EXHIBIT 99.1
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A D V A N T A G E
E N E R G Y I N C O M E F U N D
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ANNUAL INFORMATION FORM
YEAR ENDED DECEMBER 31, 2006
March 21, 2007
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TABLE OF CONTENTS
PAGE
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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..................................9
STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION...............11
ADDITIONAL INFORMATION RESPECTING ADVANTAGE ENERGY INCOME FUND.............34
ADDITIONAL INFORMATION RESPECTING ADVANTAGE OIL & GAS LTD..................41
MARKET FOR SECURITIES......................................................48
ESCROWED SECURITIES........................................................52
LEGAL PROCEEDINGS..........................................................52
INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS.................52
MATERIAL CONTRACTS.........................................................52
INTEREST OF EXPERTS........................................................52
AUDITORS, TRANSFER AGENT AND REGISTRAR.....................................53
AUDIT COMMITTEE INFORMATION................................................53
AUDIT COMMITTEE CHARTER....................................................54
AUDIT SERVICE FEES.........................................................59
INDUSTRY CONDITIONS........................................................59
RISK FACTORS...............................................................65
DISCLOSURE PURSUANT TO THE REQUIREMENTS OF THE NEW
YORK STOCK EXCHANGE................................................75
ADDITIONAL INFORMATION.....................................................76
SCHEDULES
"A" - REPORT OF MANAGEMENT AND DIRECTORS ON RESERVES DATA AND
OTHER INFORMATION
"B" - REPORT ON RESERVES DATA
GLOSSARY OF TERMS
"6.50% DEBENTURES" means 6.50% convertible unsecured subordinated debentures of
the Trust due June 30, 2010;
"7.50% DEBENTURES" means 7.50% convertible unsecured subordinated debentures of
the Trust due October 1, 2009;
"7.75% DEBENTURES" means 7.75% convertible unsecured subordinated debentures of
the Trust due December 1, 2011;
"8.25% DEBENTURES" means 8.25% convertible unsecured subordinated debentures of
the Trust due February 1, 2009;
"9.00% DEBENTURES" means 9.00% convertible unsecured subordinated debentures of
the Trust due August 1, 2008;
"10.00% DEBENTURES" means 10.00% convertible unsecured subordinated debentures
of the Trust due November 1, 2007;
"ADMINISTRATION AGREEMENT" means the agreement entered into between the Trustee
and AOG dated as of June 23, 2006 and providing for the administration of the
Trust;
"ADMINISTRATOR" means AOG;
"ADVANTAGE" or "THE TRUST" means Advantage Energy Income Fund, an
unincorporated trust formed under the laws of the Province of Alberta pursuant
to the Trust Indenture. All references to "ADVANTAGE" or "THE TRUST", unless
the context otherwise requires, are references to Advantage and its
predecessors and subsidiaries;
"ADVANTAGE RU PLAN" means the Advantage restricted unit incentive plan which
was implemented in connection with the Arrangement;
"AIM" means Advantage Investment Management Ltd., a corporation incorporated
under the ABCA and which amalgamated with AOG effective June 23, 2006;
"AOG" or the "CORPORATION" means Advantage Oil & Gas Ltd., a corporation
incorporated under the ABCA and a wholly-owned subsidiary of the Trust. All
references to "AOG", unless the context otherwise requires, are references to
Advantage Oil & Gas Ltd. and its predecessors;
"AOG BOARD OF DIRECTORS" or "BOARD OF DIRECTORS" means the board of directors
of Advantage Oil & Gas Ltd.;
"ARRANGEMENT" means the plan of arrangement involving Advantage, AOG, Ketch,
Ketch Resources Ltd., Advantage ExchangeCo II Ltd., Advantage Investment
Management Ltd., 1231801 Alberta Ltd., Advantage Unitholders and unitholders of
Ketch completed on June 23, 2006 whereby each trust unit of Ketch was exchanged
for 0.565 of a Trust Unit on a tax-deferred basis in Canada;
"DEBENTURES" means, collectively, the 6.50% Debentures, 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;
"ESCROW AGREEMENT" means the agreement entered into among Computershare Trust
Company of Canada, the Trust and various securityholders dated as of April 24,
2006;
"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;
"KETCH" means Ketch Resources Trust;
2
"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;
"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;
"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;
"OCTOBER 31, 2006 PROPOSALS" means the draft legislation released by the
Federal Minister of Finance on December 21, 2006 to implement proposals
originally announced on October 31, 2006 to amend the Tax Act to apply a
distribution tax on distributions from publicly-traded income trusts, which
proposals are described in more detail under the "RISK FACTORS - THE OCTOBER
31, 2006 PROPOSALS";
"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;
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"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;
"ROYALTY" means the 99% 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 royalty agreement entered into between AOG and us
dated as of June 24, 2006 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;
"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;
"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;
"TRUSTEE" means Computershare Trust Company of Canada or its successor or
successors as trustee under the Trust Indenture;
"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, December 13, 2005 and June 23, 2006, pursuant to which
Advantage was formed, as the same may be further amended, restated or replaced
from time to time;
"TRUST UNIT" or "UNIT" means a unit of the Trust, each unit representing an
equal undivided beneficial interest therein;
"TSX" means the Toronto Stock Exchange;
"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
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bbls barrels Mcf thousand cubic feet
Mbbls thousand barrels MMcf million cubic feet
MMbbls million barrels bcf billion cubic feet
NGLs natural gas liquids Mcf/d thousand cubic feet per day
stb stock tank barrels of oil MMcf/d million cubic feet per day
Mstb thousand stock tank barrels of oil m(3) cubic metres
MMboe million barrels of oil equivalent MMbtu million British Thermal Units
boe/d barrels of oil equivalent per day GJ Gigajoule
bbls/d barrels of oil per day
OTHER
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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
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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 a plan of
arrangement 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. Effective June 23, 2006, Advantage and Ketch completed the Arrangement
with the combined entity continuing under the name Advantage Energy Income
Fund. See "GENERAL DEVELOPMENT OF THE BUSINESS".
Prior to completion of the Arrangement, Advantage Investment Management Ltd.
("AIM") acted as manager of the Trust and of AOG. As part of the Arrangement,
Advantage internalized its external management structure and eliminated all
related fees by acquiring all of the outstanding shares of AIM for total
consideration of $44 million, paid through the issuance of 1,933,208 Trust
Units which have been placed in escrow and are releaseable as to one-third on
each of the first three anniversaries of the Arrangement.
Our head office, the head office of AOG and the registered office of AOG is
located at Suite 3100, 150 - 6th Avenue S.W., Calgary, Alberta, T2P 3Y7.
7
OUR ORGANIZATIONAL STRUCTURE
The following diagram sets forth our organizational structure as at the date
hereof.
[ORGANIZATION CHART OMITTED]
Notes:
(1) The Unitholders own 100% of the Trust.
(2) All our operations and management are conducted through AOG.
(3) Advantage receives regular monthly payments in accordance with the Royalty
Agreement as well as distributions and interest payments from the
Advantage Notes.
In accordance with the terms of the Trust Indenture, 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.
GENERAL DEVELOPMENT OF THE BUSINESS
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
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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 had an effective date of July 1, 2004.
On December 21, 2004, we announced the closing of our acquisition of Defiant
(the "DEFIANT ACQUISITION") by way of plan of arrangement under section 193 of
the ABCA. Pursuant to the plan of 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.
2006
On March 8, 2006, AOG elected to exercise its redemption right to redeem all of
its outstanding exchangeable shares. The redemption price per exchangeable
share was satisfied by delivering that number of Trust Units equal to the
exchange ratio of 1.22138 in effect on May 9, 2006. During 2006, we issued
127,014 Trust Units for the remaining AOG exchangeable shares.
On June 23, 2006 we completed the merger of Advantage and Ketch under the terms
of the Arrangement. The merger was accomplished through the exchange of each
trust unit of Ketch for 0.565 of a Trust Unit of Advantage and upon completion,
Advantage Unitholders owned approximately 65% of the combined trust and Ketch
unitholders owed approximately 35%.
We negotiated an increase to our credit facilities in June of 2006 and
currently have a $600 million credit facility agreement consisting of a $580
million extendible revolving loan facility and a $20 million operating loan
facility. The credit facilities are secured by a $1 billion floating charge
demand debenture, a general security agreement and a subordination agreement
covering all assets and cash flows.
On July 24, 2006 we announced that we adopted a Premium Distribution(TM),
Distribution Reinvestment and Optional Trust Unit Purchase Plan (the "PLAN").
The Plan commenced with the monthly cash distribution payable on August 15,
2006 to Unitholders who elected to participate and have their monthly
distribution obligation settled through the issuance of additional Trust Units
at 95% of the average market price (as defined in the Plan).
On August 1, 2006 we issued 7,500,000 Trust Units under a short-form prospectus
offering at $17.30 per Trust Unit. An additional 1,125,000 Trust Units were
issued on August 4, 2006 at $17.30 per Trust Unit upon full exercise of the
over-allotment option provided to the underwriters. The net proceeds of the
offering of approximately $141.4 million were used to pay down bank
indebtedness and to subsequently fund capital and general corporate
expenditures.
On December 21, 2006 the Federal Minister of Finance released draft legislation
to implement the October 31, 2006 Proposals pursuant to which, commencing
January 1, 2011 (provided we only experience "normal growth" and no "undue
expansion" before then) certain distributions which would have otherwise been
taxed as ordinary income generally will be characterized as dividends in
addition to being subject to tax at corporate rates at the Trust level. See
"RISK FACTORS - CHANGES IN LEGISLATION - THE OCTOBER 31, 2006 PROPOSALS".
9
RECENT DEVELOPMENTS
On January 19, 2007, we announced that the cash distribution to be paid on
February 15, 2007 to Unitholders of record on January 31, 2007 would be
adjusted to $0.15 per Trust Unit from the then current distribution rate of
$0.18 per Trust Unit and that the reduction in the monthly distribution rate
arose as a result of recent weakness in crude oil and natural gas prices which
have been driven by an abnormally mild winter heating season.
We have recently completed additional hedging to help protect the Trust's cash
flows in 2007. Overall, approximately 46% of our gas is now hedged for the 2007
calendar year at a floor of $7.51/mcf. For the first quarter of 2007, we have
secured approximately 58% of our net gas production at an $8.42/mcf floor. For
the months of April to October 2007, approximately 54% of our net gas
production is hedged at a floor of $7.08/mcf. We have also hedged approximately
14% of our 2007 net crude oil production at an average floor price of
US$65.00/bbl.
On January 19, 2007, we also announced that the Board of Directors of AOG
approved our 2007 capital expenditure budget at between $120 and $145 million.
On February 14, 2007 we issued 7,800,000 Trust Units under a short-form
prospectus offering at $12.80 per Trust Unit. An additional 800,000 Trust Units
were issued on March 7, 2007 at $12.80 per Trust Unit upon exercise of the
over-allotment option provided to the underwriters. The net proceeds of the
offering of approximately $105 million were used to pay down bank indebtedness
and to fund capital and general corporate expenditures.
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 2007 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 or
AOG purchase or authorize the purchase of any security, asset or
investment (collectively a "PROHIBITED INVESTMENT") on our behalf or
using any of our assets or property which are defined as "foreign
property" under subsection 206(1) of the INCOME TAX ACT (Canada) ("TAX
ACT") or are a "small business security" as that expression is used in
Part LI of the Regulations to the Tax Act or would result in us not being
considered either a "unit trust" or a "mutual fund trust" for purposes of
the Tax Act at the time such investment was made;
2. disposing of any part of the Trust Fund, including, without limitation,
any Permitted Investments;
3. acquiring the Royalty and other royalties in respect of Resource
Properties;
4. temporarily holding cash, and Permitted Investments (including
investments in AOG) for the purposes of paying Trust expenses and Trust
liabilities, paying amounts payable by us in connection with the
redemption of any Trust Units, and making distributions to Unitholders;
5. acquiring or investing in securities of AOG or any other subsidiary of
ours to fund the acquisition, development, exploitation and disposition
of all types of petroleum and natural gas related assets, including,
without limitation, facilities of any kind and whether effected through
the acquisition of assets or the acquisition of shares or other form of
ownership interest in any entity, the substantial majority of the assets
of which are comprised of like assets;
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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.
11
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, 2006. The effective date of the
Statement is December 31, 2006 and the preparation date of the Statement is
March 9, 2007.
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, 2006 contained in
a report of Sproule dated March 9, 2007 (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, 2006
CONSTANT PRICES AND COSTS
Reserves
----------------------------------------------------------------------------------------------
Light And Medium Oil Heavy Oil Natural Gas Natural Gas Liquids
-------------------- ------------------- --------------------- --------------------
Gross Net Gross Net Gross Net Gross Net
Reserves Category (Mbbl) (Mbbl) (Mbbl) (Mbbl) (MMcf) (MMcf) (Mbbl) (Mbbl)
- ----------------- -------- -------- -------- -------- -------- -------- -------- --------
Proved
Developed Producing 16,225 14,393 1,912 1,712 251,561 205,905 6,242 4,588
Developed Non-Producing 477 397 0 0 11,479 9,485 241 179
Undeveloped 3,527 2,919 0 0 27,861 22,361 881 653
-------- -------- -------- -------- -------- -------- -------- --------
Total Proved 20,229 17,710 1,912 1,712 290,901 237,751 7,364 5,420
Probable 13,789 11,804 697 605 145,498 116,708 3,830 2,789
-------- -------- -------- -------- -------- -------- -------- --------
Total Proved Plus Probable 34,018 29,514 2,609 2,317 436,399 354,459 11,194 8,210
======== ======== ======== ======== ======== ======== ======== ========
12
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 1,707,666 1,241,355 1,000,555 850,715 746,990 1,707,666 1,241,355 1,000,555 850,715 746,990
--------- --------- --------- --------- --------- --------- --------- --------- --------- ---------
Producing
Developed 55,498 44,779 37,293 31,804 27,622 55,498 44,779 37,293 31,804 27,622
Non-Producing
Undeveloped 171,290 125,900 91,452 66,341 47,768 171,290 125,900 91,452 66,341 47,768
Total Proved 1,934,455 1,412,034 1,129,300 948,860 822,380 1,934,455 1,412,034 1,129,300 948,860 822,380
Probable 1,079,108 612,513 409,724 298,503 228,844 1,079,108 612,513 409,724 298,503 228,844
Total Proved
Plus Probable 3,013,563 2,024,547 1,539,024 1,247,364 1,051,223 3,013,563 2,024,547 1,539,024 1,247,364 1,051,223
========= ========= ========= ========= ========= ========= ========= ========= ========= =========
TOTAL FUTURE NET REVENUE
(UNDISCOUNTED)
as of December 31, 2006
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 3,550,949 555,622 894,772 120,786 39,438 5,878 1,934,453 0 1,934,453
Proved Plus
Probable 5,545,136 903,002 1,359,142 216,628 43,331 9,472 3,013,563 0 3,013,563
FUTURE NET REVENUE
BY PRODUCTION GROUP
as of December 31, 2006
CONSTANT PRICES AND COSTS
Future Net Revenue Before
Income Taxes (Discounted At
10%/Year)
Reserves Category Production Group ($000's)
- ------------------------------------------------------------------------------------------------------------------------------
Proved Light and Medium Crude Oil (including solution gas and other
by-products) 476,825
Heavy Oil (including solution gas and other by-products) 26,750
Natural Gas (including by-products but excluding solution gas
from oil wells) 606,603
Proved Plus Probable Light and Medium Crude Oil (including solution gas and other
by-products) 691,258
Heavy Oil (including solution gas and other by-products) 35,245
Natural Gas (including by-products but excluding solution gas
from oil wells) 792,053
13
RESERVES DATA (FORECAST PRICES AND COSTS)
SUMMARY OF OIL AND GAS RESERVES
AND NET PRESENT VALUES OF FUTURE NET REVENUE
as of December 31, 2006
FORECAST PRICES AND COSTS
Reserves
----------------------------------------------------------------------------------------------
Light And Medium Oil Heavy Oil Natural Gas Natural Gas Liquids
-------------------- ------------------- --------------------- --------------------
Gross Net Gross Net Gross Net Gross Net
Reserves Category (Mbbl) (Mbbl) (Mbbl) (Mbbl) (MMcf) (MMcf) (Mbbl) (Mbbl)
- ----------------- -------- -------- -------- -------- -------- -------- -------- --------
Proved
Developed Producing 15,949 14,136 1,908 1,709 253,286 207,212 6,252 4,599
Developed Non-Producing 474 394 0 0 11,523 9,526 241 179
Undeveloped 3,513 2,907 0 0 27,970 22,464 881 654
Total Proved 19,935 17,437 1,908 1,709 292,779 239,200 7,375 5,433
Probable 13,586 11,615 688 596 146,566 117,581 3,833 2,795
Total Proved Plus Probable 33,521 29,053 2,596 2,305 439,345 356,781 11,208 8,227
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 2,110,371 1,495,671 1,200,133 1,022,394 901,119 2,110,371 1,495,671 1,200,133 1,022,394 901,119
Producing
Developed Non- 70,588 57,401 48,211 41,470 36,325 70,588 57,401 48,211 41,470 36,325
Producing
Undeveloped 184,665 146,958 111,997 85,222 65,030 184,665 146,958 111,997 85,222 65,030
--------- --------- --------- --------- --------- --------- --------- --------- --------- ---------
Total Proved 2,365,623 1,700,030 1,360,341 1,149,085 1,002,475 2,365,623 1,700,030 1,360,341 1,149,085 1,002,475
Probable 1,395,502 745,205 489,733 356,741 275,470 1,395,502 745,205 489,733 356,741 275,470
--------- --------- --------- --------- --------- --------- --------- --------- --------- ---------
Total Proved
Plus Probable 3,761,127 2,445,236 1,850,073 1,505,824 1,277,946 3,761,127 2,445,236 1,850,073 1,505,824 1,277,946
========= ========= ========= ========= ========= ========= ========= ========= ========= =========
TOTAL FUTURE NET REVENUE
(UNDISCOUNTED)
as of December 31, 2006
FORECAST 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 4,426,050 720,559 1,152,517 123,464 58,212 5,675 2,365,623 0 2,365,623
Proved Plus 7,108,931 1,195,238 1,848,496 223,800 70,818 9,453 3,761,127 0 3,761,127
Probable
14
FUTURE NET REVENUE
BY PRODUCTION GROUP
as of December 31, 2006
FORECAST PRICES AND COSTS
Future Net Revenue Before
Income Taxes (Discounted At
10%/Year)
Reserves Category Production Group ($000's)
- ------------------------------------------------------------------------------------------------------------------------------
Proved Light and Medium Crude Oil (including solution gas and other
by-products) 482,772
Heavy Oil (including solution gas and other by-products) 27,612
Natural Gas (including by-products but excluding solution gas
from oil wells) 830,835
Proved Plus Probable Light and Medium Crude Oil (including solution gas and other
by-products) 695,661
Heavy Oil (including solution gas and other by-products) 36,151
Natural Gas (including by-products but excluding solution gas
from oil wells) 1,097,794
PRICING ASSUMPTIONS
The following tables set forth the benchmark reference prices, as at December
31, 2006, reflected in the Reserves Data. These price assumptions were provided
to us by Sproule and were Sproule's then current forecasts at the date of the
Sproule Report.
