EXHIBIT 99.1
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ADVANTAGE ENERGY INCOME FUND
ANNUAL INFORMATION FORM
YEAR ENDED DECEMBER 31, 2007
March 28, 2008
TABLE OF CONTENTS
PAGE
GLOSSARY OF TERMS..............................................................1
ABBREVIATIONS..................................................................4
CONVERSION.....................................................................4
ADVANTAGE ENERGY INCOME FUND...................................................6
GENERAL DEVELOPMENT OF THE BUSINESS............................................7
DESCRIPTION OF OUR BUSINESS AND OPERATIONS....................................10
STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION..................12
ADDITIONAL INFORMATION RESPECTING ADVANTAGE ENERGY INCOME FUND................34
ADDITIONAL INFORMATION RESPECTING ADVANTAGE OIL & GAS LTD.....................41
MARKET FOR SECURITIES.........................................................49
ESCROWED SECURITIES...........................................................53
LEGAL PROCEEDINGS.............................................................53
REGULATORY ACTIONS............................................................53
INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS....................54
MATERIAL CONTRACTS............................................................54
INTEREST OF EXPERTS...........................................................54
AUDITORS, TRANSFER AGENT AND REGISTRAR........................................54
AUDIT COMMITTEE INFORMATION...................................................54
AUDIT COMMITTEE CHARTER.......................................................55
AUDIT SERVICE FEES............................................................60
INDUSTRY CONDITIONS...........................................................60
RISK FACTORS..................................................................66
DISCLOSURE PURSUANT TO THE REQUIREMENTS OF THE NEW YORK STOCK EXCHANGE........78
ADDITIONAL INFORMATION........................................................79
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;
"8.00% DEBENTURES" means 8.00% convertible unsecured subordinated debentures of
the Trust due December 31, 2011;
"8.25% DEBENTURES" means 8.25% convertible unsecured subordinated debentures of
the Trust due February 1, 2009;
"8.75% DEBENTURES" means 8.75% convertible unsecured subordinated debentures of
the Trust due June 30, 2009;
"9.00% DEBENTURES" means 9.00% convertible unsecured subordinated debentures of
the Trust due August 1, 2008;
"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;
"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., AIM, 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;
"COMMON SHARES" means the common shares of AOG;
"DEBENTURES" means, collectively, the 6.50% Debentures, 7.50% Debentures, 7.75%
Debentures, 8.00% Debentures, 8.25% Debentures, 8.75% Debentures and 9.00%
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 the Trustee, 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 the Trustee 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 the Trustee providing for the issue of Medium Term
Notes;
"MEDIUM TERM NOTES" means the unsecured subordinated promissory notes of AOG
issued to us from time to time under the Medium Term Note Indenture;
"NOTE INDENTURES" means, collectively, the Long Term Note Indenture and the
Medium Term Note Indenture;
"NOTE TRUSTEE" means Computershare Trust Company of Canada, or its successor as
trustee under the Note Indentures;
"NOTES" means the unsecured subordinated promissory notes of AOG issued to us
from time to time under the Note Indentures;
"NYSE" means the New York Stock Exchange;
"OIL AND NATURAL GAS PROPERTIES" or "PROPERTIES" means the working, royalty or
other interests of AOG in any petroleum and natural gas rights, tangibles and
miscellaneous interests, including properties which may be acquired by AOG from
time to time;
"PERMITTED INVESTMENTS" means, with respect to up to 25% of our total assets,
(unless otherwise approved by the AOG Board of Directors from time to time):
(i) obligations issued or guaranteed by the government of Canada or any
province of Canada or any agency or instrumentality thereof; (ii) term
deposits, guaranteed investment certificates, certificates of deposit or
bankers' acceptances of or guaranteed by any Canadian chartered bank or other
financial institutions (including the Trustee and any affiliate of the Trustee)
the short-term debt or deposits of which have been rated at least A or the
equivalent by Standard & Poor's Corporation, Moody's Investors Service, Inc. or
Dominion Bond Rating Service Limited; (iii) commercial paper rated at least A
or the equivalent by Dominion Bond Rating Service Limited, in each case
maturing within 180 days after the date of acquisition; and (iv) trust units
and limited partnership units in trusts and limited partnerships which invest
in energy related assets including all types of petroleum and natural gas and
energy related assets, and including, without limitation, facilities of any
kind, oil sands interests, coal, electricity or power generating assets, and
pipeline, gathering, processing and transportation assets;
"PETROLEUM SUBSTANCES" means petroleum, natural gas and related hydrocarbons
(except coal) including, without limitation, all liquid hydrocarbons, and all
other substances, including sulphur, whether gaseous, liquid or solid and
whether hydrocarbon or not, produced in association with such petroleum,
natural gas or related hydrocarbons;
"RESOURCE PROPERTIES" means Canadian resource properties as defined in the Tax
Act;
"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;
"SET" means SET Resources Inc.;
"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;
"SOUND" means Sound Resources Trust;
3
"SOUND ARRANGEMENT" means the plan of arrangement involving Advantage, AOG,
Sound and SET, various subsidiaries of Advantage, AOG, Sound and SET, holders
of trust units of Sound and holders of exchangeable shares of SET, completed on
September 5, 2007;
"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;
"TAX ACT" means the INCOME TAX ACT (Canada), R.S.C. 1985, c.1 (5th Supp), as
amended, including the regulations thereunder;
"TRUST FUND", at any time, shall mean such of the following monies, properties
and assets that are at such time held by the Trustee for the purposes of the
Trust under the Trust Indenture: (i) the Settled Amount; (ii) the Initial
Permitted Securities; (iii) the Royalty; (iv) all funds realized from the sale
of, or Permitted Investments obtained in exchange for, Trust Units from time to
time; (v) any Permitted Investments in which funds may from time to time be
invested; (vi) any Subsequent Investments; (vii) any proceeds of disposition of
any of the foregoing property including, without limitation, the Royalty but
not Trust Units in the case of a redemption thereof to which Section 9.5 of the
Trust Indenture applies; and (viii) all income, interest, dividends, return of
capital, profit, gains and accretions and additional assets, rights and
benefits of any kind or nature whatsoever arising directly or indirectly from
or in connection with or accretions to or accruals in respect of any of the
foregoing property or such proceeds of disposition from time to time;
"TRUST INDENTURE" means the trust indenture between Computershare Trust Company
of Canada and AOG made effective as of April 17, 2001, supplemented as of May
22, 2002 and amended and restated as of June 25, 2002, May 28, 2002, May 26,
2004, April 27, 2005, December 13, 2005, June 23, 2006 and December 31, 2007,
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;
"TRUSTEE" means Computershare Trust Company of Canada or its successor or
successors as trustee under the Trust Indenture;
"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
Trustee, as transfer agent of the Trust Units, 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.
4
ABBREVIATIONS
OIL AND NATURAL GAS LIQUIDS NATURAL GAS
bbls barrels Mcf thousand cubic feet
Mbbls thousand barrels MMcf million cubic feet
MMbbls million barrels bcf billion cubic feet
NGLs natural gas liquids Mcf/d thousand cubic feet per day
stb stock tank barrels of oil MMcf/d million cubic feet per day
Mstb thousand stock tank barrels of oil m(3) cubic metres
MMboe million barrels of oil equivalent MMbtu million British Thermal Units
boe/d barrels of oil equivalent per day GJ Gigajoule
bbls/d barrels of oil per day
OTHER
BOEor boe means barrel of oil equivalent, using the conversion
factor of 6 Mcf of natural gas being equivalent to one bbl of
oil. The conversion factor used to convert natural gas to oil
equivalent is not necessarily based upon either energy or price
equivalents at this time.
WTI means West Texas Intermediate.
(Degree)API means the measure of the density or gravity of liquid petroleum
products derived from a specific gravity.
psi means pounds per square inch.
CONVERSION
The following table sets forth certain conversions between Standard Imperial
Units and the International System of Units (or metric units).
TO CONVERT FROM TO MULTIPLY BY
Mcf cubic metres 28.174
cubic metres cubic feet 35.494
bbls cubic metres 0.159
cubic metres bbls 6.293
feet metres 0.305
metres feet 3.281
miles kilometres 1.609
kilometres miles 0.621
acres hectares 0.405
hectares acres 2.471
gigajoules MMbtu 0.950
5
YOU SHOULD NOT RELY ON FORWARD-LOOKING STATEMENTS
BECAUSE THEY ARE INHERENTLY UNCERTAIN
Certain statements contained in this annual information form, and in certain
documents incorporated by reference into this annual information form,
constitute forward-looking statements. These statements relate to future events
or our future performance. All statements other than statements of historical
fact may be forward-looking statements. Forward-looking statements are often,
but not always, identified by the use of words such as "seek", "anticipate",
"plan", "continue", "estimate", "expect", "may", "will", "project", "predict",
"potential", "targeting", "intend", "could", "might", "should", "believe" and
similar expressions. These statements involve known and unknown risks,
uncertainties and other factors that may cause actual results or events to
differ materially from those anticipated in such forward-looking statements. We
and AOG believe the expectations reflected in those forward-looking statements
are reasonable but no assurance can be given that these expectations will prove
to be correct and such forward-looking statements included in, or incorporated
by reference into, this annual information form should not be unduly relied
upon. These statements speak only as of the date of this annual information
form or as of the date specified in the documents incorporated by reference
into this annual information form, as the case may be.
In particular, this annual information form, and the documents incorporated by
reference, contain forward-looking statements pertaining to the following:
o the performance characteristics of our assets;
o oil and natural gas production levels;
o the size of the oil and natural gas reserves;
o projections of market prices and costs and the related sensitivities of
distributions;
o supply and demand for oil and natural gas;
o expectations regarding the ability to raise capital and to continually add
to reserves through acquisitions and development;
o treatment under governmental regulatory regimes; and
o capital expenditures programs.
The actual results could differ materially from those anticipated in these
forward-looking statements as a result of the risk factors set forth below and
elsewhere in this annual information form:
o volatility in market prices for oil and natural gas;
o liabilities inherent in oil and natural gas operations;
o uncertainties associated with estimating oil and natural gas reserves;
o competition for, among other things, capital, acquisitions of reserves,
undeveloped lands and skilled personnel;
o incorrect assessments of the value of acquisitions;
o fluctuation in foreign exchange or interest rates;
o stock market volatility and market valuations;
o changes in income tax laws or changes in tax laws and incentive programs
relating to the oil and gas industry and income trusts;
o geological, technical, drilling and processing problems and other
difficulties in producing petroleum reserves; and
o the other factors discussed under "RISK FACTORS".
Statements relating to "reserves" or "resources" are deemed to be
forward-looking statements, as they involve the implied assessment, based on
certain estimates and assumptions, that the resources and reserves described
can be profitably produced in the future. Readers are cautioned that the
foregoing lists of factors are not exhaustive. The forward looking statements
contained in this annual information form and the documents incorporated by
reference herein are expressly qualified by this cautionary statement. Except
as required by law, neither the Trust or 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 initially valued at $39.1 million, paid through the issuance of
1,933,208 Trust Units which have been placed in escrow and are releasable as to
one-third on each of the first three anniversaries of the Arrangement.
Effective September 5, 2007, Advantage and Sound completed the Sound
Arrangement whereby Advantage acquired all of the issued and outstanding trust
units of Sound and exchangeable shares of SET for consideration of either (i)
0.30 of a Unit; or (ii) $0.66 in cash and 0.2557 of a Unit, for each Sound
trust unit or SET exchangeable share held. In connection with the Sound
Arrangement, SET, AOG and various other subsidiaries of Advantage, AOG, SET and
Sound amalgamated to form "Advantage Oil & Gas Ltd." See "GENERAL DEVELOPMENT
OF THE BUSINESS".
