participating in educational programs conducted by the Trust or an outside
consultant. In addition, at least one member of the Audit Committee must have
accounting or related financial management expertise, as the Corporation's
Board of Directors interprets such qualification in its business judgment.
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
54
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.
In connection with the election of the members of the Audit Committee, the
Board will determine whether any proposed nominee for the Audit Committee
serves on the Audit Committees of more than three public companies. To the
extent that any proposed nominee of the Corporation serves on the Audit
Committees of more than three public companies, the Board will make a
determination as to whether such simultaneous services would impair the
ability of such member to effectively serve on the Corporation's Audit
Committee and will disclose such determination in the Corporation's annual
information circular and annual report on Form 40-F filed with the Securities
and Exchange Commission.
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, internal auditors (if any) 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 Section IV.4 below. The Audit Committee should also meet with management
and independent auditors on an annual basis to review and discuss annual
financial statements and the management's discussion and analysis of financial
conditions and results of operations. Attached as Schedule "B" is an example
of an annual meeting schedule/agenda.
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
endeavour to:
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 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.
7. Periodically discuss guidelines and policies to govern the processes by
which the Chief Executive Officer and senior management assess and manage
the Corporation's exposure to risk.
8. Report regularly to the Board any issues that arise with respect to the
quality or integrity of the Corporation's financial statements,
compliance with legal or regulatory requirements, performance and
independence of the Corporation's auditors, or performance of the
internal audit function.
55
9. To prepare, if required, an Audit Committee report to be included in the
Corporation's annual information circular and proxy statement.
10. Preparing an annual performance evaluation of the Audit Committee.
11. At least annually, obtaining and reviewing the report by the independent
auditors describing the Trust's internal quality control procedures, any
material issues raised by the most recent interim quality-control review,
or peer review, of the Trust or by any inquiry or investigation by
governmental or professional authorities, within the preceding five
years, respecting one or more independent audits carried out by the firm,
and any steps to deal with any such issues.
INDEPENDENT AUDITORS
12. Recommend to the Board the external auditors to be nominated for
appointment by the unitholders.
13. Approve the compensation of the external auditors.
14. 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. In addition, the Audit
Committee will ensure the rotation of the lead audit partner every five
years and, in order to ensure continuing auditor independence, consider
the rotation of the audit firm itself.
15. Review and, as appropriate, resolve 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.
16. 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.
17. 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.
18. Oversee the establishment of an internal audit function.
19. Periodically assess the Corporation's internal audit function, including
Corporation's risk management processes and system of internal controls.
20. Review the audit scope and plan of the independent auditor.
21. 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.
22. 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
(c) the procedures do not include delegation of the Audit Committee's
responsibilities to management.
56
The Audit Committee will satisfy the pre-approval requirement set forth
in this paragraph 22 if:
(d) 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;
(e) 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;
(f) 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;
and
23. Review, set and approve hiring policies relating to staff of current and
former auditors.
FINANCIAL REPORTING PROCESSES
24. In consultation with the independent auditors, annually review the
integrity of the organization's financial reporting processes, both
internal and external.
25. In consultation with the independent auditors, consider annually the
quality and appropriateness of the Corporation's accounting principles as
applied in its financial reporting.
26. 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.
27. Review risk management policies and procedures of the Trust and AOG
(i.e., litigation and insurance).
PROCESS IMPROVEMENT
28. 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.
29. 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.
30. Review any significant disagreements among management and the independent
auditors in connection with the preparation of the financial statements.
31. 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.)
32. 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.
33. Review the systems that identify and manage principal business risks.
34. Establish a procedure for:
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(a) the receipt, retention and treatment of complaints received by the
Trust and AOG regarding accounting, internal accounting controls or
auditing matters; and
(b) the confidential, anonymous submission by employees of the Trust and
AOG of concerns regarding questionable accounting or auditing
matters;
which procedure shall be set forth in a "whistle blower program" to be
adopted by the Audit Committee in connection with such matters.
ETHICAL AND LEGAL COMPLIANCE
35. Establish, review and update periodically a Code of Ethical Conduct and
ensure that management has established a system to enforce this code.