SUMMARY OF PRICING ASSUMPTIONS(1)
as of December 31, 2006
CONSTANT PRICES AND COSTS
Oil
------------------------------------------------
Edmonton Hardisty Natural Gas
WTI Par Price Heavy Cromer Medium AECO Gas Pentanes Propanes
Cushing 40(degree) 12(degree) 29.3(degree) Price Plus Fob Butanes Fob Fob Field Exchange
Oklahoma API API API ($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/$Cdn)
- ------------- --------- ---------- ---------- ---------- ----------- ---------- ---------- ---------- ----------
Historical (3)
2006 61.05 67.59 40.06 62.45 6.13 71.51 54.00 42.06 0.858
Notes:
(1) This summary table identifies benchmark reference pricing schedules that
might apply to a REPORTING ISSUER.
(2) The exchange rate used to generate the benchmark reference prices in this
table.
(3) As at December 31.
15
SUMMARY OF PRICING AND INFLATION RATE ASSUMPTIONS(1)
as of December 31, 2006
FORECAST PRICES AND COSTS
Oil
------------------------------------------------
Natural Pentanes Butantes Propoane
Edmonton Hardisty Cromer Gas(1) Plus Fob Fob Fob
WTI Par Price Heavy Medium AECO Gas Field Field Field
Cushing 40(degree) 12(degree) 29.3(degree) Price Gate Gate Gate Inflation Exchange
Oklahoma API API API ($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
2007 65.73 74.10 42.98 63.72 7.72 75.88 55.23 43.94 5.0 0.87
2008 68.82 77.62 45.02 66.75 8.59 79.49 57.85 46.03 4.0 0.87
2009 62.42 70.25 40.74 60.41 7.74 71.94 52.36 41.66 3.0 0.87
2010 58.37 65.56 38.03 56.38 7.55 67.14 48.87 38.88 2.0 0.87
2011 55.20 61.90 35.90 53.24 7.72 63.40 46.14 36.71 2.0 0.87
2012 56.31 63.15 36.63 54.31 7.85 64.67 47.07 37.45 2.0 0.87
2013 57.43 64.42 37.36 55.40 7.99 65.98 48.02 38.21 2.0 0.87
2014 58.58 65.72 38.12 56.52 8.12 67.30 48.98 38.97 2.0 0.87
2015 59.75 67.04 38.88 57.65 8.26 68.66 49.97 39.76 2.0 0.87
Thereafter +2%/yr +2%/yr +2%/yr +2%/yr +2%/yr +2%/yr +2%/yr +2%/yr +2%/yr 0.87
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, 2006, were $6.86/Mcf for natural gas, $64.34/bbl for
crude oil, $55.81/bbl for natural gas liquids.
16
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 Proved Probable Probable Proved Probable Probable
FACTORS (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl)
- ---------------------- ------ -------- -------- ------ -------- -------- ------ -------- ---------
December 31, 2005 13,693 10,124 23,817 1,539 835 2,374 2,772 1,573 4,345
------ ------ ------ ------ ------ ------ ------ ------ ------
Extensions 33 65 98 0 0 0 127 61 188
Improved Recovery 1,931 1,629 3,560 144 58 202 201 167 368
Technical Revisions 1,758 -313 1,445 304 -272 32 158 -37 121
Discoveries 44 34 78 0 0 0 0 0 0
Acquisitions 2,044 366 2,410 0 0 0 2,711 1,066 3,777
Dispositions 0 0 0 0 0 0 0. 0 0
Economic Factors -137 -101 -238 -31 -16 -47 -69 -40 -109
Production -1,656 0 -1,656 -244 0 -244 -480 0 -480
------ ------ ------ ------ ------ ------ ------ ------ ------
December 31, 2006 17,710 11,804 29,514 1,712 605 2,317 5,420 2,790 8,210
====== ====== ====== ====== ====== ====== ====== ====== ======
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, 2005 165,911 72,030 237,941 45,656 24,537 70,193
Extensions 5,126 3,465 8,591 1,014 704 1,718
Improved Recovery 3,629 2,806 6,435 2,881 2,321 5,202
Technical Revisions 2,620 -1,270 1,349 2,657 -834 1,823
Discoveries 4 7 11 45 35 80
Acquisitions 93,124 41,608 134,732 20,276 8,366 28,642
Dispositions -359 -137 -496 -60 -23 -83
Economic Factors -4,148 -1,800 -5,948 -928 -457 -1,385
Production -28,156 0 -28,156 -7,073 0 -7,073
-------- -------- -------- -------- -------- --------
December 31, 2006 237,751 116,708 354,459 64,468 34,649 99,117
======= ======= ======= ====== ====== ======
17
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 Proved Probable Probable Proved Probable Probable
FACTORS (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl)
- ---------------------- ------ -------- -------- ------ -------- -------- ------ -------- ---------
December 31, 2005 15,558 11,913 27,471 1,720 957 2,677 3,747 2,206 5,953
Extensions 40 78 118 0 0 0 174 84 258
Improved Recovery 2,327 1,962 4,289 167 73 240 275 229 504
Technical Revisions 1,747 -626 1,121 342 -326 16 156 -102 54
Discoveries 53 41 94 0 0 0 0 0 0
Acquisitions 2,455 410 2,865 0 0 0 3,741 1,451 5,192
Dispositions 0 0 0 0 0 0 0 0 0
Economic Factors -249 -191 -440 -27 -16 -43 -60 -35 -95
Production -1,996 0 -1,996 -294 0 -294 -658 0 -658
------- ------- -------- ------ ------- ------- ------ ------ ------
December 31, 2006 19,935 13,586 33,521 1,908 688 2,596 7,375 3,833 11,208
======= ======= ======== ====== ======= ======= ====== ====== ======
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, 2005 195,534 88,013 283,547 53,613 29,745 83,358
Extensions 6,420 4,340 10,760 1,284 885 2,169
Improved Recovery 4,536 3,508 8,044 3,525 2,849 6,374
Technical Revisions 4,930 -1,991 2,939 3,068 -1,388 1,680
Discoveries 5 9 14 54 42 96
Acquisitions 119,212 54,244 173,456 26,065 10,901 36,966
Dispositions -392 -149 -541 -65 -25 -90
Economic Factors -3,129 -1,408 -4,537 -858 -476 -1,334
Production -34,337 0 -34,337 -8,670 0 -8,670
-------- ------- ------- ------- -------- --------
December 31, 2006 292,779 146,566 439,345 78,016 42,533 120,549
======== ======= ======= ======= ======== ========
18
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 2006
- ------------------------------------------------------------------------------------------- --------------
Estimated Future Net Revenue at Beginning of Year 1,216,240
Sales and Transfers of Oil and Gas Produced, Net of Production Costs and Royalties -255,063
Net Change in Prices, Production Costs and Royalties Related to Future Production -385,426
Actual Development Costs Incurred During the Period 50,135
Changes in Estimated Future Development Costs -81,336
Extensions and Improved Recovery 76,549
Discoveries 2,148
Acquisitions of Reserves 374,141
Dispositions of Reserves -1,874
Net Change Resulting from Revisions in Quantity Estimates 12,162
Accretion of Discount 121,624
Net Change in Income Taxes 0
-
Estimated Future Net Revenue at End of Year 1,129,300
=========
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, first attributed to us in each of
the following financial years.
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
2006 1,047 0 10,547 576 3,381
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
2006 748 0 18,049 572 4,328
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.
19
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)
----------------------------------------------------------- ------------------------------
Proved Reserves Proved Plus Probable Reserves Proved Reserves
----------------------- ---------------------------- ------------------------------
Year 0% 10% 0% 10% 0% 10%
- ------------------- ------- ------- ------- ------- ------- -------
2007 80,717 77,216 118,930 114,145 80,518 77,013
2008 33,247 28,720 73,086 63,438 31,663 27,370
2009 8,265 6,433 13,905 10,996 7,568 5,892
2010 337 247 9,803 7,201 300 219
Additional years 898 477 8,076 4,850 737 405
Total 123,464 113,093 223,800 200,630 120,786 110,899
======= ======= ======= ======= ======= =======
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 four
western Canadian provinces, with the majority of our properties concentrated in
Alberta and northeastern British Columbia and in southeast Saskatchewan. These
properties produce from a variety of various aged geological formations and
reservoirs. We operate over 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 27% of our production and 39% of
our reserves. A further 73% of production and 61% of reserves are natural gas.
Rates referenced in the following property descriptions are as of December 31,
2006 unless otherwise noted and reserves quoted are as reported in the Sproule
Report to December 31, 2006.
MARTIN CREEK, BRITISH COLUMBIA
The Martin Creek property is located approximately 100 kilometers northwest of
Fort St. John, British Columbia and has been producing since 1978. The property
is operated with an average 76% overall working interest. This property is in
the winter drilling area which requires all drilling, completion and tie in
activities to occur essentially between January 1st and the end of March each
season. In the last winter program, January 2006, 16 wells averaging 80%
working interest were drilled across the property. These wells targeted
multiple zones within the Cretaceous including the Bluesky and Gething
Formations as well as Triassic reservoirs in the Halfway, Charlie Lake and
Baldonnel Formations. Ten of the 16 wells were placed on production and these
averaged 6.5 MMcf/d in 2006. Much of the success of the 2006 program was
focused in the northern part or the Black - Conroy area of the property.
Following up on the 2006 success, 17 wells were drilled in the 2007 program
exclusively within Black - Conroy, targeting the Baldonnel and Bluesky
Formations which occur at moderate depths between 800 to 1,300 meters. Fifteen
of the 17 wells were cased and completed. Eleven have been tied in for
production. These wells are stimulated with propped sand fracs in the case of
the Bluesky sandstones or with acid squeezes and/or fracs in the case of the
Baldonnel carbonates. Tested initial capability from the 2007 winter program is
exceeding 12 MMcf/d. Three MMcf/d of new compression was installed during March
2007. With this addition, about half of the new volumes will be able to produce
immediately with the remainder coming on stream as pipeline and facility space
20
becomes free with natural production decline. As a result it is expected that
we should be able to keep production flat until well into 2008. Total
production from the greater Martin Creek, including the Black - Conroy areas is
14.1 MMcf/d. Additional facilities, pipeline and compression options will be
scoped for next year to handle subsequent anticipated volumes from current and
future drilling programs. The successful 2007 program has set up a great number
of locations available for a 2008 drilling program which should be similar in
size and expectations to the one just executed. In addition we own a 100%
working interest ownership in key facilities, including five compressor
stations, one 30 mmcf/d plant and over 254 kilometers of pipelines, which gives
us a dominant infrastructure position in this portion of British Columbia.
Sproule evaluated our proved reserves in the area and assigned 32.6 bcf of
natural gas and 656 Mbbls of crude oil and NGLs. In addition, 22.9 bcf of
probable natural gas reserves and 478 Mbbls of probable crude oil and NGLs
reserves have been assigned to this property.
STODDART/NORTH PINE, BRITISH COLUMBIA
The Stoddart/North Pine area lies just 8 kilometers west of the Town of Fort
St. John in northeast British Columbia. This area is within the agricultural
area and is accessible year round. 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 3.0 MMcf/d of natural gas and 174 Bbls/d of light oil and NGLs.
Sproule evaluated our proved reserves in the area and assigned 12.5 bcf of
natural gas and 900 Mbbls of crude oil and NGLs. In addition, 2.9 bcf of
probable natural gas reserves and 175 Mbbls of probable crude oil and NGL
reserves have been assigned to this property.
FONTAS, ALBERTA
The Fontas property is situated in the northwestern corner of Alberta, along
the BC border just south of the Rainbow-Zama oilfields. Fontas is a natural gas
property which produces principally from Mississippian aged reservoirs in the
Debolt, Shunda and Elkton Formations. Gas is trapped as these reservoirs are
truncated and preserved beneath Cretaceous silts and shales. In addition
Cretaceous Detrital Formation sand channels which were cut into the older
Mississippian rock have formed natural gas reservoirs. We operate this winter
only access property and have an average 60% working interest. We operate six
strategically located gas processing facilities and over 200 kilometers of gas
gathering pipelines. Current production from this area is 7.5 Mmcf/d. In the
January 2006 winter season, 13 wells were drilled and cased. Nine of these are
on production. A winter drilling program was not implemented in 2007, however,
drilling plans are being evaluated for a 2008 winter program
Sproule evaluated our proved reserves in the area and assigned 14.7 bcf of
natural gas. In addition, 6.8 bcf of probable natural gas reserves have been
assigned to this property.
PEACE RIVER ARCH AREA, ALBERTA
WORSLEY/CECIL - These properties are located 150 kilometers north of the City
of Grande Prairie, Alberta. The Worsley property is complex geologically with
numerous structural and stratigraphic reservoirs ranging from 600 meters to
2,200 meters. The principle reservoirs are the Devonian, Wabamun Formation,
Mississippian Kiskatinaw and Debolt Formations and Cretaceous Bluesky and
Gething Formations. Often these pools are stacked over deep seated structural
features which provide multiple trapping opportunities up the stratigraphic
column. These structures must be controlled seismically before drilling. We
hold varying interests in approximately 35 sections of land in this area,
generally in excess of 50%. Nine wells were drilled on this property in 2006.
Seven are on production, one was abandoned and one is suspended.
The Cecil area consists of varying interests in 16 sections of land adjacent to
Worsley, again with multi-zone, shallow and medium drill depth targets. The
principal producing pool is the Charlie Lake JJ Doig Formation pool. We have a
40% working interest in 2 producing wells making collectively making 750 boe/d
of primarily 36o API gravity crude oil. We
21
hold a 100% working interest in the seven MMcf/d capacity gas processing
facility in Worsley and 10% working interest in a 50 MMcf/d gas processing
facility at Cecil.