Our head office, the head office of AOG and the registered office of AOG is
located at Suite 700, 400, 3 Avenue S.W., Calgary, Alberta T2P 4H2.
7
OUR ORGANIZATIONAL STRUCTURE
The following diagram sets forth our organizational structure as at the date
hereof.
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ADVANTAGE
UNITHOLDERS(1)
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Cash ^ ^ |
Distributions | | | Advantage Units
| | | (100%)
| |Income from |
| |Permitted |
| |Investment |
| | |
| | |
| | /\ |
| | / \ |
| | / \ |
| | / \ |
| |/ \ |
| / \ |
| / \ v
| / \
/ \
/ ADVANTAGE ENERGY \
/ INCOME FUND(2)(3) \
/ (Alberta) \
/ \
--------------------------
^ |
| |
| Interest and | royalty,
| pricipal payments, | notes,
| royalty payments | 100%
| and dividends on | shares
| common shares |
| v
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ADVANTAGE OIL & GAS LTD.
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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 principal and interest payments from the Advantage
Notes and dividends from the Common Shares.
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
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.
8
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". The
listing on the NYSE has resulted 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%.
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.
2007
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.
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 $104.1 million were used to pay down bank
indebtedness and to fund capital and general corporate expenditures.
On June 22, 2007, new legislation was passed pursuant to which, commencing
January 1, 2011 (provided that we only experience "normal growth" and no "undue
expansion" before then) certain distributions will be subject to at trust-level
tax, and will be characterized as dividends to the unitholders. See "RISK
FACTORS - CHANGES IN LEGISLATION - SIFT TAX".
On July 9, 2007 Advantage and Sound jointly announced that their respective
boards of directors had approved the Sound Arrangement. On September 5, 2007,
the Sound Arrangement was approved by the holders of trust units of Sound
("SOUND UNITS") and holders of exchangeable shares of SET ("SOUND EXCHANGEABLE
SHARES") and Advantage completed the acquisition of all of the outstanding
Sound Units and Sound Exchangeable Shares. Pursuant to the Sound Arrangement,
holders of Sound Units received 0.30 of a Unit for each Sound Unit held or, at
the election of the holder of Sound Units ("SOUND UNITHOLDERS"), $0.66 in cash
and 0.2557 of a Unit. In addition, all Sound Exchangeable Shares were exchanged
for Units or Units and cash at the election of the holders of Sound
Exchangeable Shares on the same terms as those offered to Sound Unitholders
based on the exchange ratio in effect at the effective date of the Sound
Arrangement. In total 16,977,184 Units and $21.4 million in cash was issued to
holders of Sound Units and Sound Exchangeable Shares. In addition, Advantage
also assumed approximately $108.0 million of bank indebtedness upon closing of
the Sound Arrangement. See "SIGNIFICANT ACQUISITIONS" below.
9
On August 16, 2007, we announced that Stephen Balog had been appointed to the
Board of Directors of AOG.
We negotiated an increase to our credit facilities in September of 2007 and
currently have a $710 million credit facility agreement consisting of a $690
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 September 18, 2007, our former auditors KPMG LLP resigned as auditors of the
Trust and PricewaterhouseCoopers LLP were appointed the auditors of the Trust.
On December 14, 2007, Advantage announced that in light of the recent strength
of the Canadian dollar combined with the continuing weakness in crude oil and
natural gas prices, the Board of Directors of Advantage felt it is prudent to
adjust the cash distribution beginning with the month of December to $0.12 per
Unit from the current $0.15 per Unit.
On December 14, 2007, we also announced that the Board of Directors of AOG
approved our 2008 capital expenditure budget at between $130 and $145 million.
RECENT DEVELOPMENTS
Advantage has completed additional hedging for 2008 and 2009 to (i) stabilize
cash flows and (ii) ensure that the Trust's capital program is substantially
funded out of cash flow. Approximately 53% (net of royalties) of Advantage's
natural gas is hedged for the 2008 calendar year at a floor of $7.52/mcf.
Advantage also hedged 38% (net of royalties) of its 2008 crude oil production
at an average price of $94.07/bbl.
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 2008 financial year.
SIGNIFICANT ACQUISITIONS
On September 5, 2007, Advantage completed the acquisition of all of the Sound
Units and Sound Exchangeable Shares. Pursuant to the Arrangement, holders of
Sound Units received 0.30 of a Unit for each Sound Unit held or, at the
election of the Sound Unitholders, $0.66 in cash and 0.2557 of a Unit. In
addition, all Sound Exchangeable Shares were exchanged for Units or Units and
cash at the election of the Sound Exchangeable Shareholder on the same terms as
those offered to Sound Unitholders based on the exchange ratio in effect at the
effective date of the Sound Arrangement. In total 16,977,184 Units and $21.4
million in cash was issued to holders of Sound Units and Sound Exchangeable
Shares. In addition, Advantage also assumed approximately $108.0 million of
bank indebtedness upon closing of the Sound Arrangement.
On completion of the Sound Arrangement, Sound became an indirect wholly-owned
subsidiary of AOG and as part of the Sound Arrangement, certain assets owned by
Sound and SET were transferred to Advantage and AOG and SET was amalgamated
with Sound ExchangeCo Ltd, 1135703 Alberta Ltd. and AOG to form "Advantage Oil
& Gas Ltd."
Prior to completion of the Sound Arrangement, the Sound Units traded on the TSX
under the symbol SND.UN and the debentures issued by Sound (the "SOUND
DEBENTURES") traded on the TSX under the symbols SND.DB and SND.DB.A. Following
completion of the Arrangement, the Sound Units were delisted from trading on
the TSX and Advantage assumed all of Sound's covenants and obligations with
respect to the outstanding Sound Debentures. The debentures now trade on the
TSX under the symbols "AVN.DB.F" and "AVN.DB.G" for the 8.75% Debentures and
the 8.00% Debentures, respectively. Advantage made an offer to purchase all of
the outstanding 8.75% Debentures and 8.00% Debentures at a price equal to 101%
of the principal amount plus any accrued and unpaid interest. Pursuant to the
offer, $35,958,000 principal amount of 8.75% Debentures and 8.00% Debentures
plus accrued and unpaid interest were tendered in exchange for the issuance of
3,131,998 Trust Units, and $19,214,000 principal amount of 8.75% Debentures
plus accrued and unpaid interest were tendered for cash. The Trust Units issued
and cash paid represented 101% of the tendered 8.75% Debentures and 8.00%
Debentures principal amount plus accrued and unpaid interest for July 1 to
October 18, 2007.
10
The Sound Arrangement had the effect of improving Advantage's payout ratio and
provided substantial operating synergies for the combined trust. The combined
entity has a significant prospect inventory and an undeveloped land position of
approximately 686,000 net acres, providing significant growth opportunities,
complementary winter/summer drilling programs, a reduction in general
administration costs, and further control and synergies in the common combined
properties. Unitholders benefited through the addition of Sound's tax pools of
approximately $394 million, a 30% increase, for combined tax pools in excess of
approximately $1.7 billion at December 31, 2007. The combined entity had a 2007
exit rate production of approximately 34,300 boe/d weighted 63% natural gas and
37% light oil and NGLs. The combined entity also has a Proved plus Probable
Reserve Life Index of approximately 12.1 years using average 2007 fourth
quarter production and December 31, 2007 proved plus probable reserves.
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 Tax Act or are a
"small business security" as that expression is used in Part LI of the
Regulations to the Tax Act or would result in us not being considered
either a "unit trust" or a "mutual fund trust" for purposes of the Tax
Act at the time such investment was made;
2. disposing of any part of the Trust Fund, including, without limitation,
any Permitted Investments;
3. acquiring the Royalty and other royalties in respect of Resource
Properties;
4. temporarily holding cash, and Permitted Investments (including
investments in AOG) for the purposes of paying Trust expenses and Trust
liabilities, paying amounts payable by us in connection with the
redemption of any Trust Units, and making distributions to Unitholders;
5. acquiring or investing in securities of AOG or any other subsidiary of
ours to fund the acquisition, development, exploitation and disposition
of all types of petroleum and natural gas related assets, including,
without limitation, facilities of any kind and whether effected through
the acquisition of assets or the acquisition of shares or other form of
ownership interest in any entity, the substantial majority of the
assets of which are comprised of like assets;
6. undertaking such other business and activities including investing in
securities as shall be approved by AOG from time to time provided that
we shall not undertake any business or activity which is a Prohibited
Investment (as defined in the Trust Indenture);
and to pay the costs, fees and expenses associated therewith or incidental
thereto.
In accordance with the terms of the Trust Indenture, we will make cash
distributions to our Unitholders of the interest income earned from the Long
Term Notes 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.
11
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.
REORGANIZATIONS
Other than the Arrangement and the Sound Arrangement, there have been no
material reorganizations of Advantage or AOG and or any of our subsidiaries
within the three most recently completed financial years or proposed for the
current financial year.
12
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, 2007. The effective date of the
Statement is December 31, 2007 and the preparation date of the Statement is
February 21, 2008.
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, 2007 contained in
a report of Sproule dated February 21, 2008 (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
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 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.
SUMMARY OF OIL AND GAS RESERVES
as of December 31, 2007
FORECAST PRICES AND COSTS
RESERVES
-------------------------------------------------
LIGHT AND MEDIUM OIL HEAVY OIL
---------------------- --------------------
Gross Net Gross Net
RESERVES CATEGORY (Mbbl) (Mbbl) (Mbbl) (Mbbl)
- ----------------- ------ ------ ------ ------
PROVED
Developed Producing 22,060 19,670 1,814 1,631
Developed Non-Producing 473 392 126 107
Undeveloped 3,621 2,915 297 262
------ ------ ----- -----
TOTAL PROVED 26,154 22,977 2,237 2,000
PROBABLE 17,477 14,891 3,271 3,061
------ ------ ----- -----
TOTAL PROVED PLUS PROBABLE 43,630 37,869 5,508 5,061
====== ====== ===== =====
13
RESERVES
--------------------------------------------------
NATURAL GAS NATURAL GAS LIQUIDS
---------------------- ---------------------
Gross Net Gross Net
RESERVES CATEGORY (MMcf) (MMcf) (Mbbl) (Mbbl)
- ----------------- ------ ------ ------ ------
PROVED
Developed Producing 285,551 235,061 6,646 4,883
Developed Non-Producing 12,814 10,291 266 193
Undeveloped 52,568 41,340 928 695
------- ------- ------ -----
TOTAL PROVED 350,933 286,693 7,840 5,772
PROBABLE 190,613 150,765 3,773 2,784
------- ------- ------ -----
TOTAL PROVED PLUS PROBABLE 541,545 437,457 11,613 8,555
======= ======= ====== =====
RESERVES
----------------------
TOTAL OIL EQUIVALENT
----------------------
Gross Net
RESERVES CATEGORY (Mboe) (Mboe)
- ----------------- ------ ------
PROVED
Developed Producing 78,111 65,360
Developed Non-Producing 3,001 2,408
Undeveloped 13,608 10,763
------- -------
TOTAL PROVED 94,720 78,531
PROBABLE 56,289 45,864
------- -------
TOTAL PROVED PLUS PROBABLE 151,009 124,395
======= =======
SUMMARY OF NET PRESENT VALUES OF FUTURE NET REVENUE
as at December 31, 2007
FORECAST PRICES AND COSTS
Unit Value
Before
Income Tax
Discounted
at 10%/
Before Income Tax Discounted at (%/year) After Income Taxes Discounted at (%/year) year(1)
----------------------------------------------- ---------------------------------------------- ----------
0% 5% 10% 15% 20% 0% 5% 10% 15% 20%
RESERVES CATEGORY ($000's) ($000's) ($000's) ($000's) ($000's) ($000's) ($000's) ($000's) ($000's) ($000's) ($/boe)
- ----------------- -------- --------- -------- --------- -------- -------- --------- --------- --------- --------- -------
PROVED
Developed 2,680,441 1,904,687 1,526,798 1,296,565 1,138,260 2,680,441 1,904,687 1,526,798 1,296,565 1,138,260 23.36
Producing
Developed 83,654 67,773 56,479 48,078 41,610 83,654 67,773 56,479 48,078 41,610 23.46
Non-Producing
Undeveloped 298,697 217,260 155,502 111,869 80,524 298,697 217,260 155,502 111,869 80,524 14.45
--------- --------- --------- --------- --------- --------- --------- --------- --------- -------- -----
TOTAL PROVED 3,062,792 2,189,720 1,738,779 1,456,512 1,260,395 3,062,792 2,189,720 1,738,779 1,456,512 1,260,395 22.14
PROBABLE 2,038,534 1,100,987 723,831 524,663 402,141 1,725,277 1,009,488 691,311 511,544 396,373 15.78
--------- --------- --------- --------- --------- --------- --------- --------- --------- -------- -----
TOTAL PROVED PLUS
PROBABLE 5,101,326 3,290,707 2,462,610 1,981,175 1,662,536 4,788,069 3,199,208 2,430,090 1,968,056 1,656,76 19.80
========= ========= ========= ========= ========= ========= ========= ========= ========= ======== =====
Note:
(1) The unit values are based on net reserve volumes.