36. Review management's monitoring of the Trust's compliance with the
organization's Ethical Code.
37. 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.
38. 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.
39. Review with the organization's counsel legal compliance matters including
the trading policies of securities.
OTHER
40. 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.
41. In connection with the performance of its responsibilities as set forth
above, the Audit Committee shall have the authority to engage outside
advisors and to pay outside auditors and advisors.
AUDIT SERVICE FEES
AUDITOR SERVICES FEES
The following table discloses fees billed to us by our auditors, KPMG LLP.
- -------------------------------------------------------------------------------------------------------------------------------
TYPE OF SERVICE PROVIDED 2005 2004
- -------------------------------------------------------------------------------------------------------------------------------
Audit Fees (these services included prospectus work and audit or review of financials $269,000 $244,500
forming part of such prospectus and U.S. GAAP reconciliation matters)
Audit-Related Fees (these services included French translation in connection with $30,000 $51,000
prospectus offerings)
Tax Fees (these services included review/completion of tax returns and general tax $21,725 $26,497
consultations)
RISK FACTORS
The following is a summary of certain risk factors relating to the business of
AOG and the Trust. The following information is a summary only of certain risk
factors and is qualified in its entirety by reference to, and must be read in
conjunction with, the detailed information appearing elsewhere in this annual
information form.
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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.
OIL AND NATURAL GAS PRICES
AOG's results of operations and financial condition and 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 global energy policy, including the ability of OPEC to set and maintain
production levels and prices for oil;
o political conditions throughout the world, including the risk of
hostilities in the Middle East and global terrorism;
o worldwide economic conditions;
o weather conditions;
o the supply and price of foreign oil and natural gas;
o the level of consumer demand;
o the price and availability of alternative fuels;
o the proximity to, and capacity of, transportation facilities;
o the effect of worldwide energy conservation measures; and
o government regulations.
Declines in oil or natural gas prices will have an adverse effect upon 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 2005 averaging US$56.61 WTI as
compared to an average of US$41.43 WTI in 2004, an increase of 37%.
AECO monthly index prices averaged $8.49/Mcf in 2005 as compared to $6.79/Mcf
in 2004, an increase of 25%. 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.
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
59
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.
OPERATING COSTS AND PRODUCTION DECLINES
Higher operating costs for the underlying properties of AOG will directly
decrease the amount of cash flow received by us and, therefore, may reduce
distributions to our Unitholders. Electricity, chemicals, supplies,
reclamation and abandonment and labour costs are a few of AOG's operating
costs that are susceptible to material fluctuation.
The level of production from AOG's existing properties may decline at rates
greater than anticipated due to unforeseen circumstances, many of which are
beyond AOG's control. A significant decline in production could result in
materially lower revenues and cash flow and, therefore, could reduce the
amount available for distributions to Unitholders.
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.
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 AOG Board of Directors has the discretion to determine the extent to which
cash flow will be allocated to the payment of debt service charges as well as
the repayment of outstanding debt, including under the credit facility. As a
consequence, the amount of funds retained by AOG to pay debt services charges
or reduce debt will reduce the amount of cash distributed to Unitholders
during those periods in which funds are so retained.
ASSESSMENTS OF VALUE OF ACQUISITIONS
Acquisitions of resource issuers and resource assets will be based in large
part upon engineering and economic assessments made by independent engineers.
These assessments will include a series of assumptions regarding such factors
as recoverability and marketability of oil and gas, future prices of oil and
60
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.
DEBT SERVICE
AOG has credit facilities in the amount of $355,000,000. 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.
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 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.
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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, accounting delays, 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 $Cdn/$US exchange rate that
may fluctuate over time. A material increase in the value of the Canadian
dollar, which occurred in 2005, negatively impacted our net production revenue
and may affect the future value of our reserves as determined by independent
evaluations at this time. The Canadian dollar strengthened in 2005 to average
$0.83 US/Cdn compared to $0.77 US/Cdn in 2004. 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 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:
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;
62
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 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.