Sproule evaluated our proved reserves in the Cecil/Worsley area and assigned 4
bcf of natural gas and 335 Mbbls of crude oil and NGLs. In addition, 5.2 bcf of
probable natural gas reserves and 392 Mbbls of probable crude oil and NGLs
reserves have been assigned to this property.
BOUNDARY LAKE - This property lies immediately west of the Worsley property
just east of the BC/Alberta border. The property consists of 14 sections of
land (variable but generally greater than 40% working interest.) In February
2006 one well was successfully drilled and completed into the Triassic, Halfway
Formation. This well has been flow lined in but is awaiting EUB approval for
startup of facilities to commence producing. Current production from the
Boundary Lake property is 0.4 MMcf/d, with an anticipated 2.5 MMcf/d gross
(facilities restricted) waiting to come on stream from the new wells.
Sproule evaluated our proved reserves in the area and assigned 2.2 bcf of
natural gas and 88 Mbbls of crude oil and NGLs. In addition, 1.1 bcf of
probable natural gas reserves and 27 Mbbls of probable crude oil and NGL
reserves have been assigned to this 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 Triassic "A" Unit, Sunset B, and Valleyview-Stump.
All three properties produce from the Triassic Montney Formation.
SUNSET A - We have a 70% working interest and operates the Sunset Triassic "A"
Unit. Production from the unit is predominantly (32oAPI) oil and has a forty
year production history with a very stable performance and very low decline,
indicating that there is a lot more oil to be recovered. In 2005, two wells
were drilled which evaluated the viability of additional infill drilling in the
pool. These wells came onstream at an average rate of 75 bbls/d per well,
similar to that in the original wells. An additional 14 oil wells and an
injector were added in 2006, with similar results. Current net production from
the Sunset A unit is 640 bbls/d of crude oil and 750 Mcf/d of natural gas. An
additional 14 locations have been identified with 4 budgeted for drilling in
2007.
SUNSET B - Production from this Montney reservoir is predominantly natural gas
although there is a thin oil (32oAPI) column. We have a 100% interest in this
pool. We own 100% of a sour gas processing plant and gathering system with
throughput capacity of 12 MMcf/d. Associated gas from Sunset A and from
Valleyview is gathered and streams through this facility. Current production
from the Sunset B pool is 1.6 MMcf/d and 98 Bbls/d. No wells were drilled in
2006.
VALLEYVIEW - This Montney gas pool is connected to the Sunset B gas processing
plant by a twelve kilometer pipeline. We have a 93% average working interest in
the pool. One new well was drilled in 2006 and is currently on production.
Production from this property is 1.9 MMcf/d.
For the three properties, Sunset A, Sunset B and Valleyview, the Sproule Report
assigns 14.2 bcf of proven natural gas reserves and 2,287 Mbbls of proven crude
oil and NGL reserves to this property. In addition, 16.9 bcf of probable
natural gas reserves and 2,525 Mbbls of probable crude oil and NGL reserves
have been assigned to this property.
NEVIS, ALBERTA
The Nevis property is situated 60 km east of Red Deer. Nevis is an operated
property consisting of approximately 50 sections of land with an average
working interest over 90%. This property produces natural gas from numerous
shallow depth horizons (400 to 800 m) including the Horseshoe Canyon, Edmonton,
Belly River and Viking formations. Oil and natural gas is produced from the
slightly deeper reservoirs (1,200 m) of the Glauconite, Ostacode and Ellerslie
formations within the Mannville Group. The main zone of interest however, is an
oil and gas reservoir which occurs at 1,600 meters in Devonian aged carbonates
of the Big Valley Member of the Wabamun Formation. Development of the sweet oil
from this high porosity/low permeability reservoir is being accomplished by
horizontal drilling. Crude oil quality ranges between 35o and 42o API. In 2006,
through two separate land deals, we added approximately 15 sections of land
with Wabamun rights
22
into the property. Drilling in 2007 will focus on areas on these new lands on
the west side of the Red Deer River valley. Additional facilities and
compression is planned to accommodate expected volumes from drilling on the
west side. Oil on the east side is collected at central facilities and trucked
to market. The gas is gathered through company owned pipelines and delivered to
third party midstream for final processing and sale. Currently, the property is
being reviewed to scope the potential for either waterflood or C02 secondary
recovery. In 2006, 13 horizontal wells were drilled into the Wabamun formation
and are all currently producing. The average first month initial production
from these wells is 180 Boe/d. An additional 6 shallow vertical wells were
drilled which for Horseshoe Canyon coals and Edmonton and Belly River sands.
(The CBM on this property is discussed further under the coal bed Methane
section later in this discussion.) Current production from all zones on this
property is 2,445 Boe/d.
The Sproule Report assigns 20.2 bcf of proven natural gas reserves and 4,256
Mbbls of proven crude oil and NGL reserves to this property. In addition, 7.9
bcf of probable natural gas reserves and 1,573 Mbbls of probable crude oil and
NGL reserves have been assigned to this property.
GOLDEN SPIKE, ALBERTA
The Golden Spike property is located 10 kilometers southwest of Edmonton,
Alberta. This area has been a historical oil producing area since the discovery
of oil in the Devonian Leduc reefs in the 1940's. Advantage is the operator and
holds a 100% Working Interest in all zones above the Leduc Formation. Several
wellbores which were originally used for deeper Leduc production, are now used
for the uphole productive zones in the Devonian Nisku and Wabamun carbonates
and Cretaceous Ellerslie, Glauconite, Viking and Belly River sandstones which
are draped over the deeper Leduc structure. The production is primarily gas
prone with some light oil opportunities. The area has well established sweet
and sour gas processing capacity at competitive midstream operated facilities.
Current net production from this property is 418 Boe/d from six wells.
The Sproule Report assigns 4.4 bcf of proven natural gas reserves and 304 Mbbls
of proven crude oil and NGL reserves to this property. In addition, 1.0 bcf of
probable natural gas reserves and 67 Mbbls of probable crude oil and NGL
reserves have been assigned to this property.
WAINWRIGHT, ALBERTA
The Wainwright property is located approximately 175 kilometers 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 3.4 Mmcf/d natural gas. 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. No drilling has occurred
on this property since 2003. The Sproule Report assigns 7.4 bcf of proven
natural gas reserves and 4.4 Mbbls of proven crude oil and NGL reserves to this
property. In addition, 1.8 bcf of probable natural gas reserves and 0.2 Mbbls
of probable crude oil and NGL reserves have been assigned to this property.
SKARO, ALBERTA
The Skaro property is located 50 kilometers northeast of Edmonton, Alberta. We
operate 11 sections of land with 100% working interest. Production in this area
is 25o API gravity oil at depths less than 900 meters. The Skaro property is
positioned in a productive Cretaceous Ellerslie channel trend offset by
numerous commercial, multi-well oil pools. The Skaro property has the potential
for horizontal delineation development drilling through and utilization of
existing 3-D seismic data for continued new pool exploration. Current net
production from this property is 162 Boe/d.
The Sproule Report assigns 273 Mmcf of proven natural gas reserves and 33 Mbbls
of proven crude oil and NGL reserves to this property. In addition, 225 Mmcf of
probable natural gas reserves and 32 Mbbls of probable crude oil and NGL
reserves have been assigned to this property.
23
COAL BED METHANE (CBM) PROJECTS
We hold high working interest in several properties along the main coal bed
methane fairway of the Horseshoe Canyon Formation which extends in a wide
geographical belt straddling the Queen Elizabeth 2 Highway between Calgary and
Edmonton. The Horseshoe Canyon Formation bears between 10 and 20 individual
coal seams which are fracture stimulated with nitrogen and produce "dry" (no
associated water) natural gas. Primary spacing allows for four wells per
section in this area.
NORTH CHIGWELL CBM
We entered into a 50% joint venture with a major CBM company and during 2006,
28 wells were drilled, completed and tied into a dedicated low pressure
gathering system. Central compression and a major sales line was constructed
which are owned 50%. Current production is 1.7 MMcf/d net to Advantage or about
120 Mcf/d gross per well. After suitable evaluation of this production, this
property has the potential by way of EUB application to be downspaced to eight
wells per section and double the current well count.
CHIGWELL CBM
Immediately south of the current North Chigwell CBM joint venture, we hold an
approximate 50% working interest and operate in a similar sized lock of land.
The synergies provided with the existing facilities and sales line provides a
great opportunity to exploit this resource for significant cost reductions from
the initial program. Production at North Chigwell will be monitored and along
with a favorable gas price window, this property will be considered for
development. No budget dollars have been allocated to this property in 2007.
NEVIS CBM
We hold rights to the Horseshoe Canyon in seven sections (average 47% working
interest) of operated lands as well as three non-operated (40%) lands. We have
drilled and completed one CBM well on each of six sections of land and has
recently installed wellhead compression to allow the wells to produce into our
existing higher pressure conventional gathering system. Although not enough
time has passed to suitably observe the specific individual well performance it
is expected that, based on a statistical average of 200 adjacent third party
CBM wells, rates will be significantly higher than at Chigwell. Initial rates
of between 200 and 250 Mcf/d are expected. Production from the wells will be
observed in 2007 and given favorable production rates and gas prices, a 2008
drilling program could proceed. (Reserves assigned are included in the overall
Nevis summary discussed earlier in this section.)
CAMROSE CBM
The Camrose property is located 25 kilometers southeast of Edmonton, Alberta.
We hold a 100% working interest in 22 sections of land. This property is at the
north end of the Horseshoe Canyon fairway. As such per well rates are expected
only to be in the 75 Mcf/d range. The lands have been farmed-out to a third
party that will allow us to participate on a well by well basis based on
drilling results.
CBM RESERVES:
The Sproule Report assigns 5.8 bcf of proven natural gas reserves and 4.9 bcf
of probable natural gas reserves to the CBM properties (including those
assigned separately at Nevis).
WESTEROSE, ALBERTA
The Westerose property is approximately 60 kilometers southwest of Edmonton,
Alberta. Westerose is and oil and gas property with production from various
Cretaceous reservoirs but produces principally from several pools associated
with the erosional subcrop edge of the Mississippian Banff Formation. The
primary pool is the Banff "C" Oil Unit. We also operate five compressor
stations and 80 kilometers of pipeline gathering facilities that are connected
to the Keyspan Rimbey gas plant.
24
WESTEROSE SOUTH BANFF "C" OIL UNIT. - We hold a 52% Working Interest in Banff
"C" Unit, which has an estimated 28.7 MMbbls of original oil in place.
Cumulative production for the unit was 3.7 MMbbls (13% recovery of original oil
in place) at December 31, 2006. Sproule has assigned a proved plus probable
recovery factor of 35%. The reservoir in the Banff "C" Unit is a dolomitized
carbonate that is conducive to secondary recovery through waterflooding based
on analogous pools and engineering studies completed on the unit. Waterflood
operations commenced in the Banff "C" Oil Unit during 2003 and continued
through 2006. Benefits of the waterflood are expected to be realized as we
continue to inject water and slowly build up reservoir pressure. Our current
voidage replacement ration is 1.3. In the fourth quarter of 2006 we drilled
three wells into the Banff "C" unit. The initial production rate from the three
new wells is 350 Boe/d. We have plans to drill an additional two wells plus an
additional water injector in 2007.
The Sproule Report assigns 11.2 bcf of proven natural gas reserves and 3,061
Mbbls of proven crude oil and NGL reserves to the greater Westerose area. In
addition, 3.7 bcf of probable natural gas reserves and 1,619 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 (37 degrees API) with associated gas.
Production at the end of 2006 is approximately 330 Boe/d. This property was
acquired in December 2004 and 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 have been involved in extensive
discussion with the EUB and public stakeholders throughout the last two years
to rectify and resolve this issue which is expected in 2007. The property will
continue to produce from single well batteries under maximum rate limitation
allowables until the issues are resolved.
Sproule evaluated our proved reserves in the Chip Lake area and assigned 1.6
bcf of natural gas and 1,766 Mbbls of crude oil and NGLs. Probable reserves in
this area were evaluated by Sproule at 1.7 bcf of natural gas and 2,580 Mbbls
of crude oil and NGLs.
OPEN LAKE (WILLESDEN GREEN)
The Willesden Green property is located approximately 35 km north of the Town
of Rocky Mountain House. We operate and have in excess of 90% working interest.
Oil and natural gas production is multi-zoned from various Cretaceous and
Jurassic reservoirs including the Rock Creek, Ellerslie, Ostacode, Viking,
Second White Specks and Belly River Formations. We drilled one well targeting
the Glauconite and Rock Creek in 2006. This well was placed onstream in the
fourth quarter of 2006 and a follow up well has been drilled and is being
completed in the first quarter of 2007. In addition three wells were drilled at
no cost to Advantage down to the Jurassic Rock Creek Formation on expiring
lands. These wells have tested 14 Mmcf/d at very low draw downs. Tie in of
these wells is underway and production is expected to commence shortly. We will
receive an overriding royalty of 15% on natural gas reserves and we have
exposed no capital on the project. Our net production from all zones in this
property is 3.7 Mmcf/d natural gas and 475 bbls/d NGLs and crude oil.
Sproule evaluated our proved reserves in the Willesden Green area and assigned
6.0 bcf of natural gas and 786 Mbbls of crude oil and NGLs. Probable reserves
in this area were evaluated by Sproule at 2.3 bcf of natural gas and 343 Mbbls
of crude oil and NGLs.
FERRIER/ O'CHIESE, ALBERTA
The Ferrier and O'Chiese areas lie between 75 and 100 kilometers southwest of
Edmonton, Alberta. The 20 sections of land in these properties are non-operated
with an average working interest of around 40%. This area has high yield
natural gas liquids from gas production which occurs at drill depths of 2,000
meters to 3,000 meters within the porous carbonates of the Mississippian aged
Elkton and Shunda formations, but principally from the Jurassic Rock Creek and
Cretaceous Ellerslie Formations. Some additional production occurs in shallower
Cretaceous aged clastic reservoirs as well. In 2006 Advantage participated in
the drilling of 5 wells in these areas. Our net production from these
properties is 2.4 Mmcf/d of natural gas and 76 Bbls/d of NGLs and crude oil.
25
Sproule evaluated our proved reserves in the Ferrier/O'Chiese area and assigned
2.5 bcf of natural gas and 72 Mbbls of crude oil and NGLs. Probable reserves in
this area were evaluated by Sproule at 0.8 bcf of natural gas and 30 Mbbls of
crude oil and NGLs.
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. Major facility interests include a 25.7%
working interest in the West Pembina Sour Gas Plant and a 31.6% working
interest in the Brazeau River Gas Plant. Current net production from the
property is 3.7 MMcf/d natural gas and 305 bbls/d NGLs and crude oil.
Sproule evaluated our proved reserves in the Brazeau River area and assigned
2.6 bcf of natural gas and 348 Mbbls of crude oil and NGLs. Probable reserves
in this area were evaluated by Sproule at 2.6 bcf of natural gas and 264 Mbbls
of crude oil and NGLs.
LOOKOUT BUTTE, ALBERTA
The Lookout Butte property is located approximately 90 kilometers southwest of
Lethbridge, Alberta. Production occurs primarily from the Mississippian Rundle
Formation where natural gas has been trapped in a foothills overthrust
structure in front of Waterton Park. We have a 100% working interest in the
Rundle gas production. Production began in 1963 and production decline is very
shallow at approximately 12% per year. A recently drilled well (2004) in the
southern portion of the pool indicates the potential for significant undrained
reserves and additional prospective locations targeting the Rundle carbonates.
The property includes a 100% operated working interest plant and associated gas
gathering system which dehydrates the gas before final processing at Shell's
Waterton gas plant. In 2006 a former deep producer was re-completed uphole at
3,250 meters in Cretaceous Mannville Formation sandstones and commenced
production in May 2006 and has averaged145 boe/d since. We have a 50% working
interest in the Mannville. In some of the older wells, the Cretaceous Cardium
sands tested gas rates as high as 1MMcf/d from the shallowest of up to six
overthrust repeats of the Cardium zone per well. A new well drilled for the
Cardium in Q1 2007 is awaiting completion. We have a 50% working interest in
the Cardium intervals. Working interest production from this property from all
zones is 5.8 MMcf/d of natural gas and 180 bbls/d of NGLs.