14
TOTAL FUTURE NET REVENUE
(UNDISCOUNTED)
as of December 31, 2007
FORECAST PRICES AND COSTS
FUTURE
FUTURE NET NET
REVENUE REVENUE
ABANDONMENT AND BEFORE AFTER
OPERATING DEVELOPMENT RECLAMATION INCOME INCOME INCOME
REVENUE ROYALTIES COSTS COSTS COSTS TAXES TAXES TAXES
RESERVES CATEGORY ($000's) ($000's) ($000's) ($000's) ($000's) ($000's) ($000's) ($000's)
----------------- -------- -------- -------- -------- -------- -------- -------- --------
Proved Reserves 5,949,781 965,309 1,632,590 190,146 98,945 3,062,792 0 3,062,792
Proved Plus Probable 9,876,777 1,632,999 2,627,152 386,792 128,508 5,101,326 313,257 4,788,068
Reserves
FUTURE NET REVENUE
BY PRODUCTION GROUP
as of December 31, 2007
FORECAST PRICES AND COSTS
FUTURE NET REVENUE
BEFORE INCOME TAXES
(discounted at
10%/year) UNIT VALUE
RESERVES CATEGORY PRODUCTION GROUP ($000's) ($/boe)
- ------------------- ---------------------------------------- -------------------- ----------
Proved Reserves Light and Medium Crude Oil (including 746,109 26.74
solution gas and other by-products)
Heavy Oil (including solution gas and 44,324 20.00
other by-products)
Natural Gas (including by-products but 904,625 19.91
excluding solution gas and by-products
from oil wells)
Non-Conventional Oil and Gas Activities 43,721 16.57
--------- -----
TOTAL 1,738,779 22.14
========= =====
Proved Plus Probable Light and Medium Crude Oil (including 1,099,825 24.24
Reserves solution gas and other by-products)
Heavy Oil (including solution gas and 87,990 16.36
other by-products)
Natural Gas (including by-products but 1,213,197 17.55
excluding solution gas and by-products
from oil wells)
Non-Conventional Oil and Gas Activities 61,598 15.88
--------- -----
TOTAL 2,462,610 19.80
PRICING ASSUMPTIONS
The following tables set forth the benchmark reference prices, as at December
31, 2007, 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.
15
SUMMARY OF PRICING AND INFLATION RATE ASSUMPTIONS(1)
as of December 31, 2007
FORECAST PRICES AND COSTS
Light
Sweet NATURAL NATURAL NATURAL
Crude Oil GAS GAS LIQUIDS GAS
WTI at Medium Hardisty AECO-C Edmonton LIQUIDS
Cushing Edmonton Crude Oil Heavy 12o Spot Pentanes Edmonton INFLATION EXCHANGE
Oklahoma 40o API 29o API API ($Cdn/ Plus Butanes RATES RATE (2)
Year ($US/bbl) ($Cdn/bbl) ($Cdn/bbl) ($Cdn/bbl) MMBtu) ($Cdn/bbl) ($Cdn/bbl) %/Year ($US/$Cdn)
---- --------- ---------- ---------- ---------- ------ ---------- ---------- ------ ----------
Forecast(3)
2008 89.61 88.17 75.83 54.67 6.51 90.30 65.72 2.0 1.000
2009 86.01 84.54 72.71 52.42 7.22 86.58 63.01 2.0 1.000
2010 84.65 83.16 71.52 51.56 7.69 85.17 61.98 2.0 1.000
2011 82.77 81.26 69.89 50.38 7.70 83.23 60.57 2.0 1.000
2012 82.26 80.73 69.43 50.05 7.61 82.68 60.17 2.0 1.000
2013 82.81 81.25 69.88 50.38 7.78 83.21 60.56 2.0 1.000
2014 84.46 82.88 71.28 51.39 7.96 84.88 61.78 2.0 1.000
2015 86.15 84.55 72.71 52.42 8.14 86.59 63.02 2.0 1.000
2016 87.87 86.25 74.17 53.47 8.32 88.33 64.28 2.0 1.000
2017 89.63 87.98 75.66 54.55 8.51 90.10 65.58 2.0 1.000
2018 91.42 89.74 77.17 55.64 8.68 91.90 66.89 2.0 1.000
Thereafter +2%/year +2%/year +2%/year +2%/year +2%/year +2%/year +2%/year +2%/year 1.000
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.
Weighted average historical prices, including hedging, realized by us for the
year ended December 31, 2007, were $7.21/Mcf for natural gas, $66.92/bbl for
crude oil, and $60.12/bbl for natural gas liquids.
RECONCILIATIONS OF CHANGES IN RESERVES AND FUTURE NET REVENUE
RECONCILIATION OF
COMPANY GROSS RESERVES
BY 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, 2006 19,935 13,586 33,521 1,908 688 2,596 7,375 3,833 11,208
Extensions 327 1,340 1,667 55 13 68 232 287 519
Improved Recovery 678 644 1,322 0 0 0 197 349 546
Technical Revisions 177 (1,448) (1,271) (562) (112) (674) (95) (1,015) (1,110)
Discoveries 24 17 41 0 0 0 9 2 11
Acquisitions 7,348 3,214 10,562 1,083 2,681 3,764 1,093 345 1,438
Dispositions 0 0 0 0 0 0 0 0 0
Economic Factors 370 123 493 1 1 2 (105) (28) (133)
Production (2,705) 0 (2,705) (248) 0 (248) (866) 0 (866)
------ ------ ------ ----- ----- ----- ----- ----- ------
December 31, 2007 26,154 17,476 43,630 2,237 3,271 5,508 7,840 3,773 11,613
====== ====== ====== ===== ===== ===== ===== ===== ======
16
Associated and Non-Associated Gas Natural Gas - Solution
--------------------------------- -------------------------------
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, 2006 252,290 122,334 374,624 34,648 19,335 53,983
Extensions 9,988 12,411 22,399 1,387 1,443 2,830
Improved Recovery 12,071 27,406 39,477 1,633 1,833 3,466
Technical Revisions 519 (22,926) (22,407) (4,137) (6,096) (10,233)
Discoveries 636 159 795 0 0 0
Acquisitions 59,907 21,657 81,564 5,130 2,999 8,129
Dispositions 0 0 0 0 0 0
Economic Factors (1,194) 1,446 252 589 167 756
Production (35,258) 0 (35,258) (5,268) 0 (5,268)
------- ------- ------- ------ ------ ------
December 31, 2007 298,959 162,487 461,446 33,982 19,681 53,663
======= ======= ======= ====== ====== ======
Coalbed Methane Oil Equivalent
------------------------------- ------------------------------
WI WI
Proved Proved
WI WI Plus WI WI Plus
Proved Probable Probable Proved Probable Probable
FACTORS (mmcf) (mmcf) (mmcf) (MBoe) (MBoe) (MBoe)
------- ------- ------- ====== ======== ========
December 31, 2006 5,841 4,896 10,737 78,015 42,534 120,549
Extensions 3,319 1,643 4,962 3,062 4,223 7,285
Improved Recovery 1,012 238 1,250 3,328 5,906 9,234
Technical Revisions 908 (777) 131 (930) (7,542) (8,472)
Discoveries 0 0 0 139 45 184
Acquisitions 9,057 2,438 11,495 21,872 10,756 32,628
Dispositions 0 0 0 0 0 0
Economic Factors 33 7 40 170 367 537
Production (2,178) 0 (2,178) (10,936) 0 (10,936)
------- ------- ------- ------ ------ ------
December 31, 2007 17,992 8,445 26,437 94,720 56,289 151,009
======= ======= ======= ====== ====== ======
Notes:
(1) Volumes related to infill drilling are included in the Improved Recovery
category, noted above.
ADDITIONAL INFORMATION RELATING TO RESERVES DATA
UNDEVELOPED RESERVES
Undeveloped reserves are attributed by Sproule in accordance with standards and
procedures contained in the COGE Handbook. Proved undeveloped reserves are
those reserves that can be estimated with a high degree of certainty and are
expected to be recovered from known accumulations where a significant
expenditure is required to render them capable of production. Probable
undeveloped reserves are those reserves that are less certain to be recovered
than proved reserves and are expected to be recovered from known accumulations
where a significant expenditure is required to render them capable of
production. 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.
In some cases, it will take longer than two years to develop these reserves.
There are a number of factors that could result in delayed or cancelled
development, including the following: (i) changing economic conditions (due to
pricing, operating and capital expenditure fluctuations); (ii) changing
technical conditions (including production anomalies, such as water
breakthrough or accelerated depletion); (iii) multi-zone developments (for
instance, a prospective formation completion may be delayed until the initial
completion is no longer economic); (iv) a larger development program may need
to be spread out
17
over several years to optimize capital allocation and facility utilization; and
(v) surface access issues (including those relating to land owners, weather
conditions and regulatory approvals). For more information, see "Risk Factors".
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 NGLs
Year (Mbbl) (Mbbl) (MMcf) (Mbbl)
- --------------- ----------------------- ------------------------ ----------------------- -----------------------
First Cumulative First Cumulative First Cumulative First Cumulative
Attributed at Year End Attributed at Year End Attributed at Year End Attributed at Year End
---------- ----------- ---------- ----------- ---------- ----------- ---------- -----------
2004 1,053 1,053 0 0 1,733 1,733 181 181
2005 319 1,372 0 0 2,529 4,262 30 211
2006 1,047 2,419 0 0 10,547 14,809 576 787
2007 1,371 3,790 297 297 30,056 44,865 308 1,095
Sproule has assigned 13.6 MMboe of proven undeveloped reserves in the Sproule
Report under forecast prices and costs, together with $177 million of
associated undiscounted future capital expenditures. Proven undeveloped capital
spending in the first two forecast years of the Sproule Report accounts for
$142 million, or 80 percent, of the total forecast. These figures increase to
$176 million or 99 percent, during the first five years of the Sproule Report.