63
CHANGES IN TAX AND OTHER LAWS MAY ADVERSELY AFFECT UNITHOLDERS.
Income tax laws, or other laws or government incentive programs relating to
the oil and gas industry, such as the treatment of mutual fund trusts and
resource allowance, may in the future be changed or interpreted in a manner
that adversely affects us and our Unitholders.
In particular, generally speaking, the Tax Act provides that a trust will
permanently lose its "mutual fund trust" status (which is essential to the
income trust structure) if it is established or maintained primarily for the
benefit of non-residents of Canada (which is generally interpreted to mean
that the majority of unitholders must not be non-residents of Canada), unless
at all times after February 21, 1990, "all or substantially all" of the
trust's property consisted of property other than taxable Canadian property
(the "TCP EXCEPTION"). Based on the most recent information obtained by us
through our transfer agent and financial intermediaries, in February 2006 an
estimated 60% of our issued and outstanding Trust Units were held by
non-residents of Canada (as defined in the Tax Act) at that time. We are
currently able to take advantage of the TCP Exception, and as a result, the
Trust Indenture does not currently have a specific limit on the percentage of
Trust Units that may be owned by non-residents.
On March 23, 2004 the Canadian federal government announced proposed changes
to the Tax Act which would have effectively eliminated, over a period of time,
the TCP Exception currently relied on by us to maintain our mutual fund trust
status, and, if implemented, would require us to comply with the requirement
that it "not be maintained primarily for the benefit of non-residents". In
response to submissions from and discussions with stakeholders, the Canadian
federal government suspended the implementation of those proposed amendments.
The Canadian Minister of Finance indicated in the February 23, 2005 federal
budget that further consultations would be pursued with stakeholders on
taxation issues related to income trusts and other flow-through entities. On
September 8, 2005, the Canadian Department of Finance released a discussion
paper on these matters and invited interested parties to make submissions to
the Department of Finance. On November 23, 2005, the former Canadian Minister
of Finance issued a news release announcing that no change would be made to
the tax treatment of income trusts in Canada and calling an end to the
consultation process initiated in September 2005.
Notwithstanding the above, there is no assurance that the TCP Exception will
continue to be available to the Trust or that the Canadian federal government
will not introduce new changes or proposals to tax regulations directed at
non-resident ownership which, given our level non-resident ownership, may
result in us losing our mutual fund trust status or could otherwise
detrimentally affect us and the market price of the Trust Units. We intend to
continue to take the necessary measures in order to ensure that we continue to
qualify as a mutual fund trust under the Tax Act. There would be material
adverse consequences if we lost our status as a mutual fund trust under
Canadian tax laws. See "Changes in Legislation - Material Adverse Tax
Consequences to Loss of Mutual Fund Trust Status".
However, we may not be able to take steps necessary to ensure that we maintain
our mutual fund trust status. Even if we are successful in taking such
measures, these measures could be adverse to certain holders of Trust Units,
particularly "non-residents" of Canada (as defined in the Tax Act). There can
be no assurance that such circumstances would not detrimentally affect the
market price of the Trust Units.
Additionally, legislation may be implemented to limit the investment in income
funds and royalty trusts by certain investors or to change the manner in which
these entities are taxed. Tax authorities having jurisdiction over us or our
Unitholders may disagree with how we calculate our income for tax purposes or
could change administrative practices to our detriment or the detriment of our
Unitholders.
CHANGES IN LEGISLATION - MATERIAL ADVERSE TAX CONSEQUENCES TO LOSS OF MUTUAL
FUND TRUST STATUS
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
64
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.
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
65
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 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
66
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 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. Notwithstanding the provisions of
the Trust Indenture and the fact that Alberta (our governing jurisdiction) has
adopted legislation purporting to limit trust unitholder liability, because of
uncertainties in the law relating to investment trusts, there is a risk that a
Unitholder could be held personally liable for obligations of the Trust in
respect of contracts or undertakings which the Trust enters into and for
certain liabilities arising otherwise than out of contracts including claims
in tort, claims for taxes and possibly certain other statutory liabilities.