Sproule evaluated our proved reserves at Lookout Butte and assigned 31.5 bcf of
natural gas and 1,665 Mbbls of crude oil and NGLs. Probable reserves in this
area were evaluated by Sproule at 12 bcf of natural gas and 632 Mbbls of crude
oil and NGLs.
SOUTHEAST SASKATCHEWAN
This area consists of a host of individual properties within the Williston
Sedimentary Basin in the southeast corner of Saskatchewan. We operate the
majority of this production at 100%. Production at the major properties comes
principally from the Ordovician Red River Formation at Midale, Hardy and
Froude, Devonian Winnipegosis Formation at Steelman and from Mississippian
Midale/Frobisher Formations at Steelman, Weyburn and Workman. In 2006, we
drilled two vertical wells at Pinto which have resulted in Midale and Frobisher
oil wells. Also one vertical Winnipegosis oil well was added to the Steelman
property. One well at each of Hardy, Midale and Froude was re-entered to add an
additional horizontal leg or sidetrack. The Workman property is in the process
of being unitized and ultimately waterflood. Production from Saskatchewan, all
light crude oil, was 1,522 Bbls/d.
Sproule evaluated our proved reserves in Southeast Saskatchewan and assigned
314 Mmcf of natural gas and 4,261 Mbbls of crude oil and NGLs. Probable
reserves in this area were evaluated by Sproule at 160 Mmcf of natural gas and
2,607 Mbbls of crude oil and NGLs.
26
SHALLOW GAS PROPERTIES:
A significant portion of our production comes from shallow gas properties at
Medicine Hat, Bantry, and Shouldice. 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.
MEDICINE HAT, ALBERTA
The Medicine Hat 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 where 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. From January 2002 to December 2005,
320 new wells were added. Only 16 wells were drilled in 2006. Year end 2006
production from this property is 13.1 MMcf/d.
Sproule evaluated our reserves in the area and assigned 50.9 bcf of proved
natural gas reserves and 12.6 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. 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. One well was drilled at this property in 2006. Natural gas is gathered
into our operated compression and dehydration facilities. Year end net
production from this area is 4.5 MMcf/d of natural gas and 25 bbls/d of crude
oil and NGLs.
The Sproule Report assigns 11 bcf of proven natural gas reserves and 20 Mbbls
of proven NGL reserves to this property. In addition, 4.3 bcf of probable
natural gas reserves and 7 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 3.0 MMcf/d is produced on a co-mingled basis from the
Medicine Hat Formation sands with various Belly River Formation sands from
approximately 90 wells. No new wells were added in 2006. Both natural gas and
crude oil are produced and gathered through our facilities of varying working
interests.
The Sproule Report assigns 9.2 bcf of proven natural gas reserves and 73 Mbbls
of proven crude oil and NGLs to this property. In addition, 2.6 bcf of probable
natural gas reserves and 40 Mbbls of probable crude oil and NGL reserves have
been assigned to this property.
27
OIL AND GAS WELLS
The following table sets forth the number and status of wells as at December
31, 2006 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 794.0 445.2 441.0 237.5 1,468.0 1,143.8 359.0 194.0
British Columbia 5.0 3.4 3.0 0.3 117.0 77.3 45.0 30.5
Saskatchewan 207.0 153.5 86.0 62.7 -- -- -- --
Manitoba 85.0 5.1 -- -- -- -- -- --
------- ------- ------- ------- ------- ------- ------- -------
Total 1,091.0 607.2 530.0 300.5 1,585.0 1,221.1 404.0 224.5
======= ======= ======= ======= ======= ======= ======= =======
Note:
(1) Excluding minor interest in the following units (less than 5% working
interest): Steelman Unit No. 3, Pine Creek Second White Specks Pool,
Carrot Creek Cardium K Unit No. 1, Delburne Gas Unit, Nevis Unit No. 1,
Bonnie Glen D-3A Gas Cap Unit, Bellis Gas Unit No. 2, Turner Valley Unit
No. 5, Sunchild Gas Unit No. 1, North Pembina Cardium Unit, Kakwa Cardium
A Unit, Bonanza Boundary A Pool Unit No. 1, and Boundary Lake Units No. 1
and No. 2. Injection Wells are categorized as Non-Producing Oil Wells.
PROPERTIES WITH NO ATTRIBUTED RESERVES
The following table sets out our developed and undeveloped land holdings as at
December 31, 2006.
Developed Acres Undeveloped Acres Total Acres
-------------------------- --------------------------- ------------------------
Gross Net Gross Net Gross Net
--------- --------- --------- --------- --------- ---------
Alberta 907,997 438,611 541,547 260,910 1,449,544 699,521
British Columbia 169,584 72,330 122,835 68,854 292,419 141,184
Saskatchewan 32,978 23,969 94,194 78,413 127,172 102,382
--------- --------- --------- --------- --------- ---------
Total 1,110,559 534,910 758,576 408,177 1,869,135 943,087
========= ========= ========= ========= ========= =========
We expect that rights to explore, develop and exploit 91,109 net acres of our
undeveloped land holdings will expire by December 31, 2007. The land
expirations do not consider our 2007 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.
We have implemented a hedging policy to use costless collars and fixed price
swaps to hedge up to 50% of our gross production for a maximum period of 1 1/2
years. 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.
Overall, approximately 48% of our gas is now hedged for the 2007 calendar year
at a floor of $7.55/mcf. For the first quarter of 2007, we have secured
approximately 58% of our net gas production at an $8.42/mcf floor. For the
months of April to
28
October 2007, approximately 54% of our net gas production is hedged at a floor
of $7.08mcf. We have also hedged approximately 14% of our 2007 net crude
production at an average floor price of US$65.00/bbl.
- ------------------------------------------------------------------------------------------------------------------------------
Description of Hedge Term Volume Average Price
- ------------------------------------------------------------------------------------------------------------------------------
NATURAL GAS - AECO
Fixed price November 2006 to March 2007 3,791 mcf/d Cdn$10.02/mcf
Collar November 2006 to March 2007 9,478 mcf/d Floor Cdn$8.18/mcf
Ceiling Cdn$11.24/mcf
Collar November 2006 to March 2007 4,739 mcf/d Floor Cdn$8.44/mcf
Ceiling Cdn$12.40/mcf
Collar November 2006 to March 2007 4,739 mcf/d Floor Cdn$8.18/mcf
Ceiling Cdn$11.66/mcf
Collar November 2006 to March 2007 4,739 mcf/d Floor Cdn$8.44/mcf
Ceiling Cdn$12.29/mcf
Fixed price November 2006 to March 2007 5,687 mcf/d Cdn$8.70/mcf
Collar November 2006 to March 2007 5,687 mcf/d Floor Cdn$7.91/mcf
Ceiling Cdn$9.81/mcf
Collar November 2006 to March 2007 9,478 mcf/d Floor Cdn$8.44/mcf
Ceiling Cdn$13.82/mcf
CRUDE OIL - WTI
Collar October 2006 to March 2007 1,250 bbls/d Floor US$65.00/bbl
Ceiling US$87.40/bbl
Collar October 2006 to March 2007 1,000 bbls/d Floor US$65.00/bbl
Ceiling US$90.00/bbl
NATURAL GAS PHYSICAL CONTRACTS -
AECO
Collar November 2006 to March 2007 4,739 mcf/d Floor Cdn$8.07/mcf
Ceiling Cdn$11.61/mcf
Collar April 2007 to October 2007 4,739 mcf/d Floor Cdn$7.12/mcf
Ceiling Cdn$8.67/mcf
Collar April 2007 to October 2007 4,739 mcf/d Floor Cdn$6.86/mcf
Ceiling Cdn$9.13/mcf
Collar April 2007 to October 2007 9,478 mcf/d Floor Cdn$7.39/mcf
Ceiling Cdn$9.63/mcf
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 2,859
(gross) producing and non-producing wells. Costs to abandon and reclaim the
producing wells totals $90.7 million ($23.7 million discounted at 7%) 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 $66.5 million ($10.6 million discounted at 7%), and was not
deducted in estimating
29
future net revenue. Facility reclamation costs are scheduled to be incurred in
the year following the end of the reserve life of our associated reserves under
the assumption that decommissioning of plant/facilities are mobile assets with
a long useful life.
Abandonment and reclamation costs included in the estimate of future net
revenue for the next three years are $0.6 million in 2007, $1.7 million in 2008
and $2.0 million in 2009.
TAX HORIZON
In 2006, we did not pay any income related taxes. Effective January 1, 2006 new
government legislation eliminated Federal large corporations tax.
In our structure, the operating company utilizes available tax pools to
significantly reduce taxable income and makes other required payments to the
Trust transferring both income and associated tax liability to the Unitholders.
Therefore, it is expected, based on current legislation that no cash income
taxes are to be paid by the operating company in the future and it is our
intent to continue with the current arrangement. For the 2006 distributions,
50% were taxable to the Canadian Unitholders and 50% were deemed a return of
capital. For U.S. Unitholders, 2006 distributions were 53% taxable and 47% were
deemed a return of capital.
CAPITAL EXPENDITURES
The following tables summarize capital expenditures (including capitalized
general and administrative expenses) related to our activities for the year
ended December 31, 2006:
CAPITAL EXPENDITURES ($ THOUSANDS) 2006
- ------------------------------------------------------------------------------
Land and seismic 5,261
Drilling, completions and workovers 113,146
Well equipping and facilities 39,437
Other 1,643
- ------------------------------------------------------------------------------
159,487
- ------------------------------------------------------------------------------
Property, acquisitions and purchase price adjustments 244
Property dispositions (8,727)
- ------------------------------------------------------------------------------
TOTAL CAPITAL EXPENDITURES 151,004
- ------------------------------------------------------------------------------
EXPLORATION AND DEVELOPMENT ACTIVITIES
The following table sets forth the gross and net wells in which we participated
during the year ended December 31, 2006:
Exploratory Development Total
----------------------- ------------------------ ------------------------
Gross Net Gross Net Gross Net
------- ------- ------- ------- ------- -------
Oil wells 5 4.2 48 31.8 53 36.0
Gas wells 20 7.3 67 41.9 87 49.2
Dry holes 4 3.0 3 2.0 7 5.0
------- ------- ------- ------- ------- -------
Total 29 14.5 118 75.7 147 90.2
======= ======= ======= ======= ======= =======
Subject to, among other things, the availability of drilling rigs and weather
that permits access to drill sites, in 2007, we plan to drill, complete and
tie-in 64 net wells and recomplete an additional 5 net wells.
30
PRODUCTION ESTIMATES
The following table sets out the volume of our production estimated for the
year ended December 31, 2007 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 5,731 697 104,158 2,479 26,267
Developed Non-Producing 168 0 3,647 119 895
Undeveloped 584 0 4,074 90 1,353
---------- --------- ----------- ------- -------
Total Proved 6,483 697 111,879 2,688 28,515
---------- --------- ----------- ------- -------
Probable 599 59 10,181 279 2,634
---------- --------- ----------- ------- -------
Total Proved Plus Probable 7,082 756 122,060 2,967 31,149
---------- --------- ----------- ------- -------
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
-----------------------------------------------------------------------
2006
-----------------------------------------------------------------------
Dec. 31 Sept. 30 Jun. 30 Mar. 31
--------- --------- --------- ---------
Average Daily Production(1)
Crude oil and NGLs (bbls/d) 9,570 9,330 6,593 6,760
Natural gas (Mcf/d) 117,134 122,227 70,293 65,768
Combined (boe/d) 29,092 29,701 18,309 17,721
Average Net Prices Received(2)
Crude oil and NGLs ($/bbl) 54.58 57.77 68.69 58.26
Natural gas ($/Mcf) 6.90 5.89 6.18 8.69
Combined (boe/d)
Royalties(3)(5)
Crude oil and NGLs ($/bbl) 9.87 10.20 11.17 11.09
Natural gas ($/Mcf) 1.36 1.26 1.11 1.62
Combined ($/boe) 8.72 8.40 8.30 10.25
Operating Expenses(4)(5)
Crude oil and NGLs ($/bbl) 11.92 11.04 11.86 10.86
Natural gas ($/Mcf) 1.61 1.32 1.34 1.43
Combined ($/boe) 10.39 8.92 9.41 9.45
Netback Received(6)
Crude oil and NGLs ($/bbl) 57.67 58.41 51.28 57.31
Natural gas ($/Mcf) 2.38 2.41 3.21 3.48
Combined ($/boe) 28.54 28.25 30.77 34.79
Notes:
(1) Before deduction of royalties.
(2) Production prices are net of costs to transport the product to market and
net of realized hedging gains and losses.
(3) Royalties are net of ARC.
(4) This figure includes all field operating expenses.
31
(5) We do not record royalties and operating expenses on a commodity basis.
Information in respect of royalties and operating expenses for crude oil
and NGLs ($/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, 2006:
Natural Gas Crude Oil & NGLs Total
Properties (Mcf/d) (bbls/d) (boe/d)
- -------------------------------------------------------------------------------------------------
Willesden Green 11,010 1,460 3,295
Martin Creek 14,100 290 2,640
Nevis 7,000 1,280 2,447
Medicine Hat 13,150 -- 2,192
Peace River Arch 6,900 470 1,620
Fontas 7,540 -- 1,257
Brazeau 5,210 340 1,208
Lookout Butte 5,830 230 1,202
Sunset 2,380 740 1,137
- -------------------------------------------------------------------------------------------------
Major Properties 73,120 4,810 16,997
Other 43,160 4,810 12,003
- -------------------------------------------------------------------------------------------------
TOTAL 116,280 9,620 29,000
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
32
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:
(e) 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;
(f) 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;
(g) dry hole contributions and bottom hole contributions;
(h) costs of drilling and equipping exploratory wells; and
(i) costs of drilling exploratory type stratigraphic test wells.
"GROSS" means:
(j) 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;
(k) in relation to wells, the total number of wells in which we have an
interest; and
(l) in relation to properties, the total area of properties in which we have
an interest.
"NET" means:
(m) 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;
(n) in relation to wells, the number of wells obtained by aggregating our
working interest in each of our gross wells; and
(o) 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.
33
(b) PROBABLE RESERVES are those additional reserves that are less
certain to be recovered than proved reserves. It is equally likely
that the actual remaining quantities recovered will be greater or
less than the sum of the estimated proved plus probable reserves.
Other criteria that must also be met for the categorization of reserves are
provided in the COGE Handbook.
Each of the reserve categories (proved and probable) may be divided into
developed and undeveloped categories:
(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% probability that the quantities actually recovered
will equal or exceed the estimated proved reserves; and
(b) at least a 50% 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 13% 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
34
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.
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 2007 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, 2006, we employ 111 full-time employees, 87 of which are
located in the head office and 24 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, 2006, 105,390,471 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 three classes, as follows: (i)
"ordinary trust units", which are entitled to the rights, subject to
limitations, restrictions and conditions set out in the Trust Indenture, as
summarized herein; (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; and (iii)
"special trust units", which shall be entitled to the rights and subject to the
limitations, restrictions and conditions set out in the Trust Indenture, as
summarized herein. As at the date hereof there is one special voting unit and
no special trust units 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
(including ordinary trust units and special 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. Each special
trust unit entitles the holder or holders thereof to one-half of one vote at
any meeting of the Unitholders and each ordinary trust unit entitles the holder
or holders thereof to one vote at any meeting of the Unitholders.
The Trust Units do not represent a traditional investment and should not be
viewed by investors as "shares" in either AOG or the Trust. Corporate law does
not govern the Trust and the rights of Unitholders. As holders of Trust Units
in the Trust, the
35
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 ability of the AOG Board of Directors to effect long term growth in
the value of the Trust. The market price of the Trust Units will be sensitive
to a variety of market conditions including, but not limited to, interest
rates, commodity prices and our ability to acquire additional assets. Changes
in market conditions may adversely affect the trading price of the Trust Units.
A return on an investment in the Trust is not comparable to the return on an
investment in a fixed-income security. The recovery of an initial investment in
the Trust is at risk, and the anticipated return on such investment is based on
many performance assumptions. Although the Trust intends to make distributions
of its available cash to holders of Trust Units, these cash distributions may
be reduced or suspended. The actual amount distributed will depend on numerous
factors including: the financial performance of AOG, debt obligations, working
capital requirements and future capital requirements. In addition, the market
value of the Trust Units may decline if the Trust's cash distributions decline
in the future, and that market value decline may be material.