PROBABLE UNDEVELOPED RESERVES
Light and Medium Oil Heavy Oil Natural Gas NGLs
Year (Mbbl) (Mbbl) (MMcf) (Mbbl)
- --------------- ----------------------- ------------------------ ----------------------- -----------------------
First Cumulative First Cumulative First Cumulative First Cumulative
Attributed at Year End Attributed at Year End Attributed at Year End Attributed at Year End
---------- ----------- ---------- ----------- ---------- ----------- ---------- -----------
2004 265 265 0 0 1,945 1,945 126 126
2005 764 1,029 0 0 11,109 13,054 320 446
2006 748 1,777 0 0 18,049 31,103 572 1,018
2007 2,410 4,187 2,312 2,312 40,261 71,364 528 1,546
Sproule has assigned 26.6 MMboe of probable undeveloped reserves and has
allocated future development capital of $194 million to all probable
undeveloped reserves with $193 million scheduled for the first five years.
SIGNIFICANT FACTORS OR UNCERTAINTIES
High operating costs substantially reduce our netback, which in turn reduces
the amount of cash available for reinvestment in drilling opportunities. This
becomes most relevant during periods of low commodity prices when profits are
more significantly impacted by high costs.
18
FUTURE DEVELOPMENT COSTS
The following table sets forth development costs deducted in the estimation of
our future net revenue attributable to the reserve categories noted below.
Forecast Prices and Costs
------------------------------------------
Proved Reserves Proved Plus Probable
Year (MM$) Reserves (MM$)
- --------------------------------- --------------- --------------------
2008 93 153
2009 62 161
2010 31 60
2011 4 5
2012 0 7
Total: Undiscounted for all years 190 387
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 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.
There can be no guarantee that funds will be available or that we will allocate
funding to develop all of the reserves attributed in the Sproule Report.
Failure to develop those reserves would have a negative impact on future
production and cash flow and could result in negative revisions to our
reserves.
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 29% of
our reserves. A further 62% of production and 60% of reserves are natural gas.
Rates referenced in the following property descriptions are as of December 31,
2007 unless otherwise noted and reserves quoted are as reported in the Sproule
Report to December 31, 2007.
MARTIN CREEK, BLACK AND CONROY, BRITISH COLUMBIA
The Martin Creek property is located approximately 100 kilometres northwest of
Fort St. John, British Columbia. 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 1 and the end of March each season. In the latest winter
program beginning in January 2008, 10 wells averaging 95% working interest were
drilled in the Conroy area in the northern part of the property. These wells
were successful in multiple zones including the Cretaceous Bluesky Formation as
well as reservoirs within the Triassic Charlie Lake Formation. These zones
occur at moderate depths between 800 to 1,300 metres. All 10 wells in the 2008
program were cased with 9 of these completed and tied in along with one
additional well from the 2007 program being tied in as well. Total production
prior to this winter's drilling program from the greater Martin Creek,
including the Black - Conroy areas is approximately 18 MMcf/d or 3,000 boe/d.
Additional
19
facilities, pipeline and compression options will be scoped in 2008 to handle
subsequent anticipated volumes from current and future drilling programs.
Advantage constructed a 26 kilometre all year access road to our major
compression sites that will also allow us the flexibility to expand outside of
the winter operating season should we choose to bring on extra capacity which
resulted from the successful 2008 program. This year's drilling results have
set up a similar 2009 drilling program, should we choose to execute on it at
that time. In addition we own 60% to 100% working interest ownership in key
facilities, including five compressor stations, one gas plant with 24 MMcf/d
current throughput and over 290 kilometres 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 37.6 bcf of
natural gas and 752 Mbbls of crude oil and NGLs. In addition, 22.4 bcf of
probable natural gas reserves and 446 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 kilometres 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 property produces from multiple
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 operating 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. Recently this area of British
Columbia has become the focus of exploration and development interest for the
Triassic Montney tight gas play which is being explored on adjacent lands and
developed further along trend to the southeast at Dawson and Swan. Advantage is
evaluating the Montney gas resource potential on our lands which include 16,800
gross (11,800 net) acres of undeveloped land with rights to this interval and
we are planning for a possible new drilling location or recompletion later in
2008 to evaluate this resource.
Current production from the Stoddart area is 580 boe/d.
Sproule evaluated our proved reserves in the area and assigned 12.7 bcf of
natural gas and 762 Mbbls of crude oil and NGLs. In addition, 3 bcf of probable
natural gas reserves and 188 Mbbls of probable crude oil and NGL reserves have
been assigned to this property.
ZAMA LAKE (SOUSA), ALBERTA
The Zama Lake property lies 150 kilometres south/southeast of the Northwest
Territories/British Columbia/Alberta border adjacent to the Hay Zama Lake
Complex. Productive zones on this property are primarily oil and gas from the
Devonian Keg River, Sulphur Point and Slave Point formations as well as gas in
the shallow Cretaceous Bluesky formation. Regionally, Keg River oil wells are
characterized by prolific carbonate reefs. Bluesky sandstone reservoirs tend to
provide lower deliverability, but longer-life sweet-natural-gas production. In
February 2008 we drilled and successfully completed two new Keg River reefs as
well as two shallow Bluesky wells which were used to validate land leases. We
own and operate a sour oil battery, complete with treaters, tanks, oil-pumping
station and solution gas compression. The area also has an existing
gas-gathering system comprised of three owned and operated compressors complete
with a small refrigeration package, dehydration, and sales point. Additional
capacity is available for further development of our lands.
Production from the Zama Lake/Sousa property is currently 1,100 boe/d.
The Sproule Report assigns 6.1 bcf of proven natural gas reserves and 1,195
Mbbls of proven NGL reserves to this property. In addition, 1.2 bcf of probable
natural gas reserves and 439 Mbbls of probable NGL reserves have been assigned
to this property.
RAINBOW, ALBERTA
The Rainbow property lies 175 kilometres south/southeast of the Northwest
Territories/British Columbia/Alberta border in northwest Alberta. The major
focus of production on this property is the Cretaceous Bluesky formation, a
shallow sandstone reservoir that covers an extensive area and offers low-risk
development. No new wells were drilled in the Bluesky in 2007.
20
With the acquisition of Sound, we are planning to optimize facilities and
reviewing opportunities for improving operations prior to commencing a new
round of drilling. Upwards of 50 infill and/or step out locations remain
available for development on this property. In the winter season of 2006/2007,
field compression was added which will support long-term sustained production
volumes from the area. Shallow natural gas production at Black is compressed
and dehydrated in an owned and operated facility before it is further
compressed and processed by a third-party processor in the area. Other Rainbow
shallow natural gas production is compressed, refrigerated and dehydrated at an
owned and operated facility, then delivered to the TCPL System.
Current production from the Rainbow property is 1,000 boe/d.
The Sproule Report assigns 18.1 bcf of proven natural gas reserves and 1,001
Mbbls of proven NGL reserves to this property. In addition, 3.4 bcf of probable
natural gas reserves and 807 Mbbls of probable NGL reserves have been assigned
to this property.
FONTAS, ALBERTA
The Fontas property is situated about 80 kilometres south of the Rainbow Zama
oilfields and about 20 kilometres east of the British Columbia/Alberta border.
Fontas is a natural gas property which produces primarily from Mississippian
aged reservoirs in the Debolt, Shunda and Elkton Formations. Gas is trapped as
these reservoirs are truncated beneath Cretaceous strata and is also trapped in
Cretaceous channels which down cut into the older Mississippian rock. We
operate this winter only access property at a 65% working interest. We operate
six strategically located gas processing/compression facilities and over 200
kilometres of gas gathering pipelines. A winter road was built into the
property for well servicing and replenishment of perishables this winter but no
drilling program was undertaken.
Production from the Fontas property is currently 1,000 boe/d.
The Sproule Report assigns 9.8 bcf of proven natural gas reserves to this
property. In addition, 4.4 bcf of probable natural gas reserves have been
assigned to this property.
SUNSET/VALLEYVIEW, ALBERTA
This area is located approximately 100 kilometres 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, which in this area is a fine grained sandstone conventional
reservoir.
SUNSET "A" - We have a 70% working interest and operate the Sunset Triassic "A"
Unit. Production from the unit is predominantly oil (32o API). The unit 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. Advantage
commenced infill development of the pool in 2005 where two wells were drilled
to evaluate the viability of infill drilling. These wells came on-stream 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 followed with the
addition of 5 oil wells and one water injection well in 2007, all with similar
results. Significant upgrading to oil production and handling facilities and
gathering systems has been ongoing throughout 2006 and 2007 to handle increased
oil production and additional water injection for pressure maintenance. An
additional 22 locations have been identified with 5 wells budgeted for drilling
in 2008.
SUNSET "B" - Production from this Montney reservoir is predominantly natural
gas although there is a thin oil (32o API) 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. No wells were drilled
in 2007 at Sunset "B".
VALLEYVIEW - This Montney gas pool is connected to the Sunset "B" gas
processing plant by a twelve kilometre pipeline. We have a 93% average working
interest in the pool. There was no new drilling in this pool in 2007.
Currently production from the Sunset/Valleyview area is approximately 1,400
boe/d.
21
For the three properties, Sunset "A", Sunset "B" and Valleyview, the Sproule
Report assigns 12.7 bcf of proven natural gas reserves and 2,465 Mbbls of
proven crude oil and NGL reserves. In addition, 17.1 bcf of probable natural
gas reserves and 3,130 Mbbls of probable crude oil and NGL reserves have been
assigned to these properties.
GLACIER, ALBERTA
The Glacier property lies along the east side of the border between Grande
Prairie, Alberta and Dawson Creek, British Columbia. The property consists of
83 sections with an average working interest of 93%. Current production of 350
boe/d is comprised all of natural gas out of various producing zones in 13
wells, which is at present processed at a third party facility. Although gas is
produced out of a variety of horizons in the Cretaceous and Triassic section,
the primary zone of interest is the rapidly emerging unconventional gas play in
the Triassic Montney formation tight gas siltstones. We are in early stages of
drilling and scoping this resource on our lands and in the first three months
of 2008 Advantage drilled and completed various intervals within the Montney in
5 vertical wells (4.33 net) on the Glacier property. These wells clearly frame
and establish the presence of reservoir in both the Upper Montney shore face
portion as well as in the Lower Montney shelf /turbidite portion of the
formation similar to adjacent producing fields at Swan and Dawson on the
British Columbia side of the border. Drilling locations are being secured for
drilling horizontal wells later in the year. These horizontal wells will be
split between targeting both the upper and lower prospective portions of the
formation. Multiple fracs in each horizontal well will be deployed to achieve
maximum production rates.
Sproule evaluated our proved reserves in the area and assigned 16.8 bcf of
natural gas and 151 Mbbls of crude oil and NGLs. In addition, 36.4 bcf of
probable natural gas reserves and 328 Mbbls of probable crude oil and NGLs
reserves have been assigned to this property.
WORSLEY, CECIL, CLEAR RIVER AND BOUNDARY LAKE, ALBERTA
These properties are located 150 kilometres north of the City of Grande
Prairie, Alberta in the Peace River Arch region.
WORSLEY - The Worsley property is complex geologically with numerous structural
and stratigraphic reservoirs ranging from 600 to 2,200 metres. The principle
reservoirs are the Devonian, Wabamun Formation, Mississippian Kiskatinaw and
Debolt Formations and Cretaceous Bluesky and Gething Formations. We hold
varying interests in approximately 35 sections of land in this area, generally
in excess of 50%. We hold a 100% working interest a 7 MMcf/d capacity gas
processing facility in Worsley.