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.
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.
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.
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.
67
CHANGES IN ACCOUNTING STANDARDS
During 2005 there were several changes to financial reporting requirements.
The changes impacting us are noted below.
FINANCIAL INSTRUMENTS - PRESENTATION AND DISCLOSURE
Effective January 1, 2005, the Fund retroactively adopted the revised
accounting standard Section 3860 "Financial Instruments - Presentation and
Disclosure" as issued by the CICA. The revised standard applies to financial
instruments that may be settled at the issuer's option in cash or its own
equity instruments and impacts our prior accounting for convertible debentures
and the performance incentive fee. We previously classified the issuance of
convertible debentures and the performance fee obligation as components of
equity on the basis that the obligations could be settled with the issuance of
Trust Units. Interest expense and issuance costs related to the debentures
were charged to accumulated income as a component of equity. Based on the
revised standard, a financial instrument is presented based on the substance
of the contractual arrangement regardless of the means of settlement. This
results in the reclassification of convertible debentures to long-term
liabilities and the performance fee to current liabilities. Additionally, a
financial instrument with an embedded conversion feature must be segregated
between liabilities and equity based on the relative fair market value of the
liability and equity portions. Therefore, the debenture liabilities are
presented at less than their eventual maturity values. The liability and
equity components are further reduced for issuance costs initially incurred.
The discount of the liability component as compared to maturity value is
accreted by the "effective interest" method over the debenture term. As
debentures are converted to Trust Units, an appropriate portion of the
liability and equity components are transferred to Unitholders' capital.
Interest and accretion expense on the convertible debentures are shown on the
Consolidated Statements of Income.
EXCHANGEABLE SHARES
In March 2005, the CICA's Emerging Issues Committee amended EIC-151
"Exchangeable Securities Issued by Subsidiaries of Income Trusts". The EIC
specifies the required criteria to present exchangeable shares as a component
of Unitholders' equity. Exchangeable shares that do not meet both criteria are
classified as either debt or non-controlling interest depending on the nature
of the instrument. Prior to the amendment, Exchangeable Shares of AOG were
shown as a component of Unitholders' equity. However, the Exchangeable Shares
do not meet the requirements of the amended standard given that the shares are
transferable, although not publicly traded. Therefore, Exchangeable Shares are
now classified as non-controlling interest, outside of Unitholders' equity.
The Exchangeable Shares and Trust Units are considered economically equivalent
since the exchange ratio is increased on each date that a distribution is paid
on the Trust Units and all shares must be exchanged for either Trust Units or
cash, based on the current market price of the Trust Units. Since the
Exchangeable Shares are required to be exchanged, there is no permanent
non-controlling interest. As a consequence of presenting Exchangeable Shares
as non-controlling interest, a corresponding expense is recorded that reflects
the earnings attributable to the non-controlling interest. When Exchangeable
Shares are converted to Trust Units, the carrying value of non-controlling
interest on the balance sheet is reclassified to Unitholders' capital. We
retroactively implemented the revised standard but there was no income impact
on periods prior to 2005 given that the Exchangeable Shares were issued at the
end of 2004.
FINANCIAL INSTRUMENTS -- RECOGNITION AND MEASUREMENT
In April 2005, a series of new accounting standards were released which
established guidance for the recognition and measurement of financial
instruments. These new standards include Section 1530 "Comprehensive Income",
Section 3855 "Financial Instruments -- Recognition and Measurement", and
Section 3865 "Hedges", in each case issued by the CICA. The new standards also
resulted in a number of significant consequential amendments to other
accounting standards to accommodate the new sections. The standards require
all applicable financial instruments to be classified into one of several
categories including: financial assets and financial liabilities held for
trading, held-to-maturity investments, loans and receivables,
available-for-sale financial assets, or other financial liabilities. The
financial instruments are then included on an issuer's balance sheet and
measured at fair value, cost or amortized value, depending on the
classification. Subsequent measurement and recognition of changes in value of
the financial instruments also depends on the initial classification. These
standards are effective for interim and annual financial statements for fiscal
years beginning on or after October 1, 2006 and must be implemented
simultaneously. We have not yet assessed the full impact, if any, of these
standards on the consolidated financial statements. However, we anticipate
adoption of the new standards on January 1, 2007.