It is important for an investor to consider the particular risk factors that
may affect the industry in which it is investing, and therefore the stability
of the distributions that it receives. See "RISK FACTORS".
The after-tax return from an investment in Trust Units to Unitholders subject
to Canadian income tax can be made up of both a return on capital and a return
of capital. That composition may change over time, thus affecting an investor's
after-tax return. Returns on capital are generally taxed as ordinary income in
the hands of a Unitholder. Returns of capital are generally tax-deferred (and
reduce the Unitholder's cost base in the Trust Unit for tax purposes).
Legislation affecting the tax treatment of an investment in Trust Units can
change at any time. See "RISK FACTORS".
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.
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.
36
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 is 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 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
37
market price shall be an amount equal to the simple average of the highest and
lowest prices for each of the trading days on which there was a trade, and
provided further that if there was trading on the applicable exchange or market
for fewer than five of the 10 trading days, the market price shall be the
simple average of the following prices established for each of the 10 trading
days: the average of the last bid and last ask prices for each day on which
there was no trading; the closing price of the Trust Units for each day that
there was trading if the exchange or market provides a closing price; and the
average of the highest and lowest prices of the Trust Units for each day that
there was trading, if the market provides only the highest and lowest prices of
Trust Units traded on a particular day. The "closing market price" shall be: an
amount equal to the closing price of the Trust Units if there was a trade on
the date; an amount equal to the average of the highest and lowest prices of
the Trust Units if there was trading and the exchange or other market provides
only the highest and lowest prices of Trust Units traded on a particular day;
and the average of the last bid and last ask prices if there was no trading on
the date.
The aggregate Redemption Price payable by us in respect of any Trust Units
surrendered for redemption during any calendar month shall be satisfied by way
of a cash payment on or before the last day of the following month; provided
that the entitlement of Unitholders to receive cash upon the redemption of
their Trust Units is subject to the limitations that: (i) the total amount
payable by us in respect of such Trust Units and all other Trust Units tendered
for redemption in the same calendar month shall not exceed $100,000 (provided
that the Trustee may, in its sole discretion, waive such limitation in respect
of any calendar month); (ii) at the time such Trust Units are tendered for
redemption the outstanding Trust Units shall be listed for trading on a stock
exchange or traded or quoted on any other market which the Trustee considers,
in its sole discretion, provides representative fair market value prices for
the Trust Units; and (iii) the normal trading of Trust Units is not suspended
or halted on any stock exchange on which the Trust Units are listed (or, if not
listed on a stock exchange, on any market on which the Trust Units are quoted
for trading) on the Redemption Date or for more than five trading days during
the 10-day trading period commencing immediately after the Redemption Date.
If a Trust Unitholder is not entitled to receive cash upon the redemption of
Trust Units as a result of the foregoing limitations, then the Redemption Price
for such Trust Units shall be the Fair Market Value thereof (as defined in the
Trust Indenture), as determined by the Trustee in the circumstances described
in subparagraphs (ii) and (iii) above, and shall, subject to any applicable
regulatory approvals, be paid and satisfied by way of distribution IN SPECIE of
a PRO RATA number of Long Term Notes (in a minimum amount of $100.00 and
integral multiples of $1.00), from time to time outstanding (i.e., in a
principal amount equal to the Redemption Price). No fractional Long Term Notes
will be distributed and where the number of Long Term Notes to be received by a
Trust Unitholder includes a fraction, such number shall be rounded to the next
lowest whole number. We shall be entitled to all interest paid, or accrued and
unpaid, on the Long Term Notes on or before the date of the distribution IN
SPECIE. If we do not hold Long Term Notes having a sufficient principal amount
outstanding to effect such payment, we will be entitled to create and, subject
to any applicable regulatory approvals, issue in satisfaction of the Redemption
Price our own debt securities (the "REDEMPTION NOTES") having terms and
conditions substantially the same as the Long Term Notes, and with recourse of
the holder limited to our assets. Holders of such Long Term Notes and
Redemption Notes will be required to acknowledge that they are subject to the
subordination agreements described below under the heading "ADDITIONAL
INFORMATION REGARDING ADVANTAGE OIL & GAS LTD. - NOTES". Long Term Notes and
Redemption Notes may not be qualified investments for trusts governed by
registered retirement savings plans, registered retirement income funds and
deferred profit sharing plans if the Trust ceases to qualify as a mutual fund
trust.
It is anticipated that the redemption right will not be the primary mechanism
for holders of Trust Units to dispose of their Trust Units. Long Term Notes or
Redemption Notes which may be distributed IN SPECIE to Unitholders in
connection with a redemption will not be listed on any stock exchange and no
market is expected to develop in such Long Term Notes or Redemption Notes.
MEETINGS OF UNITHOLDERS
The Trust Indenture provides that meetings of Unitholders must be called and
held for, among other matters, the election or removal of the Trustee, the
appointment or removal of our auditors, the approval of amendments to the Trust
Indenture (except as described under "ADDITIONAL INFORMATION RESPECTING
ADVANTAGE ENERGY INCOME FUND - AMENDMENTS TO THE TRUST INDENTURE"), the sale of
our assets in their entirety or substantially in their entirety (other than as
part of an internal 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
38
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 25,
2007.
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 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
AOG has generally been delegated our significant management decisions. In
particular, pursuant to the Administration Agreement, the Trustee has delegated
to AOG responsibility for the administration and management of all general and
administrative affairs of Advantage, including, among other things:
39
(a) maintaining records and accounts;
(b) preparing all tax returns, filings and documents and monitor the
tax status of the Trust and of the Trust Units;
(c) providing advice with respect to the Trust's obligations as a
reporting issuer and ensure compliance under applicable securities
legislation;
(d) providing investor relations services to the Trust;
(e) calling and holding all meetings of the Unitholders;
(f) undertaking all matters relating to an offering including;
(i) compliance with all applicable laws;
(ii) all matters relating to the content of any offering
documents, the accuracy of the disclosure and the
certification thereof; and
(iii) all matters concerning the entering into, terms of, and
amendment from time to time of material contracts;
(g) retaining professional services and advisors;
(h) dealing with banks and other institutional lenders;
(i) taking all actions reasonably necessary in relation to the
redemption of Trust Units;
(j) taking all actions reasonably necessary in relation to voting
rights on any investments in the Trust Fund;
(k) taking all action reasonably necessary relating to the specific
powers and authorities as set forth in the Trust Indenture;
(l) taking all actions reasonably necessary in relation to providing
indemnities for the directors and officers of the Administrator and
any affiliates of the Trust or the Administrator;
(m) providing or causing to be provided to the Trustee any services
reasonably necessary for the Trustee to be able to consider any
future acquisitions or divestitures by the Trustee of any portion
of the Trust Fund;
(n) providing advice and, at the request and under the direction of the
Trustee, direction to the transfer agent;
(o) determining and arranging for distributions to Unitholders;
(p) providing advice and assistance to the Trustee with respect to the
performance of the obligations of the Trust and the enforcement of
the rights of the Trust under all agreements entered into by the
Trust;
(q) withholding the withholding taxes required and promptly remit such
taxes to the appropriate taxing authority;
(r) providing such additional administrative and support services
pertaining to the Trust, the Trust Fund and the Trust Units and
matters incidental thereto as may be reasonably requested by the
Trustee from time to time;
(s) reporting to Unitholders;
40
(t) providing management services, for the economic and efficient
exploration, exploitation and development of assets of the Trust;
(u) recommending, carrying out and monitoring property acquisitions and
dispositions and exploitation and development programs for the
Trust; and
(v) doing all such things regarding the use of commodity price swaps,
hedges or other such instruments or agreements on behalf of the
Trust in respect of commodity prices or rates of exchange of
currencies or interest rates, the purpose of which is to mitigate
or eliminate exposure to the fluctuations and prices of commodities
or rates of exchange of one currency for another or interest rates.
For more information as to the AOG Board of Directors, see "ADDITIONAL
INFORMATION RESPECTING ADVANTAGE OIL & GAS LTD. - MANAGEMENT OF AOG".
LIABILITY OF THE TRUSTEE
The Trustee, its directors, officers, employees, shareholders and agents shall
not be liable to any 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 AOG or any other appropriately qualified person, any
reliance upon any such evaluation, any action or failure to act of the 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 AOG to perform its duties under or delegated to it under the
Trust Indenture or any material contract), unless such liabilities arise out of
the gross negligence, wilful default or fraud of the Trustee or any of its
directors, officers, employees, shareholders or agents. If the Trustee has
retained an appropriate expert, adviser or legal counsel with respect to any
matter connected with its duties under the Trust Indenture or any material
contract, the Trustee may act or refuse to act based upon the advice of such
expert, adviser or legal counsel, and the Trustee shall not be liable for and
shall be fully protected from any loss or liability occasioned by any action or
refusal to act based upon the advice of any such expert, adviser or legal
counsel. In the exercise of the powers, authorities or discretion conferred
upon the Trustee under the Trust Indenture, the Trustee is and shall be
conclusively deemed to be acting as Trustee of the assets of the Trust and
shall not be subject to any personal liability for any debts, liabilities,
obligations, claims, demands, judgments, costs, charges or expenses against or
with respect to the Trust or the Trust Fund. In addition, the Trust Indenture
contains other customary provisions limiting the liability of the Trustee.
AMENDMENTS TO THE TRUST INDENTURE
The Trust Indenture may be amended or altered, from time to time, by at least
66?% of the votes cast at a meeting of 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;
41
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 2/3% 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.
DIRECTORS AND OFFICERS OF AOG
- ------------------------------------------------------------------------------------------------------------------------------
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 AIM from March 2001 to June 2006. Prior thereto, Managing
Ontario, Canada 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 Chief Executive Chief Executive Officer of AOG since May 24, 2001. President of AIM from
Alberta, Canada Officer and March 2001 to June 2006. Prior thereto, Senior Vice President
Director since (1997-2001) and Vice President, Finance and Chief Financial Officer
May 24, 2001 (1990-1997) of EnerPlus Group of Companies, which companies specialize in
the management of oil and gas income funds and royalty trusts.
42
DIRECTORS AND OFFICERS OF AOG
- ------------------------------------------------------------------------------------------------------------------------------
Position Held and
Name, Province and Country Period Served as
of Residence a Director(4)(5) Principal Occupations During Past Five Years
- ------------------------------------------------------------------------------------------------------------------------------
Grant B. Fagerheim(2)(4) Director since President and Chief Executive Officer of Kereco Energy Ltd. since
Alberta, Canada June 23, 2006 January, 2005. President and Chief Executive Officer of Ketch Resources
Ltd. from November 2002 to January 2005. President and Chief Executive
Officer of Ketch Energy Ltd. from April 2000 to October 2002.
John A. Howard (3)(8) Director since Independent Businessman. Director of Ketch Resources Ltd. from January
Alberta, Canada June 23, 2006 2005 to June 23, 2006. Director of Bear Ridge Resources Ltd. since
January 2005. President of Lunar Enterprises Corp. Director of Eastshore
Energy Ltd. since July 2003. Director of Rockyview Energy Inc. since June
2005. Director of Bear Creek Energy Ltd. from June 2004 to January 2005.
Director of APF Energy Trust from August 2004 to June 2005.
Andy J. Mah President and President and Chief Operating Officer since June 23, 2006. Prior
Alberta, Canada Chief Operating thereto, President of Ketch Resources Ltd. since October 2005. Chief
Officer and a Operating Officer of Ketch Resources Ltd. from January 2005 to September
Director since 2005. Prior thereto, Executive Officer and Vice President, Engineering
June 23, 2006 and Operations of Northrock Resources Ltd. from August 1998 to January
2005.
Ronald A. McIntosh(1)(3) Director since Chairman of North American Energy Partners Inc., a publicly traded
Alberta, Canada September 25, corporation.
1998(6)
Roderick M. Myers(1)(3)(9) 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(1)(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(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)(2)(7) Director since President of Tourigny Management Ltd., a private oil and gas consulting
Alberta, Canada December 31, company.
1996(6)
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.
43
DIRECTORS AND OFFICERS OF AOG
- ------------------------------------------------------------------------------------------------------------------------------
Position Held and
Name, Province and Country Period Served as
of Residence a Director(4)(5) Principal Occupations During Past Five Years
- ------------------------------------------------------------------------------------------------------------------------------
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
David Cronkhite Vice-President, Vice-President, Operations since July 18, 2006. Prior thereto,
Alberta, Canada Operations Production Manager of AOG for five years. Prior thereto, Mr. Cronkhite
held engineering positions with several oil and gas companies.
Neil Bokenfohr Vice President, Vice-President, Exploitation since June 23, 2006. Prior thereto, Vice
Alberta, Canada Exploitation President Exploitation and Operations of Ketch Resources Ltd. since
January 2005; Vice President, Engineering of Bear Creek Energy Ltd. (and
Crossfield Gas Corp. prior thereto) from March 2002 to January 2005.
Prior thereto, Director of Exploitation for Calpine Canada Natural Gas
Company from December 2000 to March 2002.
Weldon M. Kary Vice President, Vice President, Exploitation since February 14, 2005. Prior thereto, with
Alberta, Canada Geosciences and AOG since May 23, 2001, most recently as Manager, Geology and Geophysics.
Land 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. 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) Mr. Howard was the President, Chief Executive Officer and Director of
Sunoma Energy Corp. Immediately upon his resignation from the executive
and board of directors, Sunoma Energy Corp. filed for Court protection.
(9) Not standing for re-election at the upcoming meeting of Unitholders.
44
As at March 12, 2007, the directors and executive officers of AOG, as a group,
beneficially owned, directly or indirectly, or exercised control or direction
over, 3,731,958 Trust Units, or approximately 3.3% 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, preferred
shares or exchangeable shares issued and outstanding. Advantage is also the
sole holder of the outstanding Notes.
The following is a description of the rights attaching to the common shares,
non-voting shares, preferred shares and Notes.
COMMON SHARES
Each common share entitles its holder to receive notice of and to attend all
meetings of the shareholders of AOG and to one vote at such meetings. The
holders of common shares are, at the discretion of the 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.
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
45
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.
NOTES
The following is a summary of the material attributes and characteristics of
the Notes. This summary does not purport to be complete and is qualified in its
entirety by reference to the provisions of the Note Indentures, pursuant to
which the Notes are issued.
PAYMENT UPON MATURITY
On maturity and subject to any applicable subordination restrictions, AOG will
repay the indebtedness represented by the Notes by paying to the Note Trustee,
in lawful money of Canada, an amount equal to the principal amount of the
outstanding Notes, together with accrued and unpaid interest thereon.
RANKING
Payment of the principal and interest (other than regularly scheduled interest
and principal at maturity, provided no default on Senior Indebtedness (as
hereinafter defined) has occurred and payment of such interest or principal is
not otherwise required to be suspended in accordance with the terms of
subordination agreements which may be entered into with the holders of Senior
Indebtedness (as herein defined)) on the Notes will be subordinated in right of
payment, as set forth in the Note Indentures, to the prior payment in full of
the principal of and accrued and unpaid interest on, and all other amounts
owing in respect of, all senior indebtedness ("SENIOR INDEBTEDNESS") which is
defined as: (a) all indebtedness, obligations and liabilities of AOG in respect
of borrowed money (including the deferred purchase price of property), other
than: (i) indebtedness evidenced by the Note Indentures; and (ii) indebtedness
which, by the terms of the instrument creating or evidencing the same, is
expressed to rank in right of payment equally with or subordinate to the
indebtedness evidenced by the Note Indentures; and (b) from and after the
commencement of, and during the continuance of, any creditor proceedings
(including bankruptcy, liquidation, winding-up, dissolution, restructuring or
arrangement proceedings), all indebtedness, obligations and liabilities of AOG,
other than indebtedness, obligations and liabilities of AOG represented by the
Notes. The Note Indentures provide that in the event of any creditor
proceedings relative to AOG, the holders of all Senior Indebtedness, which
would include bank debt and suppliers of AOG, will be entitled to receive
payment in full before the holders of the Notes are entitled to receive any
payment. Any amount of property received contrary to these provisions shall be
held in trust for and paid over to the holders of Senior Indebtedness.
In the event of any creditor proceedings, the indebtedness represented by the
Notes is not to be classified with any Senior Indebtedness for voting or
distribution, which means that holders of Senior Indebtedness may vote
separately from the holders of Notes in respect of any restructuring or
arrangement proposal regarding AOG.