CECIL - 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. In 2007 our working interest in this pool increased from 30% to 90% with
the acquisition of Sound. We hold a 10% working interest in a 50 MMcf/d gas
processing facility at Cecil.
BOUNDARY LAKE - This property lies immediately west of the Worsley property
just east of the British Columbia/Alberta border. The property consists of 15
sections of land (variable but generally greater than 40% working interest.)
The principle asset at Boundary Lake is our 65.625% working interest in a
Halfway Formation gas pool consisting of two wells which have a combined
extended production test rate in excess of 8 MMcf/d. Extensive pooling
discussions with partners, ERCB applications and a purchase of partner
interests have delayed getting this pool coming on stream; however this should
be on production by mid 2008 as most of the regulatory and approval processes
are near complete. One additional well is planned for drilling in 2008 on
expiring land.
CLEAR RIVER - The principle asset on this property is our interest in the
Triassic "CC" oil pool which is a Baldonnel Formation reservoir producing 33o
API crude oil at a depth of 1,200 metres. Two wells were drilled in 2007 on
this property, one early in the year by Sound and a second late in 2007.
Current production from these 4 properties is 1,700 boe/d.
Sproule evaluated our proved reserves in these areas (Worsley, Cecil, Clear
River and Boundary Lake) and assigned 7.1 bcf of natural gas and 795 Mbbls of
crude oil and NGLs. In addition, 5.3 bcf of probable natural gas reserves and
539 Mbbls of probable crude oil and NGL reserves have been assigned to these
properties.
22
NEVIS, ALBERTA
The Nevis property is situated 60 kilometres east of Red Deer. Nevis is an
operated property consisting of approximately 90 sections of land with an
average working interest of 76%. This property produces natural gas from
numerous shallow depth horizons (400 to 800 metres) including the Horseshoe
Canyon, Edmonton, Belly River and Viking formations. Oil and natural gas is
produced from the slightly deeper reservoirs (1,200 metres) 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 metres of
depth in Devonian aged carbonates of the Big Valley Member of the Wabamun
Formation. Because this reservoir is a low permeability carbonate and as such
inflow in vertical wells is low, the pool is being developed with horizontal
wells numbering 4 per section each with an average horizontal length of 1,200
metres. Crude oil quality ranges between 35o and 42o API. In 2007,
approximately 8 sections of land with Wabamun rights were acquired in a
property acquisition. An additional 31 sections of land were added in 2007
through the acquisition of Sound which had a significant land position synergy
with Advantage at Nevis. Drilling for the Wabamun in 2008 continues to focus on
new lands primarily located on the west side of the property. Facilities and
compression are being expanded on the west side of the Red Deer River to
accommodate additional volumes established in 2007 drilling and anticipated in
2008. Oil on the property from all areas is collected at central facilities and
trucked to market. Natural gas is gathered through company owned pipelines and
delivered to third party midstream for final processing and sale. Currently,
the property is being scoped for suitable secondary recovery potential. In
2007, 12 horizontal wells were drilled into the Wabamun formation and are all
currently producing with an average first month initial production of 122
boe/d. The acquisition of Sound added 20 sections (55% net) which have shallow
Horseshoe Canyon coal bed methane ("CBM") potential. We have budgeted 37 wells
(55% working interest) for CBM in 2008. This program commenced drilling in
March. To accommodate shallow pressures encountered with the CBM, appropriate
upgrades to facilities and gathering systems are being implemented in 2008 as
well.
Nevis is Advantage's largest producing property with current production from
all zones at Nevis over 4,600 boe/d.
The Sproule Report assigns 39.4 bcf of proven natural gas reserves and 4,795
Mbbls of proven crude oil and NGL reserves to this property. In addition, 14.1
bcf of probable natural gas reserves and 1,898 Mbbls of probable crude oil and
NGL reserves have been assigned to this property.
WILLESDEN GREEN (OPEN LAKE), ALBERTA
The Willesden Green property is located approximately 35 kilometres north of
the Town of Rocky Mountain House. We operate and have in excess of 90% working
interest. In 2007 we successfully drilled and completed five 2,400 metre deep
wells (4.2 net) targeting two distinct plays, a Jurassic Rock Creek gas play on
the east side of the property and a Cretaceous Ellerslie/Ostracode/Glauconite
play on the north side of the property. In addition 3 wells were farmed out and
these were successfully completed as well as Rock Creek gas wells. We retain a
15% overriding royalty in these latter three wells. In 2008, 3 additional wells
were drilled (100% working interest) in the first quarter resulting in 2
Cretaceous oil wells and one additional Rock Creek gas well. Also, one well was
successfully recompleted in the Cretaceous as an oil well. For the remainder of
2008, two additional drilling locations and 3 more recompletions have been
budgeted.
Current production from all zones at Willesden Green is 1,100 boe/d, with 600
additional boe/d tested and completed from the new 2008 wells drilled to date
and which will be coming on-stream in the second quarter of 2008.
Sproule evaluated our proved reserves in the Willesden Green area and assigned
6.5 bcf of natural gas and 830 Mbbls of crude oil and NGLs. Probable reserves
in this area were evaluated by Sproule at 2.7 bcf of natural gas and 350 Mbbls
of crude oil and NGLs.
WESTEROSE, ALBERTA
The Westerose property is approximately 60 kilometres southwest of Edmonton,
Alberta. Westerose is an 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 in which we hold a 52% interest and
operate. The reservoir in the Banff Formation is a dolomitized carbonate that
is conducive to secondary recovery through waterflooding. The reservoir is
currently under active waterflood pressure maintenance since 2003 and one new
injection well was added to the injection scheme in 2007 along with two new
additional oil producers. We also
23
operate five compressor stations and 80 kilometres of pipeline gathering
facilities that are connected to the Rimbey gas plant. One additional well and
one recompletion workover are budgeted for 2008.
Current production from all zones at the greater Westerose area, including the
Banff "C" Oil Unit is 1,350 boe/d.
Sproule evaluated our proved reserves in the Brazeau River area and assigned
8.9 bcf of natural gas and 2,095 Mbbls of crude oil and NGLs. Probable reserves
in this area were evaluated by Sproule at 2.3 bcf of natural gas and 1,220
Mbbls of crude oil and NGLs.
BRAZEAU RIVER, ALBERTA
The Brazeau River property is located approximately 50 kilometres 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 production from the Brazeau area, including the Nisku pinnacles is 725
boe/d.
Sproule evaluated our proved reserves in the Brazeau River area and assigned
5.5 bcf of natural gas and 527 Mbbls of crude oil and NGLs. Probable reserves
in this area were evaluated by Sproule at 2.8 bcf of natural gas and 273 Mbbls
of crude oil and NGLs.
LOOKOUT BUTTE, ALBERTA
The Lookout Butte property is located approximately 90 kilometres 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 low
at approximately 12% per year. A well drilled in 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. Two wells (50% working interest) have been recompleted in the Cretaceous
Dalhousie Formation which occurs at about 3,100 metres. Both wells are
producing between 100 and 150 boe/day. A new well (50% working interest) was
drilled at year end 2007 and it encountered two overthrust repeats of the pay
zone. Completion of this well is still ongoing. One additional well on this
play is budgeted for 2008.
Current production from Lookout Butte in the Mississippian and Cretaceous
intervals combined is 1,300 boe/d.
Sproule evaluated our proved reserves at Lookout Butte and assigned 30.6 bcf of
natural gas and 1,592 Mbbls of crude oil and NGLs. Probable reserves in this
area were evaluated by Sproule at 11.3 bcf of natural gas and 646 Mbbls of
crude oil and NGLs.
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 metres 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 - The Medicine Hat property is located 20 kilometres northeast of
the City of Medicine Hat in the heart of the south-eastern 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
24
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. No new wells were
added in 2007. Production from this property is currently 9.5 MMcf/d or 1,550
boe/d.
Sproule evaluated our reserves in the area and assigned 43.1 bcf of proved
natural gas reserves and 10.6 bcf of probable reserves. As such, this property
is our largest property on an assigned reserves basis.
BANTRY - This property 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 metres. No new wells were added in 2007. Natural gas is gathered
into our operated compression and dehydration facilities. Current production
from this area is 650 boe/d.
The Sproule Report assigns 8.6 bcf of proven natural gas reserves and 33 Mbbls
of proven NGL reserves to this property. In addition, 3.9 bcf of probable
natural gas reserves and 15 Mbbls of probable NGL reserves have been assigned
to this property.
SHOULDICE - The Shouldice area of southern Alberta is located approximately 50
kilometres 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. No new wells were added in 2007. Both natural
gas and crude oil are produced and gathered through our facilities of varying
working interests. Current natural gas production of 420 boe/d is produced on a
co-mingled basis from the Medicine Hat Formation sands with various Belly River
Formation sands from approximately 90 wells.
The Sproule Report assigns 7.3 bcf of proven natural gas reserves and 67 Mbbls
of proven crude oil and NGLs to this property. In addition, 2 bcf of probable
natural gas reserves and 34 Mbbls of probable crude oil and NGL reserves have
been assigned to this property.
SOUTHEAST SASKATCHEWAN
This area consists of a host of individual properties within the Williston
Sedimentary Basin in the southeast corner of Saskatchewan. 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,
McCoun and Crystal Hills. In 2007, we drilled 4.7 net wells. These included one
(0.6 net) horizontal at Talmage for Ordovician, Red River Oil and 2 net
vertical Frobisher Oil wells at Pinto. The remaining wells were drilled at
Elswick, Queensdale and Crystal Hills. In addition Advantage farmed out two
significant blocks of land to two industry partners in the Midale/Froude area
which have resulted in 10 Bakken horizontal wells with a 10% overriding royalty
and an additional two additional horizontals with a 5 to 12% sliding scale
overriding royalty. We have an additional 6 wells budgeted spread across these
properties in 2008.
Combined production from all the properties in southeast Saskatchewan
(excluding the Wapella area) is 1,755 boe/d.
Sproule evaluated our proved reserves in southeast Saskatchewan and assigned
832 Mmcf of natural gas and 5,513 Mbbls of crude oil and NGLs. Probable
reserves in this area were evaluated by Sproule at 353 Mmcf of natural gas and
3,471 Mbbls of crude oil and NGLs.
WAPELLA/RED JACKET, SASKATCHEWAN
Our Wapella property is located in southeast Saskatchewan, 200 kilometres east
of Regina and produces medium-gravity (25(0) API) oil from Cretaceous and
Jurassic-aged sandstone reservoirs. This property was acquired in 2007 in the
Sound acquisition. It is characterized by its relatively high reserve life
index, high working interest and substantial undeveloped acreage. There is a
significant inventory of drilling locations. The pool is being developed with a
staged waterflood program to enhance reserves and productivity. Future plans
call for continued delineation and development of the pool as well as expansion
of the waterflood scheme. There are two drilling locations and a number of
recompletions budgeted on this property in 2008.
25
Production from the Wapella area is currently 725 boe/d.
Sproule evaluated our proved reserves in Wapella/Red Jacket and assigned 2,774
Mbbls of crude oil. Probable reserves in this area were evaluated by Sproule at
1,123 Mbbls of crude oil.