68
RISKS PARTICULAR TO UNITED STATES AND OTHER NON-RESIDENT UNITHOLDERS
In addition to the risk factors set forth above, the following risk factors
are particular to unitholders who are not residents of Canada.
UNITED STATES AND OTHER NON-RESIDENT UNITHOLDERS MAY BE SUBJECT TO ADDITIONAL
TAXATION.
The Tax Act and the tax treaties between Canada and other countries may impose
additional withholding or other taxes on the cash distributions or other
property paid by us to Unitholders who are not residents of Canada, and these
taxes may change from time to time. For instance, since January 1, 2005, a 15%
withholding tax is applied to return of capital portion of distributions made
to non-resident unitholders.
THE ABILITY OF UNITED STATES AND OTHER NON-RESIDENT UNITHOLDERS INVESTORS TO
ENFORCE CIVIL REMEDIES MAY BE LIMITED.
We are a trust organized under the laws of Alberta, Canada, and our principal
place of business is in Canada. All of the directors and officers of AOG are
residents of Canada and most of the experts who provide services to us (such
as its auditors and some of its independent reserve engineers) are residents
of Canada, and all or a substantial portion of their assets and our assets are
located within Canada. As a result, it may be difficult for investors in the
United States or other non-Canadian jurisdictions (a "FOREIGN JURISDICTION")
to effect service of process within such Foreign Jurisdiction upon such
directors, officers and representatives of experts who are not residents of
the Foreign Jurisdiction or to enforce against them judgments of courts of the
applicable Foreign Jurisdiction based upon civil liability under the
securities laws of such Foreign Jurisdiction, including United States federal
securities laws or the securities laws of any state within the United States.
In particular, there is doubt as to the enforceability in Canada against us or
any of our directors, officers or representatives of experts who are not
residents of the United States, in original actions or in actions for
enforcement of judgments of United States courts of liabilities based solely
upon the United States federal securities laws or the securities laws of any
state within the United States.
DISCLOSURE PURSUANT TO THE REQUIREMENTS OF THE NEW YORK STOCK EXCHANGE
As a Canadian issuer listed on the New York Stock Exchange (the "NYSE"), we
are not required to comply with most of the NYSE rules and listing standards
and instead may comply with domestic requirements. As a foreign private
issuer, we are only required to comply with three of the NYSE Rules: 1) have
an audit committee that satisfies the requirements of the United States
Securities Exchange Act of 1934; 2) the Chief Executive Officer must promptly
notify the NYSE in writing after an executive officer becomes aware of any
material non-compliance with the applicable NYSE Rules; and 3) provide a brief
description of any significant differences between our corporate governance
practices and those followed by U.S. companies listed under the NYSE. We have
reviewed the NYSE listing standards and confirm that our corporate governance
practices do not differ significantly from such standards.
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 provided in our
financial statements and management's discussion and analysis for the year
ended December 31, 2005. 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, 2005 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, 2005 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 7, 2006
SCHEDULE "B"
REPORT ON RESERVES DATA
To the board of directors of Advantage Energy Income Fund (the "Trust"):
2. We have evaluated the Trust's reserves data as at December 31, 2005. The
reserves data consist of the following:
(a) (i) proved and proved plus probable oil and gas reserves estimated
as at December 31, 2005 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, 2005
using constant prices and costs; and
(ii) the related estimated future net revenue.
3. 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).
4. 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.
5. 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, 2005, 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 91,382 1,331,190 Nil 1,422,572
Reserves of Advantage Energy
Income Fund as of December
31, 2005 prepared October
2005 to February 2006
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 judgments regarding future
events, actual results will vary and the variations may be material.
(signed) "Sproule Associates Limited"
- -------------------------------------
Sproule Associates Limited
Calgary, Alberta
February 28, 2006