DEFAULT
The Note Indentures provides that any of the following shall constitute an
"Event of Default": (i) default in payment of the principal of the Notes when
the same becomes due; (ii) the failure to pay the interest obligations of the
Notes for a period of 12 months; (iii) default on any indebtedness exceeding
$10,000,000; (iv) certain events of winding-up, liquidation, bankruptcy,
insolvency or receivership; (v) the taking of possession by an encumbrancer of
all or substantially all of the property of AOG; or (vi) default in the
observance or performance of any other covenant or 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
46
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, 2006 was
$662,269,576. 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, 2006 was $213,575,284. The Medium Term Notes
consist of a series of notes, which as of December 31, 2006, 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
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 99% of the production revenues from the
Properties
47
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 99% 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 acquire or dispose of any properties that will cost or result
in proceeds in excess of $5 million, approval of the AOG Board of Directors is
required to approve such acquisition or disposition, respectively.
CASH DISTRIBUTIONS
The following is a summary of the distributions made by us for each of the
three most recently completed financial years.
Distributions
For the 2006 Period Ended per Unit Payment Date
------------------------- ------------- ------------------
January 31 $0.25 February 15, 2006
February 28 0.25 March 15, 2006
March 31 0.25 April 17, 2006
April 30 0.25 May 15, 2006
May 31 0.25 June 15, 2006
June 30 0.25 July 17, 2006
July 31 0.20 August 15, 2006
August 31 0.20 September 15, 2006
September 30 0.20 October 16, 2006
October 31 0.20 November 15, 2006
November 30 0.18 December 15, 2006
December 31 0.18 January 15, 2007
--------
TOTAL: $2.66
48
Distributions
For the 2005 Period Ended 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
Distributions
For the 2004 Period Ended per Unit Payment Date
------------------------- ------------- ------------------
January 31 $0.23 February 17, 2004
February 29 0.23 March 15, 2004
March 31 0.23 April 15, 2004
April 30 0.23 May 17, 2004
May 31 0.23 June 15, 2004
June 30 0.23 July 15, 2004
July 31 0.23 August 16, 2004
August 31 0.23 September 15, 2004
September 30 0.23 October 15, 2004
October 31 0.25 November 15, 2004
November 30 0.25 December 15, 2004
December 31 0.25 January 17, 2005
----
TOTAL $2.82
Note:
(1) On February 15, 2007 a distribution of $0.15 per Trust Unit was paid to
Unitholders of Record on the close of business on January 31, 2006. We
announced on February 14, 2007 that a distribution of $0.15 per Trust
Unit will be payable on March 15, 2007 to Unitholders of record on the
close of business on February 28, 2007.
MARKET FOR SECURITIES
Our Trust Units are listed for trading on the TSX under the symbol "AVN.UN"
and, since December 9, 2005, on the NYSE under the symbol "AAV". The following
table sets forth the high and low closing trading prices and the aggregate
trading volume of the Trust Units as reported by the TSX for the periods
indicated.
49
Period High Low Volume
------------------ --------- ----------- ------------
TSX TRADING ($) ($)
2006
January 23.95 21.02 9,642,249
February 24.35 19.87 10,809,845
March 23.00 20.81 6,193,383
April 23.26 21.30 3,993,614
May 22.10 20.01 4,514,672
June 21.18 18.55 7,236,955
July 19.45 17.25 14,968,997
August 18.83 17.65 8,135,213
September 17.83 13.17 8,434,297
October 16.42 12.05 15,632,835
November 14.95 11.74 13,668,239
December 14.49 12.20 5,573,202
2007
January 13.41 11.47 7,579,256
February 12.80 12.13 5,898,850
NYSE TRADING ($US)
2006
January 21.00 18.05 9,773,000
February 21.30 17.50 8,086,300
March 19.98 18.08 5,633,800
April 20.46 18.85 3,913,300
May 19.88 17.51 5,390,200
June 19.08 16.69 5,688,500
July 17.85 15.33 7,869,600
August 16.70 15.88 4,845,400
September 16.12 11.88 6,183,700
October 14.55 10.74 9,064,500
November 13.10 10.28 12,499,000
December 12.65 10.47 5,648,500
2007
January 11.40 9.76 5,406,700
February 10.90 10.46 3,333,500
Our 10% Convertible Debentures are listed for trading on the TSX under the
symbol "AVN.DB". The following table sets forth the high and low closing
trading prices and the aggregate trading volume of the 10% Convertible
Debentures as reported by the TSX for the periods indicated.
Period High Low Volume
------------------ --------- ----------- ------------
2006 ($) ($)
January 177.24 160.79 1,150
February 178.21 164.48 940
March 170.00 169.03 550
April 170.00 168.00 300
May 163.75 150.92 1,450
June 155.50 150.65 2,670
July -- -- --
August 138.55 134.62 550
September 117.00 117.00 100
October -- -- --
November 100.00 100.00 100
December 110.00 101.01 300
50
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
------------------ --------- ----------- ------------
2006 ($) ($)
January 140.00 129.25 2,385
February 140.50 126.07 7,130
March 131.89 125.00 1,630
April 135.00 127.91 990
May 127.00 117.50 2,020
June 124.00 110.00 3,690
July 111.71 108.75 800
August 113.00 107.12 360
September 103.80 100.26 450
October 103.00 103.00 270
November 109.00 103.00 450
December 103.01 103.01 240
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
------------------ --------- ----------- ------------
2006 ($) ($)
January 144.40 129.15 5,280
February 146.27 126.78 32,670
March 138.03 130.00 5,520
April 139.09 131.56 950
May 132.50 120.65 2,980
June 122.83 116.08 820
July 112.50 106.00 890
August 110.07 106.68 670
September 106.60 103.75 1,630
October 106.00 104.05 1,210
November 106.00 102.50 850
December 105.00 105.00 140
51
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
------------------ --------- ----------- ------------
January 118.00 107.59 17,920
February 120.00 105.01 30,350
March 113.25 106.70 26,660
April 114.50 108.01 7,310
May 110.20 104.65 19,110
June 108.01 103.75 23,400
July 105.00 102.00 37,650
August 104.34 102.25 4,130
September 103.50 100.00 344,210
October 102.95 100.25 6,740
November 102.27 100.01 9,110
December 101.99 100.50 2,240
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
------------------ --------- ----------- ------------
2006 ($) ($)
January 113.90 104.59 46,730
February 115.72 104.01 45,770
March 111.00 106.50 25,310
April 111.00 108.00 19,580
May 108.99 104.75 27,750
June 107.99 104.10 20,410
July 105.01 101.25 19,622
August 104.00 102.20 6,020
September 103.41 101.00 32,350
October 102.75 99.22 11,340
November 102.50 100.00 15,270
December 101.35 100.60 5,930
Our 6.50% Convertible Debentures are listed for trading on the TSX under the
symbol "AVN.DB.E". The following table sets forth the high and low closing
trading prices and the aggregate trading volume of the 6.50% Convertible
Debentures as reported by the TSX for the periods indicated.
Period High Low Volume
------------------ --------- ----------- ------------
2006 ($) ($)
June 101.99 99.50 1,290
July 102.00 99.00 11,560
August 102.00 99.00 13,810
September 100.00 97.01 36,430
October 99.50 96.00 21,950
November 98.01 94.50 22,560
December 98.00 95.77 30,840
52
ESCROWED SECURITIES
As part of the Arrangement, shareholders of AIM received Trust Units in payment
for the sale of their AIM shares to the Trust. All such shareholders were
required to enter into an escrow agreement (the "ESCROW AGREEMENT") providing
for the release of Trust Units as to one-third on each anniversary date of the
Arrangement for three years. All distributions paid on the Trust Units held in
escrow are made directly to the holders of the escrowed Trust Units,
notwithstanding that their Trust Units are in escrow.
All Trust Units will be released from escrow if a Change in Control (as defined
in the Escrow Agreement) occurs. All Trust Units being held in escrow for a
particular shareholder will be released upon that shareholder ceasing to be an
employee for any reason other than termination for just cause or voluntary
departure or resignation.
The Board may consent to the transfer within escrow or the release from escrow
of Trust Units in such circumstances and on such terms and conditions as it
shall determine in its sole discretion.
The Trust Units subject to escrow at December 31, 2006 are as follows:
NUMBER OF TRUST
UNITS HELD IN PERCENTAGE OF
DESIGNATION OF CLASS IN ESCROW CLASS
-------------------- -------------- -------------
Trust Units 1,822,099(1) 1.7%
Notes:
(1) All Trust Units are held by Computershare Trust Company of Canada as
escrow agent.
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 and senior
officers of AOG or 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 2006 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 2006; and (ii)
as disclosed herein.
MATERIAL CONTRACTS
Except for contracts entered into by us in the ordinary course of business or
otherwise disclosed herein, the only material contracts we entered into are the
Trust Indenture described herein under the heading "ADDITIONAL INFORMATION
RESPECTING ADVANTAGE ENERGY INCOME FUND" and the Administrative Agreement
described herein under the heading "ADDITIONAL INFORMATION RESPECTING ADVANTAGE
ENERGY INCOME FUND - DELEGATION OF AUTHORITY, ADMINISTRATION AND TRUST
GOVERNANCE". Copies of the Trust Indenture and Administration 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
53
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.
KPMG LLP has confirmed that it is independent in accordance with the relevant
rules and related interpretation prescribed by the Institute of Chartered
Accountants of Alberta.
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 and AOG 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. Roderick
Meyers, Rodger Tourigny, Carol Pennycook and Ronald McIntosh. 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.
- ----------------------------------------------------------------------------------------------------------------------------
NAME, PROVINCE AND COUNTRY OF FINANCIALLY
RESIDENCE INDEPENDENT LITERATE RELEVANT EDUCATION AND EXPERIENCE
- ----------------------------------------------------------------------------------------------------------------------------
Roderick M. Myers(1) Yes Yes Mr. Meyers has a Masters degree in Civil Engineering.
British Columbia, Canada He is currently a self-employed businessman who has been
working in Calgary's energy sector since 1981 and has
focused on evaluating and investing in small-cap oil and
natural gas ventures.
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 Sound Energy Trust and is a director and
member of the Audit Committee of Burmis Energy Inc. and
of Ramparts Energy Ltd., a private oil and gas company.
Ronald A. McIntosh Yes Yes Mr. McIntosh is the Chairman and member of audit
Alberta, Canada committee of North American Energy Partners Inc., a
publicly traded corporation. He is a director and member
of the audit committee of C1 Energy Ltd. Mr. McIntosh is
also the Chairman and member of the audit committee of
Tasman Energy, a private oil and gas company.
54
- ----------------------------------------------------------------------------------------------------------------------------
NAME, PROVINCE AND COUNTRY OF FINANCIALLY
RESIDENCE INDEPENDENT LITERATE RELEVANT EDUCATION AND EXPERIENCE
- ----------------------------------------------------------------------------------------------------------------------------
Carol D. Pennycook Yes Yes Ms. Pennycook is a partner at the Toronto offices of
Ontario, Canada Davies Ward Phillips & Vineberg, LLP, a national law
firm. Ms. Pennycook received her LLB in 1979 and has
been a partner since 1986. A significant portion of Ms.
Pennycook's practice involves financing transactions
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
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.
55
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 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.
56
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.
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.
57
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.
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.
58
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:
(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.
59
AUDIT SERVICE FEES
AUDITOR SERVICES FEES
The following table discloses fees billed to us by our auditors, KPMG LLP.
- --------------------------------------------------------------------------------------------------------------------------
TYPE OF SERVICE PROVIDED 2006 2005
- --------------------------------------------------------------------------------------------------------------------------
Audit Fees (these services included prospectus work and audit or review of financials $617,000 $269,000
forming part of such prospectus and U.S. GAAP reconciliation matters)
Audit-Related Fees (these services included French translation in connection with $144,500 $ 30,000
prospectus offerings)
Tax Fees (these services included review/completion of tax returns and general tax $ 36,040 $ 21,725
consultations)
INDUSTRY CONDITIONS
The oil and natural gas industry is subject to extensive controls and
regulations governing its operations (including land tenure, exploration,
development, production, refining, transportation, and marketing) imposed by
legislation enacted by various levels of government and with respect to pricing
and taxation of oil and natural gas by agreements among the governments of
Canada, Alberta, British Columbia, and Saskatchewan, all of which should be
carefully considered by investors in the oil and gas industry. It is not
expected that any of these controls or regulations will affect our operations
in a manner materially different than they would affect other oil and gas
entities of similar size. All current legislation is a matter of public record
and we are unable to predict what additional legislation or amendments may be
enacted. Outlined below are some of the principal aspects of legislation,
regulations and agreements governing the oil and gas industry.
PRICING AND MARKETING - OIL AND NATURAL GAS
The producers of oil are entitled to negotiate sales contracts directly with
oil purchasers, with the result that the market determines the price of oil.
Oil prices are primarily based on worldwide supply and demand. The specific
price depends in part on oil quality, prices of competing fuels, distance to
market, the value of refined products, the supply/demand balance, and other
contractual terms. Oil exporters are also entitled to enter into export
contracts with terms not exceeding one year in the case of light crude oil and
two years in the case of heavy crude oil, provided that an order approving such
export has been obtained from the National Energy Board of Canada (the "NEB").
Any oil export to be made pursuant to a contract of longer duration (to a
maximum of 25 years) requires an exporter to obtain an export licence from the
NEB and the issuance of such licence requires the approval of the Governor in
Council.
The price of natural gas is determined by negotiation between buyers and
sellers. Natural gas exported from Canada is subject to regulation by the NEB
and the Government of Canada. Exporters are free to negotiate prices and other
terms with purchasers, provided that the export contracts must continue to meet
certain other criteria prescribed by the NEB and the Government of Canada.
Natural gas exports for a term of less than two years or for a term of two to
20 years (in quantities of not more than 30,000 m3/day), must be made pursuant
to an NEB order. Any natural gas export to be made pursuant to a contract of
longer duration (to a maximum of 25 years) or a larger quantity requires an
exporter to obtain an export licence from the NEB and the issuance of such
licence requires the approval of the Governor in Council.
The governments of Alberta, British Columbia, and Saskatchewan also regulate
the volume of natural gas that may be removed from those provinces for
consumption elsewhere based on such factors as reserve availability,
transportation arrangements, and market considerations.
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PIPELINE CAPACITY
Although pipeline expansions are ongoing, the lack of firm pipeline capacity
continues to affect the oil and natural gas industry and limit the ability to
produce and to market natural gas production. In addition, the pro-rationing of
capacity on the inter-provincial pipeline systems also continues to affect the
ability to export oil and natural gas.
THE NORTH AMERICAN FREE TRADE AGREEMENT
The North American Free Trade Agreement ("NAFTA") among the governments of
Canada, United States of America, and Mexico became effective on January 1,
1994. NAFTA carries forward most of the material energy terms that are
contained in the Canada United States Free Trade Agreement. In the context of
energy resources, Canada continues to remain free to determine whether exports
of energy resources to the United States or Mexico will be allowed, provided
that any export restrictions do not: (i) reduce the proportion of energy
resources exported relative to domestic use (based upon the proportion
prevailing in the most recent 36 month period); (ii) impose an export price
higher than the domestic price subject to an exception with respect to certain
voluntary measures which only restrict the volume of exports; and (iii) disrupt
normal channels of supply. All three countries are prohibited from imposing
minimum or maximum export or import price requirements, provided, in the case
of export price requirements, prohibition in any circumstances in which any
other form of quantitative restriction is prohibited, and in the case of
import-price requirements, such requirements do not apply with respect to
enforcement of countervailing and anti-dumping orders and undertakings.
NAFTA contemplates the reduction of Mexican restrictive trade practices in the
energy sector by 2010 and prohibits discriminatory border restrictions and
export taxes. NAFTA also contemplates clearer disciplines on regulators to
ensure fair implementation of any regulatory changes and to minimize disruption
of contractual arrangements and avoid undue interference with pricing,
marketing and distribution arrangements, which is important for Canadian
natural gas exports.