HEAVY OIL PROPERTIES (WESTERN SASKATCHEWAN - LLOYDMINSTER AREA)
The majority of the east Lloydminster (Lashburn and West Hazel) and Eyehill
properties lie on the Saskatchewan side of the Saskatchewan/Alberta border in
the heart of the Lloydminster heavy oil producing area. These properties
produce primarily from the Cretaceous Sparky Formation and also from the Rex,
Cummings and Dina Formations. Crude gravities are all less than 19(0) API but
are conventionally produced with some pools under active water flood as
pressure maintenance schemes. These properties were added to our portfolio
through the Sound Arrangement.
Currently production from these heavy oil properties is 475 boe/d.
Sproule evaluated our proved reserves in the Heavy Oil Properties of western
Saskatchewan and assigned 88 Mmcf of natural gas and 902 Mbbls of crude oil and
NGLs. Probable reserves in this area were evaluated by Sproule at 43 Mmcf of
natural gas and 2,666 Mbbls of crude oil and NGLs.
OIL AND GAS WELLS
The following table sets forth the number and status of wells as at December
31, 2007 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 986.0 586.8 485.0 259.2 2,090.0 1,549.5 523.0 258.1
British Columbia 5.0 3.4 3.0 0.3 125.0 82.5 50.0 34.6
Saskatchewan 461.0 335.1 161.0 111.2 1.0 1.0 7.0 0.1
Manitoba 85.0 5.1 - - - - - -
------- ----- ----- ----- ------- ------- ----- -----
Total 1,537.0 930.4 649.0 370.7 2,216.0 1,633.0 580.0 292.8
======= ===== ===== ===== ======= ======= ===== =====
Note:
(1) Excluding minor interest in the following units (less than 5% working
interest): Steelman Unit No. 3, Pine Creek Second White Specks Pool,
Carrot Creek Cardium K Unit No. 1, Delburne Gas Unit, Nevis Unit No. 1,
Bonnie Glen D-3A Gas Cap Unit, Bellis Gas Unit No. 2, Turner Valley Unit
No. 5, Sunchild Gas Unit No. 1, North Pembina Cardium Unit, Kakwa Cardium
A Unit, Bonanza Boundary A Pool Unit No. 1, and Boundary Lake Units No. 1
and No. 2. Injection Wells are categorized as Non-Producing Oil Wells.
PROPERTIES WITH NO ATTRIBUTED RESERVES
The following table sets out our developed and undeveloped land holdings as at
December 31, 2007.
Developed Acres Undeveloped Acres Total Acres
--------------------------- -------------------------- -----------------------
Gross Net Gross Net Gross Net
----- --- ----- --- ----- ---
Alberta 1,238,745 647,934 789,914 429,360 2,028,659 1,077,294
British Columbia 159,486 73,877 109,807 64,153 269,293 138,030
Saskatchewan 50,660 38,312 226,301 192,071 276,961 230,383
--------- ------- --------- ------- --------- ---------
Total 1,448,891 760,123 1,126,022 685,584 2,574,913 1,445,707
========= ======= ========= ======= ========= =========
We expect that rights to explore, develop and exploit 164,577 net acres of our
undeveloped land holdings will expire by December 31, 2008. The land
expirations do not consider our 2008 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.
26
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 60% of our gross production for a maximum period of 1 1/2
years. These hedging activities could expose us to losses or gains. 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 53% of our gas is now hedged for the 2008 calendar year
at a floor of $7.52/mcf. For the first quarter of 2008, we have secured
approximately 22% of our net gas production at an $8.85/mcf floor. For the
first quarter of 2009, approximately 60% of our net gas production is hedged at
a floor of $7.87/mcf. We have also hedged approximately 38% of our 2008 net
crude production at an average floor price of Cdn$94.07/bbl and 32% of our
first quarter 2009 production at Cdn$95.84/bbl.
Advantage has the following derivatives in place:
DESCRIPTION OF DERIVATIVE TERM VOLUME AVERAGE PRICE
- --------------------------- --------------------------- ------------ ----------------------------
NATURAL GAS - AECO
Fixed price November 2007 to March 2008 7,109 mcf/d Cdn$9.54/mcf
Fixed price April 2008 to October 2008 14,217 mcf/d Cdn$6.85/mcf
Fixed price April 2008 to October 2008 9,478 mcf/d Cdn$7.25/mcf
Fixed price April 2008 to October 2008 14,217 mcf/d Cdn$7.83/mcf
Fixed price April 2008 to March 2009 14,217 mcf/d Cdn$7.10/mcf
Fixed price April 2008 to March 2009 14,217 mcf/d Cdn$7.06/mcf
Fixed price November 2008 to March 2009 14,217 mcf/d Cdn$7.77/mcf
Fixed price November 2008 to March 2009 4,739 mcf/d Cdn$8.10/mcf
Fixed price November 2008 to March 2009 14,217 mcf/d Cdn$9.45/mcf
Collar November 2007 to March 2008 9,478 mcf/d Floor Cdn$8.44/mcf
Ceiling Cdn$10.29/mcf
Collar November 2007 to March 2008 7,109 mcf/d Floor Cdn$8.70/mcf
Ceiling Cdn$10.71/mcf
CRUDE OIL - WTI
Fixed price February 2008 to January 2009 2,000 bbls/d Cdn$90.93/bbl
Fixed price April 2008 to March 2009 2,500 bbls/d Cdn$97.15/bbl
Collar February 2008 to January 2009 2,000 bbls/d Sold put Cdn$70.00/bbl
Purchased call Cdn$105.00/bbl
Cost Cdn$1.52/bbl
ADDITIONAL INFORMATION CONCERNING ABANDONMENT AND RECLAMATION COSTS
We estimate the costs to abandon and reclaim all our shut-in and producing
wells, facilities, gas plants, pipelines, batteries and satellites. No estimate
of salvage value is netted against the estimated cost. Our model for estimating
the amount and timing of future abandonment and reclamation expenditures was
done on an operating area level. Estimated expenditures for each operating area
are initially based upon Sproule's methodology, which details the cost of
abandonment for the major properties that we hold. Our initial estimated
expenditures are then further adjusted for non-producing wells, pipelines and
27
facilities, and surface reclamation costs. 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 5,425
(gross) producing and non-producing wells. Costs to abandon and reclaim the
producing wells totals $20.3 million ($97.0 million discounted at 10%) and are
included in the estimate of future net revenue. The additional liability
associated with non-producing wells, pipelines and facilities, and surface
reclamation costs was estimated to be $22.0 million ($146.9 million discounted
at 10%), and was not deducted in estimating future net revenue. Facility
reclamation costs are generally 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 undiscounted and included in the estimate of
future net revenue for the next three years are $0.8 million in 2008, $1.3
million in 2009 and $1.5 million in 2010.
TAX HORIZON
In 2007, we did not pay any income related taxes.
In our structure, the operating company utilizes available tax pools to
significantly reduce taxable income and makes other required payments to the
Trust transferring both income and associated tax liability to the Unitholders.
Therefore, it is expected, based on current legislation that no cash income
taxes are to be paid by the operating company prior to 2011 and it is our
intent to continue with the current arrangement. For the 2007 distributions,
100% were taxable to Canadian and U.S. Unitholders.
The Trust does not expect to pay income taxes until the earlier of January 1,
2011 or if and when it ceases to be a trust. New legislation passed in June
2007 will impose a tax on distributions from entities, such as the Trust,
beginning generally on January 1, 2011. Commencing in January 2011 (provided
that the Trust experiences only "normal growth" and no "undue expansion" before
then) the Trust will be liable for tax at the federal "net corporate income tax
rate" combined with the "provincial SIFT tax factor" (effectively the federal
general corporate tax rate plus 13% on account of provincial corporate tax) on
all income payable to Unitholders, which the Trust will not be able to deduct
in computing its taxable income.
CAPITAL EXPENDITURES
The following tables summarize capital expenditures (including capitalized
general and administrative expenses) related to our activities for the year
ended December 31, 2007:
CAPITAL EXPENDITURES ($ THOUSANDS) 2007
- --------------------------------------------------------------------------------
Land and seismic $ 3,270
Drilling, completions and workovers 94,786
Well equipping and facilities 48,296
Other 2,373
- --------------------------------------------------------------------------------
148,725
Property acquisitions
Proved properties 3,200
Unproved properties 12,851
Property dispositions (1,037)
Corporate costs 22,307
- --------------------------------------------------------------------------------
TOTAL CAPITAL EXPENDITURES $ 186,046
- --------------------------------------------------------------------------------
The total capital expenditures for the year ended December 31, 2007 include
approximately $18.3 million related to exploration activities.
EXPLORATION AND DEVELOPMENT ACTIVITIES
The following table sets forth the gross and net wells in which we participated
during the year ended December 31, 2007:
28
Exploratory Development Total
---------------------- -------------------- --------------------
Gross Net Gross Net Gross Net
----- --- ----- --- ----- ---
Oil wells 9 9.0 37 22.6 46 31.6
Gas wells 24 15.4 41 16.8 65 32.2
Dry holes - - 1 1.0 1 1.0
----- ----- ----- ----- ----- -----
Total 33 24.4 79 40.4 112 64.8
===== ===== ===== ===== ===== =====
Subject to, among other things, the availability of drilling rigs and weather
that permits access to drill sites, in 2008, we plan to drill, complete and
tie-in 88 net wells and recomplete an additional 14 net wells.
We estimate capital expenditures of between $125 million and $145 million in
2008 to execute our capital programs. The primary components of our programs
are described under the heading "Other Oil and Gas information - Oil and
Natural Gas Properties".
PRODUCTION ESTIMATES
The following table sets out the volume of our production estimated for the
year ended December 31, 2008 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 Total
(bbl/d) (bbl/d) (Mcf/d) (bbl/d) (Boe/d)
-------------- -------------- ------------------ -------------- ------------------
Gross Net Gross Net Gross Net Gross Net Gross Net
----- --- ----- --- ----- --- ----- --- ----- ---
Proved Producing 8,384 7,068 895 747 116,770 92,775 2,586 1,892 31,327 25,170
Proved Developed Non-
Producing 131 107 7 5 3,170 2,452 69 52 735 573
Proved Undeveloped 235 184 25 21 3,795 3,068 52 45 944 761
----- ----- ----- --- ------- ------- ----- ----- ------ ------
Total Proved 8,750 7,359 927 773 123,735 98,295 2,707 1,989 33,006 26,504
Total Probable 1,059 824 86 65 12,449 9,142 231 181 3,451 2,594
----- ----- ----- --- ------- ------- ----- ----- ------ ------
Total Proved Plus
Probable 9,809 8,183 1,013 838 136,184 107,437 2,938 2,170 36,457 29,098
===== ===== ===== === ======= ======= ===== ===== ====== ======
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 2007 Year Ended
-------------------------------------------------- -------------
Mar. 31 June 30 Sept. 30 Dec. 31 Dec. 31, 2007
------- ------- -------- ------- -------------
Average Daily Production(1)
Crude Oil (bbl/d) 7,557 6,615 7,750 10,410 8,090
Gas (MMcf/d) 114.3 109.0 116.0 128.6 117.0
NGLs (bbl/d) 2,401 2,337 2,264 2,485 2,372
Combined (boe/d) 29,012 27,115 29,346 34,321 29,962
Average Net Production Prices Received(2)
Crude Oil ($/bbl) 59.03 64.23 70.22 74.19 67.71
Gas ($/Mcf) 7.61 7.54 5.62 6.23 6.72
NGLs ($/bbl) 49.93 55.05 64.95 70.09 60.12
Combined ($/boe) 49.51 50.71 45.79 50.91 49.27
29
Quarter Ended 2007 Year Ended
-------------------------------------------------- -------------
Mar. 31 June 30 Sept. 30 Dec. 31 Dec. 31, 2007
------- ------- -------- ------- -------------
Gain/(Loss) on Derivatives
Crude Oil ($/bbl) 2.37 0.14 (0.67) (3.71) (0.79)
Gas ($/Mcf) 0.45 (0.02) 0.73 0.74 0.49
Combined ($/boe) 2.39 (0.02) 2.67 1.65 1.70
Royalties Paid
Crude Oil ($/bbl) 10.67 10.49 12.81 15.08 12.58
Gas ($/Mcf) 1.51 1.33 0.90 0.79 1.12
NGLs ($/bbl) 15.44 15.23 18.75 14.72 15.99
Combined ($/boe) 10.02 9.22 8.37 8.58 9.02
Operating Expenses(3)(4)
Crude oil ($/bbl) 14.15 14.56 16.06 14.91 14.94
Natural gas ($/Mcf) 1.82 1.64 1.62 1.94 1.76
NGLs ($/bbl) 9.00 9.06 9.62 9.24 9.22
Combined ($/boe) 11.59 10.91 11.40 12.46 11.64
Netback Received(5)
Crude Oil ($/bbl) 36.58 39.32 40.68 40.49 39.40
Gas ($/Mcf) 4.73 4.55 3.83 4.24 4.33
NGLs ($/bbl) 25.49 30.76 36.58 46.13 34.91
Combined ($/boe) 30.29 30.56 28.69 31.52 30.31
Notes:
(1) Before deduction of royalties.
(2) Production prices are net of costs to transport the product to market.
(3) This figure includes all field operating expenses.
(4) We do not record operating expenses on a commodity basis. Information in
respect of operating expenses for crude oil and NGLs ($/bbl) and natural
gas ($/Mcf) has been determined by allocating 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.
(5) 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 (4) above.
The following table indicates our approximate average daily production from our
important fields for the quarter ended December 31, 2007:
30
Natural Gas Crude Oil & NGLs Total
Properties (Mcf/d) (bbls/d) (boe/d)
- ---------------------------------------------------------------------------------------------------------------
Nevis 14,770 1,780 4,241
Martin Creek 17,840 310 3,283
Saskatchewan 310 3,170 3,222
Willesden Green/Westerose 9,280 1,180 2,727
Medicine Hat 10,340 - 1,723
Boundary Lake/Cecil 4,740 860 1,650
Sunset 3,830 840 1,478
Sousa 3,350 740 1,298
Brazeau/Ferrier 5,310 370 1,255
Chip Lake 4,400 440 1,173
- ---------------------------------------------------------------------------------------------------------------
Major Properties 74,170 9,690 22,050
Other 54,386 3,205 12,271
- ---------------------------------------------------------------------------------------------------------------
TOTAL 128,556 12,895 34,321
FUTURE COMMITMENTS
We have committed to certain payments over the next five years, in addition to
regular payments under our credit facilities, as follows:
($ millions) 2008 2009 2010 2011 2012
- ------------ ---- ---- ---- ---- ----
Building leases 5.3 4.1 4.1 1.8 1.3
Capital leases 1.9 2.1 2.2 1.9 -
Pipeline/transportation 4.4 1.3 0.3 - -
Convertible debentures(1) 5.4 87.0 69.9 62.3 -
Note:
(1) As at December 31, 2007, Advantage had $224.6 million convertible
debentures outstanding. Each series of convertible debentures are
convertible to Trust Units based on an established conversion price. The
Fund expects that the obligations related to convertible debentures will
be settled either directly or indirectly through the issuance of Trust
Units.
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;
31
(c) acquire, construct and install production facilities such as flow
lines, separators, treaters, heaters, manifolds, measuring devices
and production storage tanks, natural gas cycling and processing
plants, and central utility and waste disposal systems; and
(d) provide improved recovery systems.
"EXPLORATION COSTS" means costs incurred in identifying areas that may
warrant examination and in examining specific areas that are considered
to have prospects that may contain oil and gas reserves, including costs
of drilling exploratory wells and exploratory type stratigraphic test
wells. Exploration costs may be incurred both before acquiring the
related property and after acquiring the property. Exploration costs,
which include applicable operating costs of support equipment and
facilities and other costs of exploration activities, are:
(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
32
o specified economic conditions.
Reserves are classified according to the degree of certainty associated with
the estimates.
(a) PROVED RESERVES are those reserves that can be estimated with a
high degree of certainty to be recoverable. It is likely that the
actual remaining quantities recovered will exceed the estimated
proved reserves.
(b) PROBABLE RESERVES are those additional reserves that are less
certain to be recovered than proved reserves. It is equally likely
that the actual remaining quantities recovered will be greater or
less than the sum of the estimated proved plus probable reserves.
Other criteria that must also be met for the categorization of reserves are
provided in the COGE Handbook.
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 11% of our natural
gas
33
production is sold to aggregators who accumulate production from various
producers and market the gas on behalf of the group. Such contracts are reserve
specific and continue for the life of production from the specified reserves.
CYCLICAL AND SEASONAL IMPACT OF INDUSTRY
Our operational results and financial condition will be dependent on the prices
received for oil and natural gas production. Oil and natural gas prices have
fluctuated widely during recent years and are determined by supply and demand
factors, including weather and general economic conditions, as well as
conditions in other oil and natural gas regions. Any decline in oil and natural
gas prices could have an adverse effect on our financial condition. We mitigate
such price risk through closely monitoring the various commodity markets and
establishing hedging programs, as deemed necessary, to provide stability to
Unitholders' cash distributions and lock-in high netbacks on production
volumes. See "OTHER OIL AND GAS INFORMATION - FORWARD CONTRACTS" for our
current hedging program.
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 2008 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.
HEALTH, SAFETY AND ENVIRONMENTAL
AOG is committed to a comprehensive and effective health, safety and
environmental program that meets or exceeds regulatory and corporate
requirements.
Management, employees and all contractors are responsible and accountable for
the overall health, safety and environmental program. AOG will operate in
compliance with all applicable regulations and will ensure all staff and
contractors employ sound practices to protect the environment and to ensure
employee and public health and safety.
We will maintain a safe and environmentally responsible work place and provide
training, equipment and procedures to all individuals in adhering to our
policies. We will also solicit and take into consideration input from our
neighbors, communities and other stakeholders in regard to protecting people
and the environment.
AOG participates in the Environment, Health and Safety Stewardship Program
developed by the Canadian Association of Petroleum Producers. Participation
requires commitment to continuous improvement in the environment, health and
safety management practices including sound planning and implementation, open
communication and measured performance against our peers.
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.
34
HUMAN RESOURCES
As at December 31, 2007, we employed 172 full-time employees, 139 of which are
located in the head office and 33 of which are located in the field. We also
employed 27 consultants in the head office.
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, 2007, 138,269,374 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 are no special voting units 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 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 will generally continue to be taxed as
ordinary income in the hands of a Unitholder until
35
January 2011 (provided we do not exceed "normal growth" or experience undue
expansion), and will be treated as dividends after such time. 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 - CHANGES
IN LEGISLATION".
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.
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.
36
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
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
37
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
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 2/3% 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 June 3,
2008.
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.
38
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:
(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;
39
(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;
(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
40
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 2/3% of the votes cast at a meeting of our Unitholders called for such
purpose.
The Trustee may, without the approval of the Unitholders, make certain
amendments to the Trust Indenture, including amendments:
1. for the purpose of ensuring continuing compliance with applicable laws
(including the Tax Act), regulations, requirements or policies of any
governmental or other authority having jurisdiction over the Trustee or
over the Trust;
2. ensuring that we will satisfy the provisions of each of Sections
108(2)(a) and 132(6) of the Tax Act, as from time to time amended or
replaced;
3. which, in the opinion of the Trustee, provide additional protection for
or benefit to the Unitholders;
4. to remove any conflicts or inconsistencies in the Trust Indenture or
making corrections, including the correction or rectification of any
ambiguities, defective provisions, errors, mistakes or omissions, which
are, in the opinion of the Trustee, necessary or desirable and not
prejudicial to the Unitholders;
5. which, in the opinion of the Trustee, are necessary or desirable as a
result of changes in taxation laws; and
6. removing or curing inconsistencies between the Trust Indenture and the
Material Contracts (as such term is defined in the Trust Indenture) which
are, in the opinion of the Trustee, necessary or desirable and not
prejudicial to the Unitholders.
In December 2007, the Trust Indenture was amended to allow the Trust to
participate in the DRS. Effective January 1, 2008, all issuers whose securities
are listed on the New York Stock Exchange are required to ensure that their
listed securities are eligible for participation in the DRS. DRS eligible
issuers must provide an investor with the ability to have their securities
registered in the investors' name directly on the issuer's books (through its
transfer agent) or through the investors' brokerage dealer, thereby eliminating
the need for physical certificates to evidence ownership of securities. As a
result of the implementation of the need to be DRS eligible, certain amendments
were required to be made to the Trust Indenture of the Trust.
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.
41
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 2/3% 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
Period Served as
Name, Province and Country a Director or
of Residence Officer(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
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 (1997-2001)
Director since and Vice President, Finance and Chief Financial Officer (1990-1997) of
May 24, 2001 EnerPlus Group of Companies, which companies specialize in the management
of oil and gas income funds and royalty trusts.
John A. Howard (3)(8) Director since President of Lunar Enterprises Corp., a private holding company.
Alberta, Canada June 23, 2006
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)
Stephen Balog(3) Director since President, West Butte Management Inc., a private oil and gas consulting
Alberta, Canada August 16, 2007 company. Prior thereto, President & Chief Operating Officer and a
Director of Tasman Exploration Ltd. from 2001 to June, 2007.
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.
42
Position Held and
Period Served as
Name, Province and Country a Director or
of Residence Officer(4)(5) Principal Occupations During Past Five Years
- --------------------------- ----------------- --------------------------------------------------------------------------
Steven Sharpe(2) Director since Since, July, 2008, Senior Advisor to Blair Franklin Capital Partners,
Ontario, Canada May 24, 2001 and Inc., a Toronto-based investment bank which he co-founded in May, 2003.
Non-Executive Prior to that, Mr. Sharpe was Managing Partner of Blair Franklin, from its
Chairman since inception. Before then, he was Managing Director of The EBS Corporation, a
May 26, 2004 management and strategic consulting 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)
Sheila O'Brien(2) Director since From April 2004, President of Belvedere Investments and Corporate
March 21, 2007 Director; from July 1998 to April 2004, Senior Vice President, Human
Resources, Public Affairs, Investor and Government Relations with Nova
Chemicals Corporation. Among her other accomplishments, Ms. O'Brien was
designated as Member, Order of Canada in 1999.
Patrick J. Cairns Senior Vice Senior Vice President of AOG since June 2001. Vice President of the
Alberta, Canada President Manager since May 2001. Prior thereto, Mr. Cairns was Vice President,
Evaluations with the Enerplus Group of Companies, which companies
specialize in the management of oil and gas income funds and royalty
trusts.
Peter Hanrahan Vice President Chief Financial Officer of AOG since January 2003. Prior thereto,
Alberta, Canada Finance and Controller of AOG since December 1999.
Chief Financial
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
43
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) AOG does not have an executive committee of the Board.
(5) AOG's directors shall hold office until the next annual general meeting
of Unitholders 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.
As at March 12, 2008, the directors and executive officers of AOG, as a group,
beneficially owned, directly or indirectly, or exercised control or direction
over, 3,208,852 Trust Units, or approximately 2.3% of the issued and
outstanding Trust Units.