PROVINCIAL ROYALTIES AND INCENTIVES
GENERAL
In addition to federal regulation, each province has legislation and
regulations which govern land tenure, royalties, production rates,
environmental protection, and other matters. The royalty regime is a
significant factor in the profitability of crude oil, natural gas liquids,
sulphur, and natural gas production. Royalties payable on production from lands
other than Crown lands are determined by negotiations between the mineral owner
and the lessee, although production from such lands is subject to certain
provincial taxes and royalties. Crown royalties are determined by governmental
regulation and are generally calculated as a percentage of the value of the
gross production. The rate of royalties payable generally depends in part on
prescribed reference prices, well productivity, geographical location, field
discovery date, method of recovery, and the type or quality of the petroleum
product produced. Other royalties and royalty-like interests are, from time to
time, carved out of the working interest owner's interest through non-public
transactions. These are often referred to as overriding royalties, gross
overriding royalties, net profits interests, or net carried interests.
Occasionally the governments of the western Canadian provinces create incentive
programs for exploration and development. Such programs often provide for
royalty rate reductions, royalty holidays, and tax credits, and are generally
introduced when commodity prices are low. The programs are designed to
encourage exploration and development activity by improving earnings and cash
flow within the industry. Royalty holidays and reductions would reduce the
amount of Crown royalties paid by oil and gas producers to the provincial
governments and would increase the net income and funds from operations of such
producers. However, the trend in recent years has been for provincial
governments to eliminate, amend or allow such incentive programs to expire
without renewal, and consequently few such incentive programs are currently
operative.
The Canadian federal corporate income tax rate levied on taxable income is
22.1% effective January 1, 2007 for active business income including resource
income. With the elimination of the corporate surtax effective January 1, 2008
and other rate reductions introduced in the 2006 Federal Budget, the federal
corporate income tax rate will decrease to 19% in three steps: 20.5% on January
1, 2008, 20% on January 1, 2009 and 19% on January 1, 2010.
61
ALBERTA
In Alberta, companies are granted the right to explore, produce and develop
petroleum and natural gas resources in exchange for royalties, bonus bid
payments and rents. Currently, the amount of royalties that are payable is
influenced by the oil production, density of the oil, and the vintage of the
oil. Originally, the vintage classified oil in "new oil" and "old oil"
depending on when the oil pools were discovered. If discovered prior to March
31, 1974 it is considered "old oil", if discovered after March 31, 1974 and
before September 1, 1992, it is considered "new oil". The Alberta government
introduced in 1992 a Third Tier Royalty with a base rate of 10% and a rate cap
of 25% for oil pools discovered after September 1, 1992. The new oil royalty
reserved to the Crown has a base rate of 10% and a rate cap of 30%. The old oil
royalty reserved to the Crown has a base rate of 10% and a rate cap of 35%.
The royalty reserved to the Crown in respect of natural gas production, subject
to various incentives, is between 15% and 30%, in the case of new natural gas,
and between 15% and 35%, in the case of old natural gas, depending upon a
prescribed or corporate average reference price. Natural gas produced from
qualifying intervals in eligible gas wells spudded or deepened to a depth below
2,500 metres is also subject to a royalty exemption, the amount of which
depends on the depth of the well.
Oil sands projects are subject to a specific regulation made effective July 1,
1997, and expiring June 30, 2007, which, among other things, determines the
Crown's share of crude and processed oil sands products.
Regulations made pursuant to the MINES AND MINERALS ACT (Alberta) provided
various incentives for exploring and developing oil reserves in Alberta.
However, the Alberta Government announced in August of 2006 that four royalty
programs were to be amended, a new program was to be introduced and the Alberta
Royalty Tax Credit Program ("ARTC") was to be eliminated, effective January 1,
2007. The ARTC was eliminated on January 1, 2007 as announced. The programs
being amended are: (i) Deep Gas Royalty Holiday; (ii) Low Productivity Well
Royalty Reduction; (iii) Reactivated Well Royalty Exemption; and (iv)
Horizontal Re-Entry Royalty Reduction. The program being introduced is the
Innovative Energy Technologies Program (the "IETP") which is intended to
promote the producers' investment in research, technology and innovation for
the purposes of improving environmental performance while creating commercial
value. The IETP provides royalty reductions which are presumed to reduce
financial risk. Alberta Energy will be the one to decide which projects qualify
and the level of support that will be provided. The deadline for the IETP's
third round of applications is May 31, 2007.
On February 16, 2007, the Alberta Government announced that a review of the
province's royalty and tax regime (including income tax and freehold mineral
rights tax) pertaining to oil, gas and oil sands will be conducted by a panel
of experts, with the assistance of individual Albertans and key stakeholders.
The purpose of this process is to ensure that Albertans are receiving a fair
share from energy development through royalties, taxes and fees. The issues to
be reviewed during this examination process are: (i) undertaking a comparison
of Alberta's royalty system to other oil and gas producing jurisdictions,
taking into account investment economics and industry returns and risks in
Alberta; (ii) whether Alberta's royalty system is sufficiently sensitive to
market conditions; (iii) whether the current revenue minus cost system for oil
sands royalties is optimal; (iv) which programs built into the existing royalty
system should be retained or strengthened, and which should be adapted or
eliminated; (v) how the tax treatment of the oil and gas sector compares to
other sectors and jurisdictions; (vi) the economic and fiscal impacts of any
possible changes to the royalty and corporate tax structures; and (vii) how
existing resource development should be treated if changes are to be made to
the fiscal regime. The review panel is to produce a final report that will be
presented to the Minister of Finance by August, 31, 2007.
BRITISH COLUMBIA
Producers of oil and natural gas in the Province of British Columbia are
required to pay annual rental payments with respect to the Crown leases and
royalties and freehold production taxes in respect of oil and gas produced from
Crown and freehold lands. The amount payable as a royalty in respect of oil
depends on the type of oil, the value of the oil, the quantity of oil produced
in a month, and the vintage of the oil. Generally, the vintage of oil is based
on the determination of whether the oil is produced from a pool discovered
before October 31, 1975 (old oil), between October 31, 1975, and June 1, 1998
(new oil), or after June 1, 1998 (third-tier oil). The royalty rates are
calculated in three stages, which take into account the vintage of the oil, if
the oil produced has already been sold and any royalty exempt value applicable
(exempt wells). Oil produced from newly discovered pools may be exempt from the
payment of a royalty for the first 36 months of production or 11,450m(3)
produced, whichever comes first; and the royalties for third-tier oil are the
lowest reflecting the higher costs of
62
exploration and extraction that the producers would incur. The royalty payable
on natural gas is determined by a sliding scale based on a reference price,
which is the greater of the price obtained by the producer, and a prescribed
minimum price. However, when the reference price is below the select price (a
parameter used in the royalty rate formula), the royalty rate is fixed. As an
incentive for the production and marketing of natural gas, which may have been
flared, natural gas produced in association with oil has a lower royalty then
the royalty payable on non-conservation gas.
On May 30, 2003, the Ministry of Energy and Mines for the Province of British
Columbia announced an Oil and Gas Development Strategy for the Heartlands
("STRATEGY"). The Strategy is a comprehensive program to address road
infrastructure, targeted royalties and regulatory reduction, and British
Columbia service sector opportunities. In addition, the Strategy will result in
economic and employment opportunities for communities in British Columbia's
heartlands.
Some of the financial incentives in the Strategy include:
o Royalty credits of up to $30 million annually towards the construction,
upgrading, and maintenance of road infrastructure in support of resource
exploration and development. Funding will be contingent upon an equal
contribution from industry.
o Changes to provincial royalties: new royalty rates for low productivity
natural gas to enhance marginally economic resources plays, royalty
credits for deep gas exploration to locate new sources of natural gas,
and royalty credits for summer drilling to expand the drilling season.
On February 27, 2007 the Government of British Columbia unveiled the Energy
Plan outlining the Province's strategy towards the environment and which
includes targeting for zero net greenhouse gas emissions, promoting new
investments in innovation, and becoming the world's leader in sustainable
environmental management. With regards to the oil and gas industry the
objective is to achieve clean energy through conservation and energy efficient
practices, whilst competitiveness is advocated in order to attract investment
for the development of the oil and gas sector. Among the changes to be
implemented are: (i) a new of Net Profit Royalty Program; (ii) the creation of
a Petroleum Registry; (iii) the establishing of an infrastructure royalty
program (combining roads and pipelines); (iv) the elimination of routine
flaring at producing wells; (v) the creation of policies and measures for the
reduction of emissions; (vi) the development of unconventional resources such
as tight gas and coalbed gas; and (vii) the new Oil and Gas Technology Transfer
Incentive Program that encourages the research, development and use of
innovative technologies to increase recoveries from existing reserves from
existing reserves and promotes responsible development of new oil and gas
reserves.
SASKATCHEWAN
In Saskatchewan, the amount payable as a royalty in respect of oil depends on
the vintage of the oil, the type of oil, the quantity of oil produced in a
month, and the value of the oil. For Crown royalty and freehold production tax
purposes, crude oil is considered "heavy oil", "southwest designated oil", or
"non-heavy oil other than southwest designated oil". The conventional royalty
and production tax classifications ("fourth tier oil" introduced October 1,
2002, "third tier oil", "new oil", or "old oil") of oil production are
applicable to each of the three crude oil types. The Crown royalty and freehold
production tax structure for crude oil is price sensitive and varies between
the base royalty rates of 5% for all "fourth tier oil" to 20% for "old oil".
Marginal royalty rates are 30% for all "fourth tier oil" to 45% for "old oil".
The amount payable as a royalty in respect of natural gas is determined by a
sliding scale based on a reference price (which is the greater of the amount
obtained by the producer and a prescribed minimum price), the quantity produced
in a given month, the type of natural gas, and the vintage of the natural gas.
As an incentive for the production and marketing of natural gas which may have
been flared, the royalty rate on natural gas produced in association with oil
is less than on non-associated natural gas. The royalty and production tax
classifications of gas production are "fourth tier gas" introduced October 1,
2002, "third tier gas", "new gas", and "old gas". The Crown royalty and
freehold production tax for gas is price sensitive and varies between the base
royalty rate of 5% for "fourth tier gas" and 20% for "old gas". The marginal
royalty rates are between 30% for "fourth tier gas" and 45% for "old gas".
On October 1, 2002, the following changes were made to the royalty and tax
regime in Saskatchewan:
63
o A new Crown royalty and freehold production tax regime applicable to
associated natural gas (gas produced from oil wells) that is gathered for
use or sale. The royalty/tax will be payable on associated natural gas
produced from an oil well that exceeds approximately 65 thousand cubic
metres in a month.
o A modified system of incentive volumes and maximum royalty/tax rates
applicable to the initial production from oil wells and gas wells with a
finished drilling date on or after October 1, 2002, was introduced. The
incentive volumes are applicable to various well types and are subject to
a maximum royalty rate of 2.5% and a freehold production tax rate of zero
per cent.
o The elimination of the re entry and short section horizontal oil well
royalty/tax categories. All horizontal oil wells with a finished drilling
date on or after October 1, 2002, will receive the "fourth tier" royalty/
tax rates and new incentive volumes.
In 1975, the Government of Saskatchewan introduced a Royalty Tax Rebate ("RTR")
as a response to the federal government disallowing crown royalties and similar
taxes as a deductible business expense for income tax purposes. As of January
1, 2007, the remaining balance of any unused RTR limited in its carry forward
to five years since the federal government had the initiative to reintroduce
the full deduction of provincial resource royalties from federal and provincial
taxable income.
LAND TENURE
Crude oil and natural gas located in the western provinces is owned
predominantly by the respective provincial governments. Provincial governments
grant rights to explore for and produce oil and natural gas pursuant to leases,
licences, and permits for varying terms from two years, and on conditions set
forth in provincial legislation including requirements to perform specific work
or make payments. Oil and natural gas located in such provinces can also be
privately owned and rights to explore for and produce such oil and natural gas
are granted by lease on such terms and conditions as may be negotiated.
ENVIRONMENTAL REGULATION
The oil and natural gas industry is currently subject to environmental
regulations pursuant to a variety of provincial and federal legislation. Such
legislation provides for restrictions and prohibitions on the release or
emission of various substances produced in association with certain oil and gas
industry operations. In addition, such legislation requires that well and
facility sites be abandoned and reclaimed to the satisfaction of provincial
authorities. Compliance with such legislation can require significant
expenditures and a breach of such requirements may result in suspension or
revocation of necessary licenses and authorizations, civil liability for
pollution damage, and the imposition of material fines and penalties.
Environmental legislation in the Province of Alberta has been consolidated into
the ENVIRONMENTAL PROTECTION AND ENHANCEMENT ACT (Alberta) (the "EPEA"), which
came into force on September 1, 1993, and the OIL AND GAS CONSERVATION ACT
(Alberta) (the "OGCA"). The EPEA and OGCA impose stricter environmental
standards, require more stringent compliance, reporting and monitoring
obligations, and significantly increased penalties. In 2006, the Alberta
Government enacted regulations pursuant to the EPEA to specifically target
sulphur oxide and nitrous oxide emissions from industrial operations including
the oil and gas industry. No additional expenses are foreseen that are
associated with complying with the new regulations. We are committed to meeting
its responsibilities to protect the environment wherever it operates and
anticipates making increased expenditures of both a capital and an expense
nature as a result of the increasingly stringent laws relating to the
protection of the environment, and will be taking such steps as required to
ensure compliance with the EPEA and similar legislation in other jurisdictions
in which it operates. We believe that we are in material compliance with
applicable environmental laws and regulations. We also believe that it is
reasonably likely that the trend towards stricter standards in environmental
legislation and regulation will continue.
British Columbia's ENVIRONMENTAL ASSESSMENT ACT became effective June 30, 1995.
This legislation rolls the previous processes for the review of major energy
projects into a single environmental assessment process with public
participation in the environmental review process.
64
In December, 2002, the Government of Canada ratified the Kyoto Protocol
("PROTOCOL"). The Protocol calls for Canada to reduce its greenhouse gas
emissions to 6% below 1990 "business-as-usual" levels between 2008 and 2012.
Given revised estimates of Canada's normal emissions levels, this target
translates into an approximately 40% gross reduction in Canada's current
emissions. It remains uncertain whether the Kyoto target of 6% below 1990
emission levels will be enforced in Canada. The Federal Government has
introduced legislation aimed at reducing greenhouse gas emissions using a
"intensity based" approach, the specifics of which have yet to be determined.
Bill C-288, which is intended to ensure that Canada meets its global climate
change obligations under the Kyoto Protocol, was passed by the House of Commons
on February 14, 2007. As details of the implementation of this legislation have
not yet been announced, the effect of our operations cannot be determined at
this time.
TRENDS
There are a number of trends that have been developing in the oil and gas
industry during the past several years that appear to be shaping the near
future of the business.
The first trend is the volatility of commodity prices. Natural gas is a
commodity influenced by factors within North America. A tight supply-demand
balance for natural gas causes significant elasticity in pricing, whereas
higher than average storage levels tend to depress natural gas pricing.
Drilling activity, weather, fuel switching and demand for electrical generation
are all factors that affect the supply-demand balance. Changes to any of these
or other factors create price volatility.
Crude oil is influenced by the world economy, Organization of the Petroleum
Exporting Countries' ability to adjust supply to world demand and weather.
Crude oil prices have been kept high by political events causing disruptions in
the supply of oil and concern over potential supply disruptions triggered by
unrest in the Middle East and more recently have been impacted by weather and
increased storage levels. Political events trigger large fluctuations in price
levels.
The impact on the oil and gas industry from commodity price volatility is
significant. During periods of high prices, producers generate sufficient cash
flows to conduct active exploration programs without external capital.
Increased commodity prices frequently translate into very busy periods for
service suppliers triggering premium costs for their services. Purchasing land
and properties similarly increase in price during these periods. During low
commodity price periods, acquisition costs drop, as do internally generated
funds to spend on exploration and development activities. With decreased
demand, the prices charged by the various service suppliers also decline.
A second trend within the Canadian oil and gas industry is the fairly
consistent "renewal" of private and small junior oil and gas companies starting
up business. These companies often have experienced management teams from
previous industry organizations that have disappeared as a part of the ongoing
industry consolidation. Many are able to raise capital and recruit well
qualified personnel. We will have to compete with these companies and others to
attract qualified personnel.
A third trend currently affecting the oil and gas industry is the impact on
capital markets caused by investor uncertainty in the North American economy.
The capital market volatility in Canada has also been affected by uncertainties
surrounding the economic impact that the Protocol, and other environmental
initiatives, will have on the sector and, in more recent times, by the October
31, 2006 Proposals of the Federal government of Canada relating to income
trusts and other "specified investment flow-through" entities ("SIFTS").
Pursuant to the existing provisions of the INCOME TAX ACT (Canada), to the
extent that a SIFT has any income for a taxation year after certain inclusions
and deductions, the SIFT will be permitted to deduct all amounts of income
which are paid or become payable by it to unitholders in the year. Under the
October 31, 2006 Proposals, SIFTs will be liable for tax at a rate consistent
with the taxes currently imposed on corporations commencing in January 2011,
provided that the SIFT experiences only "normal growth" and no "undue
expansion" before then, in which case the tax could be imposed prior to the
January 2011 deadline. See "RISK FACTORS - CHANGES IN LEGISLATION - THE OCTOBER
31, 2006 PROPOSALS".
Generally during the past year, the economic recovery combined with increased
commodity prices has caused an increase in new equity financings in the oil and
gas industry, although the level of same was negatively impacted by the October
31, 2006 Proposals. We will compete with numerous new companies and their new
management teams and development plans in its access to capital. The
competitive nature of the oil and gas industry will cause opportunities for
equity financings to be selective. We may have to rely on internally generated
funds to conduct our exploration and developmental programs.
65
RISK FACTORS
The following is a summary of certain risk factors relating to the business of
AOG and the Trust. The following information is a summary only of certain risk
factors and is qualified in its entirety by reference to, and must be read in
conjunction with, the detailed information appearing elsewhere in this annual
information form.
DEPENDENCE ON AOG
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 2006 averaging US$66.35 WTI as
compared to an average of US$56.61 WTI in 2005, an increase of 17%.
AECO monthly index prices averaged $6.98/Mcf in 2006 as compared to $8.49/Mcf
in 2005, a decrease of 18%. 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.
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EXPLOITATION AND DEVELOPMENT
Exploitation and development risks are due to the uncertain results of
searching for and producing oil and natural gas using imperfect scientific
methods. These risks are mitigated by using highly skilled staff, focusing
exploitation efforts in areas in which we have existing knowledge and expertise
or access to such expertise, using up-to-date technology to enhance methods,
and controlling costs to maximize returns. Advanced oil and natural gas related
technologies such as three-dimensional seismography, reservoir simulation
studies and horizontal drilling have been and will be used by us to improve our
ability to find, develop and produce oil and natural gas.
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.
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ASSESSMENTS OF VALUE OF ACQUISITIONS
Acquisitions of resource issuers and resource assets will be based in large
part upon engineering and economic assessments made by independent engineers.
These assessments will include a series of assumptions regarding such factors
as recoverability and marketability of oil and gas, future prices of oil and
gas and operating costs, future capital expenditures and royalties and other
government levies which will be imposed over the producing life of the
reserves. Many of these factors are subject to change and are beyond our
control. In particular, the prices of and markets for resource products may
change from those anticipated at the time of making such assessment. In
addition, all such assessments involve a measure of geologic and engineering
uncertainty which could result in lower production and reserves than
anticipated. Initial assessments of acquisitions may be based upon reports by a
firm of independent engineers that are not the same as the firm that we use for
our year end reserve evaluations. Because each of these firms may have
different evaluation methods and approaches, these initial assessments may
differ significantly from the assessments of the firm used by us. Any such
instance may offset the return on and value of the Trust Units.
DEBT SERVICE
AOG has credit facilities in the amount of $600,000,000. 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
All phases of the oil and natural gas business present environmental risks and
hazards and are subject to environmental regulation pursuant to a variety of
federal, provincial and local laws and regulations. Compliance with such
legislation can require significant expenditures and a breach may result in the
imposition of fines and penalties, some of which may be material. Environmental
legislation is evolving in a manner expected to result in stricter standards
and enforcement, larger fines and liability and potentially increased capital
expenditures and operating costs. In 2002, the Government of Canada ratified
the Kyoto Protocol (the "PROTOCOL"), which calls for Canada to reduce its
greenhouse gas emissions to specified levels. There has been much public debate
with respect to Canada's ability to meet these targets and the Government's
strategy or alternative strategies with respect to climate change and the
control of greenhouse gases. Implementation of strategies for reducing
greenhouse gases whether to meet the limits required by the Protocol or as
otherwise determined, could have a material impact on the nature of oil and
natural gas operations, including those of the Trust. Given the evolving nature
of the debate related to climate change and the control of greenhouse gases and
resulting requirements, it is not possible to predict either the nature of
those requirements or the impact on the Trust and its operations and financial
68
condition. 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 our 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.
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 2006, 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 2006 to an
average $0.88 US/Cdn compared to $0.83 US/Cdn in 2005. 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 SENIOR EXECUTIVES OF AOG
Unitholders will be dependent upon the management of 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 AOG
should not invest in the Trust Units.
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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;
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
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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.
CHANGES IN LEGISLATION - THE OCTOBER 31, 2006 PROPOSALS
The October 31, 2006 Proposals propose to apply a tax at the trust level on
distributions of certain income from publicly traded mutual fund trusts at
rates of tax comparable to the combined federal and provincial corporate tax
and to treat such distributions as dividends to the unitholders. Existing
trusts will have a four-year transition period and, subject to the
qualification below, will not be subject to the new rules until January 1,
2011. However, assuming the October 31, 2006 Proposals are ultimately enacted
in their current form, the implementation of such legislation would be expected
to result in adverse tax consequences to the Trust and certain Unitholders
(including most particularly Unitholders that are tax deferred or non-residents
of Canada) and may impact cash distributions from the Trust.
In light of the foregoing, management of AOG believes that the October 31, 2006
Proposals may reduce the value of the Trust Units, which would be expected to
increase the cost to the Trust of raising capital in the public capital
markets. In addition management of AOG believes that the October 31, 2006
Proposals are expected to: (a) substantially eliminate the competitive
advantage that the Trust and other Canadian energy trusts enjoy relative to
their corporate peers in raising capital in a tax-efficient manner; and (b)
place the Trust and other Canadian energy trusts at a competitive disadvantage
relative to industry competitors, including U.S. master limited partnerships,
which will continue to not be subject to entity level taxation. The October 31,
2006 Proposals are also expected to make the Trust Units less attractive as an
acquisition currency. As a result, it may become more difficult for the Trust
to compete effectively for acquisition opportunities. There can be no assurance
that the Trust will be able to reorganize its legal and tax structure to
substantially mitigate the expected impact of the October 31, 2006 Proposals.
Further, the proposals provide that, while there is no intention to prevent
"normal growth" during the transitional period, any "undue expansion" could
result in the transition period being "revisited", presumably with the loss of
the benefit to the Trust of that transitional period. As a result, the adverse
tax consequences resulting from the proposals could be realized sooner than
January 1, 2011. On December 15, 2006, the Department of Finance issued
guidelines with respect to what is meant by "normal growth" in this context.
Specifically, the Department of Finance stated that "normal growth" would
include equity growth within certain "safe harbour" limits, measured by
reference to a SIFT's market capitalization as of the end of trading on October
31, 2006 (which would include only the market value of the SIFT's issued and
outstanding publicly-traded trust units, and not any convertible debt, options
or other interests convertible into or exchangeable for trust units). Those
safe harbour limits are 40% for the period from November 1, 2006 to December
31, 2007, and 20% each for calendar 2008, 2009 and 2010. Moreover, these limits
are cumulative, so that any unused limit for a period carries over into the
subsequent period. Additional details of the Department of Finance's guidelines
include the following:
(a) new equity for these purposes includes units and debt that is
convertible into units (and may include other substitutes for
equity if attempts are made to develop those);
(b) replacing debt that was outstanding as of October 31, 2006 with new
equity, whether by a conversion into trust units of convertible
debentures or otherwise, will not be considered growth for these
purposes and will therefore not affect the safe harbour; and
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(c) the exchange, for trust units, of exchangeable partnership units or
exchangeable shares that were outstanding on October 31, 2006 will
not be considered growth for those purposes and will therefore not
affect the safe harbour where the issuance of the trust units is
made in satisfaction of the exercise of the exchange right by a
person other than the SIFT.
The Trust's market capitalization as of the close of trading on October 31,
2006, having regard only to its issued and outstanding publicly-traded Trust
Units, was approximately $1.6 billion, which means the Trust's "safe harbour"
equity growth amount for the period ending December 31, 2007 is approximately
$640 million, and for each of calendar 2008, 2009 and 2010 is an additional
approximately $320 million (in any case, not including equity, including
convertible debentures, issued to replace debt that was outstanding on October
31, 2006).
While these guidelines are such that it is unlikely they would affect our
ability to raise the capital required to maintain and grow our existing
operations in the ordinary course during the transition period, they could
adversely affect the cost of raising capital and our ability to undertake more
significant acquisitions.
It is not known at this time when the October 31, 2006 Proposals will be
enacted by Parliament, if at all, or whether the October 31, 2006 Proposals
will be enacted in the form currently proposed.
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.
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 2007 an estimated 70% 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.
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 of 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".
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.
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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 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 we 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
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Properties acquired by AOG, and the Manager's ability to effect long-term
growth in our value. The market price of the Trust Units will be sensitive to a
variety of market conditions including, but not limited to, interest rates and
our ability to acquire suitable oil and natural gas properties. Changes in
market conditions may adversely affect the trading price of the Trust Units.
The Trust Units are also unlike conventional debt instruments in that there is
no principal amount owing to Unitholders. The Trust Units will have minimal
value when reserves from our properties can no longer be economically produced
or marketed. Unitholders will only be able to obtain a return of the capital
they invested during the period when reserves may be economically recovered and
sold. Accordingly, the distributions received over the life of the investment
may not be equal to or greater than the initial capital investment.
THE TRUST UNITS ARE NOT "DEPOSITS" WITHIN THE MEANING OF THE CANADA DEPOSIT
INSURANCE CORPORATION ACT (CANADA) AND ARE NOT INSURED UNDER THE PROVISIONS OF
THAT ACT OR ANY OTHER LEGISLATION. FURTHERMORE, THE TRUST IS NOT A TRUST
COMPANY AND, ACCORDINGLY, IS NOT REGISTERED UNDER ANY TRUST AND LOAN COMPANY
LEGISLATION AS IT DOES NOT CARRY ON OR INTEND TO CARRY ON THE BUSINESS OF A
TRUST COMPANY.
NET ASSET VALUE
The net asset value of our assets from time to time will vary depending upon a
number of factors beyond the control of management, including oil and gas
prices. The trading prices of the Trust Units from time to time is also
determined by a number of factors which are beyond the control of management
and such trading prices may be greater than the net asset value of our assets.
ADDITIONAL FINANCING
In the normal course of making capital investments to maintain and expand our
oil and gas reserves, additional Trust Units are issued from treasury which may
result in a decline in production per Trust Unit and reserves per Trust Unit.
Additionally, from time to time we issue Trust Units from treasury in order to
reduce debt and maintain a more optimal capital structure. To the extent that
external sources of capital, including the issuance of additional Trust Units,
become limited or unavailable, our ability and AOG's ability to make the
necessary capital investments to maintain or expand our oil and gas reserves
will be impaired. To the extent that the Trust and AOG are required to use cash
flow to finance capital expenditures or property acquisitions or to pay debt
service charges or to reduce debt, the level of distributable income will be
reduced.
COMPETITION
There is strong competition relating to all aspects of the oil and gas
industry. There are numerous trusts in the oil and gas industry, who are
competing for the acquisitions of properties with longer life reserves and
properties with exploitation and development opportunities. As a result of such
increasing competition, it will be more difficult to acquire reserves on
beneficial terms. The Trust and AOG also compete for reserve acquisitions and
skilled industry personnel with a substantial number of other oil and gas
companies, many of which have significantly greater financial and other
resources than the Trust and AOG.
RETURN OF CAPITAL
Trust Units will have no value when reserves from the Properties can no longer
be economically produced and, as a result, cash distributions do not represent
a "yield" in the traditional sense and are not comparable to bonds or other
fixed yield securities, where investors are entitled to a full return of the
principal amount of debt on maturity in addition to a 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
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may not be listed on any stock exchange and a market may not develop for such
securities. In addition, there may be resale restrictions imposed by law upon
the recipients of the securities pursuant to the redemption right.
REDEMPTION RIGHT
It is anticipated that the redemption right will not be the primary mechanism
for Unitholders to liquidate their investments. Long Term Notes or Redemption
Notes which may be distributed IN SPECIE to Unitholders in connection with a
redemption will not be listed on any stock exchange and no established market
is expected to develop for such Long Term Notes or Redemption Notes. Cash
redemptions are subject to limitations. See "ADDITIONAL INFORMATION RESPECTING
ADVANTAGE ENERGY INCOME FUND - REDEMPTION RIGHT".
UNITHOLDER LIMITED LIABILITY
The Trust Indenture provides that no 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.
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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.
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.
Additionally, the reduced "Qualified Dividend" rate of 15% tax applied to our
distributions under current U.S. tax laws is scheduled to expire at the end of
2010 and there is no assurance that this reduced tax rate will be renewed by
the U.S. government at such time.
Furthermore, it is unclear what impact the proposed changes relating to the
October 31, 2006 Proposals will have on the taxation of cash distributions or
other property paid by the Trust to unitholders who are not residents of
Canada.
NON-RESIDENT UNITHOLDERS ARE SUBJECT TO FOREIGN EXCHANGE RISK ON THE
DISTRIBUTIONS THAT THEY MAY RECEIVE FROM THE TRUST.
Distributions from the Trust are declared in Canadian dollars and converted to
foreign denominated currencies at the spot exchange rate at the time of
payment. As a consequence, investors are subject to foreign exchange risk. To
the extent that the Canadian dollar weakens with respect to the currency of a
non-resident, the amount of the distribution will be reduced when converted to
the home currency of a non-resident.
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
76
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, 2006. Documents affecting the rights of securityholders,
along with additional information relating to Advantage, may be found on SEDAR
at www.sedar.com.
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SCHEDULE "A"
REPORT OF MANAGEMENT AND DIRECTORS ON RESERVES DATA AND OTHER INFORMATION
Management of the Trust are responsible for the preparation and disclosure of
information with respect to the Trust's oil and gas activities in accordance
with securities regulatory requirements. This information includes reserves
data, which consist of the following:
(a) (i) proved and proved plus probable oil and gas reserves
estimated as at December 31, 2006 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, 2006 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.
/s/ Kelly I. Drader /s/ Peter A. Hanrahan
- ------------------------------ --------------------------------
Kelly I. Drader Peter A. Hanrahan
Chief Executive Officer Vice President, Finance and Chief
Financial Officer
/s/ Ronald A. Mcintosh /s/ John Howard
- ------------------------------ --------------------------------
Ronald A. McIntosh John Howard
Director Director
March 21, 2007
SCHEDULE "B"
FORM 51-101F2 - REPORT ON RESERVES DATA
BY INDEPENDENT QUALIFIED RESERVES EVALUATOR OR AUDITOR
To the board of directors of Advantage Energy Income Fund (the "TRUST"):
1. We have evaluated the Trust's reserves data as at December 31, 2006. The
reserves data consist of the following:
(a) (i) proved and proved plus probable oil and gas reserves
estimated as at December 31, 2006 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, 2006
using constant prices and costs; and
(ii) the related estimated future net revenue.
2. The reserves data are the responsibility of the Trust's management. Our
responsibility is to express an opinion on the reserves data based on our
evaluation.
We carried out our evaluation in accordance with standards set out in the
Canadian Oil and Gas Evaluation Handbook (the "COGE HANDBOOK") prepared
jointly by the Society of Petroleum Evaluation Engineers (Calgary
Chapter) and the Canadian Institute of Mining, Metallurgy & Petroleum
(Petroleum Society).
3. Those standards require that we plan and perform an evaluation to obtain
reasonable assurance as to whether the reserves data are free of material
misstatement. An evaluation also includes assessing whether the reserves
data are in accordance with principles and definitions presented in the
COGE Handbook.
4. The following table sets forth the estimated future net revenue
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, 2006, and identifies the respective portions thereof
that we have audited, evaluated and reviewed and reported on to the
Trust's management and 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
Reserves of Advantage Energy
Income Fund as of December
31, 2006 prepared October
2006 to March 2007
TOTAL 170,226 1,679,848 Nil 1,850,074
5. In our opinion, the reserves data respectively evaluated by us have, in
all material respects, been determined and are presented in accordance
with the COGE Handbook.
6. We have no responsibility to update the report 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.
/s/ Sproule Associates Limited
- ----------------------------------
SPROULE ASSOCIATES LIMITED
Calgary, Alberta
March 9, 2007