CEASE TRADE ORDERS, BANKRUPTCIES, PENALTIES OR SANCTIONS
Other than as disclosed above, no current director or officer or securityholder
holding a sufficient number of securities of the Trust or AOG to affect
materially the control of the Trust or AOG has, within the last ten years prior
to the date of this document, been a director, chief executive officer or chief
financial officer of any issuer (including AOG) that, (i) while the person was
acting in the capacity as director, chief executive officer or chief financial
officer, was the subject of a cease trade or similar order or an order that
denied the company access to any exemption under securities legislation, that
was in effect for a period of more than thirty (30) consecutive days; or (ii)
was subject to an order that resulted, after the director, executive officer or
securityholder holding a sufficient number of securities of the Trust or AOG to
affect materially the control of the Trust or AOG ceased to be a director,
chief executive officer or chief financial officer of an issuer, in the issuer
being the subject of a cease trade or similar order or an order that denied the
relevant issuer access to any exemption under securities legislation, for a
period of more than thirty (30) consecutive days, which resulted from an event
that occurred while that person was acting as a director, chief executive
officer or chief financial officer if the issuer.
No current director or officer or securityholder holding a sufficient number of
securities of the Trust or AOG to affect materially the control of the Trust or
AOG has, within the last ten years prior to the date of this document, been a
director or executive officer of any company (including AOG) that, while such
person was acting in that capacity, or within a year of that person ceasing to
act in that capacity, became bankrupt, made a proposal under any legislation
relating to bankruptcy or insolvency or was subject to or instituted any
proceedings, arrangement for compromise with creditors or had a receiver,
receiver manager or trustee appointed to hold its assets.
In addition, no current director or officer or securityholder holding a
sufficient number of securities of the Trust or AOG to affect materially the
control of the Trust or AOG has, within the last ten years prior to the date of
this document, become bankrupt, made a proposal under any legislation relating
to bankruptcy or insolvency, or become 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 the director,
officer or securityholder.
No current director or officer or securityholder holding a sufficient number of
securities of the Trust or AOG to affect materially the control of the Trust or
AOG has been subject to: (i) any penalties or sanctions imposed by a court
relating to securities legislation or by a securities regulatory authority or
has entered into a settlement agreement with a securities
44
regulatory authority; or (ii) 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.
CONFLICTS OF INTEREST
The directors and officers of AOG may, from time to time, be involved in the
business and operations of other issuers, in which case a conflict may arise.
The ABCA provides that in the event 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 interests arise, such conflicts will be
resolved in accordance with the provisions of the ABCA.
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. Advantage 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 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.
45
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
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.
46
LONG TERM NOTES
The aggregate principal amount of Long Term Notes as at December 31, 2007 was
approximately $634.8 million. 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 $344.8 million
("ORIGINAL PRINCIPAL AMOUNT") and the aggregate principal amount of the Medium
Term Notes as at December 31, 2007 was approximately $244.7 million. The Medium
Term Notes consist of a series of notes, which as of December 31, 2007,
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)).
DEBENTURES
The Debentures pay interest semi-annually and are convertible at the option of
the holder into Trust Units at the applicable conversion price per Trust Unit
plus accrued and unpaid interest. The details of the Debentures including the
balance outstanding as at December 31, 2007 are as follows:
10.00% 9.00% 8.25% 8.75%
------------- ------------ ------------ -------------
Trading symbol AVN.DB AVN.DBA AVN.DBB AVN.DBF
Issue date Oct. 18, 2002 July 8, 2003 Dec. 2, 2003 June 10, 2004
Maturity date Matured Aug. 1, 2008 Feb. 1, 2009 June 30, 2009
Conversion price Matured $17.00 $16.50 $34.67
Outstanding at December 31, 2007 - $5,392,000 $4,867,000 $29,839,000
47
7.50% 6.50% 7.75% 8.00% TOTAL
------------- ------------- ------------- ------------- ------------
Trading symbol AVN.DBC AVN.DBE AVN.DBD AVN.DBG
Issue date Sep. 15, 2004 May 18, 2005 Sep. 15, 2004 Nov. 13, 2006
Maturity date Oct. 1, 2009 June 30, 2010 Dec. 1, 2011 Dec. 31, 2011
Conversion price $20.25 $24.96 $21.00 $20.33
Outstanding at December 31, 2007 $52,268,000 $69,952,000 $46,766,000 $15,528,000 $224,612,000
The convertible debentures are redeemable prior to their maturity dates, at the
option of the Fund, upon providing 30 to 60 days advance notification. The
redemption prices for the various debentures, plus accrued and unpaid interest,
is dependent on the redemption periods and are as follows:
CONVERTIBLE
DEBENTURE REDEMPTION PERIODS PRICE
- ----------- -------------------------------------------------------- -------
9.00% After August 1, 2007 and before August 1, 2008 $1,025
8.25% After February 1, 2007 and on or before February 1, 2008 $1,050
After February 1, 2008 and before February 1, 2009 $1,025
8.75% After June 30, 2007 and on or before June 30, 2008 $1,050
After June 30, 2008 and before June 30, 2009 $1,025
7.50% After October 1, 2007 and on or before October 1, 2008 $1,050
After October 1, 2008 and before October 1, 2009 $1,025
6.50% After June 30, 2008 and on or before June 30, 2009 $1,050
After June 30, 2009 and before June 30, 2010 $1,025
7.75% After December 1, 2007 and on or before December 1, 2008 $1,050
After December 1, 2008 and on or before December 1, 2009 $1,025
After December 1, 2009 and before December 1, 2011 $1,000
8.00% After December 31, 2009 and on or before December 31, 2010 $1,050
After December 31, 2010 and before December 31, 2011 $1,025
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 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.
48
CASH DISTRIBUTIONS
The following is a summary of the distributions made by us for each of the
three most recently completed financial years.
For the 2007 Period Ended Distributions per Unit Payment Date
- ------------------------- ---------------------- ------------
January 31 $0.15 February 15, 2007
February 28 $0.15 March 15, 2007
March 31 $0.15 April 16, 2007
April 30 $0.15 May 15, 2007
May 31 $0.15 June 15, 2007
June 30 $0.15 July 16, 2007
July 31 $0.15 August 15, 2007
August 31 $0.15 September 17, 2007
September 30 $0.15 October 15, 2007
October 31 $0.15 November 15, 2007
November 30 $0.15 December 17, 2007
December 31 $0.12 January 15, 2008
-----
TOTAL: $1.77
For the 2006 Period Ended Distributions 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
For the 2005 Period Ended Distributions per Unit Payment Date
------------------------- ---------------------- ------------
January 31 $0.28 February 15, 2005
February 28 0.28 March 15, 2005
March 31 0.28 April 15, 2005
April 30 0.28 May 16, 2005
May 31 0.25 June 15, 2005
June 30 0.25 July 15, 2005
July 31 0.25 August 15, 2005
August 31 0.25 September 15, 2005
September 30 0.25 October 17, 2005
October 31 0.25 November 15, 2005
November 30 0.25 December 15, 2005
December 31 0.25 January 16, 2006
----
TOTAL $3.12
Note:
(1) On February 15, 2008 a distribution of $0.12 per Trust Unit was paid to
Unitholders of Record on the close of business on January 31, 2007. We
announced on February 15, 2008 that a distribution of $0.12 per Trust
Unit will be payable on March 15, 2008 to Unitholders of record on the
close of business on February 28, 2008.
MARKET FOR SECURITIES
Our Trust Units are listed for trading on the TSX under the symbol "AVN.UN"
and, since December 9, 2005, on the NYSE under the symbol "AAV". The following
table sets forth the high and low closing trading prices and the aggregate
trading volume of the Trust Units as reported by the TSX and NYSE for the
periods indicated.
Period High Low Volume
- --------------------- ------- ------- -----------
TSX TRADING ($) ($)
2007
- ----
January 13.41 11.47 7,579,256
February 12.80 12.13 5,898,850
March 12.56 11.46 4,620,757
April 12.87 11.70 5,527,749
May 14.47 12.46 4,881,754
June 15.97 13.14 6,602,894
July 14.95 12.99 9,267,097
August 13.53 11.56 6,126,077
September 12.42 11.30 7,607,438
October 12.50 11.75 5,903,420
November 12.00 9.81 5,535,740
December 10.58 8.54 6,316,637
2008
====
January 9.92 8.65 5,340,085
February 11.06 9.23 4,168,544
50
Period High Low Volume
- --------------------- ------- ------- -----------
NYSE TRADING ($US)
2007
- ----
January 11.40 9.76 5,406,700
February 10.90 10.46 3,333,500
March 10.82 9.75 4,689,000
April 11.50 10.17 3,815,000
May 13.32 11.27 5,579,900
June 14.95 12.40 7,623,900
July 14.24 12.20 5,972,800
August 12.75 10.74 5,210,700
September 12.45 11.05 4,621,500
October 12.89 11.96 5,295,600
November 12.69 10.22 4,971,700
December 10.46 8.68 6,550,900
2008
====
January 9.84 8.45 4,006,900
February 11.16 9.12 3,789,300
Our 6.50% 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% Debentures as reported by
the TSX for the periods indicated.
Period High Low Volume
- --------------------- ------- ------- -----------
2007 (%) (%)
- ----
January 98.00 95.50 11,970
February 97.99 96.00 31,540
March 97.00 94.25 36,920
April 96.00 94.00 16,710
May 100.50 95.50 29,330
June 99.84 96.50 14,100
July 99.25 96.56 11,940
August 99.19 95.00 8,270
September 97.50 95.00 6,420
October 97.50 94.00 6,300
November 96.48 92.01 8,030
December 94.50 90.00 4,880
2008
====
January 95.75 93.01 21,780
February 96.99 93.25 41,540
51
Our 7.5% 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% Debentures as reported by
the TSX for the periods indicated.
Period High Low Volume
- --------------------- ------- ------- -----------
2007 (%) (%)
- ----
January 105.00 100.01 5,280
February 102.50 100.37 3,220
March 101.00 99.51 2,300
April 101.25 98.50 11,430
May 102.49 99.51 9,100
June 101.99 100.50 3,880
July 102.50 100.51 3,160
August 102.49 99.51 3,440
September 101.00 99.01 1,210
October 99.95 97.01 3,590
November 99.99 97.51 6,260
December 99.99 95.00 3,470
2008
====
January 100.25 98.00 12,300
February 101.50 99.81 2,070
Our 7.75% 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% Debentures as reported by
the TSX for the periods indicated.
Period High Low Volume
- --------------------- ------- ------- -----------
2007 (%) (%)
- ----
January 101.50 100.06 7,590
February 101.69 100.01 5,780
March 101.00 99.75 12,160
April 100.50 99.15 14,330
May 101.99 99.91 4,740
June 101.99 100.21 5,880
July 102.00 100.10 6,160
August 102.00 99.00 5,830
September 100.99 95.51 7,210
October 99.49 95.50 5,980
November 97.99 95.00 8,270
December 96.50 90.00 4,990
2008
====
January 97.99 94.00 12,340
February 99.19 97.00 5,670
Our 8.00% Debentures are listed for trading on the TSX under the symbol
"AVN.DB.G". The following table sets forth the high and low closing trading
prices and the aggregate trading volume of the 8.00% Debentures as reported by
the TSX for the periods indicated.
52
Period High Low Volume
- --------------------- ------- ------- -----------
2007 (%) (%)
- ----
September 103.75 100.00 155,600
October 102.65 96.51 38,800
November 98.50 97.00 2,790
December 98.50 98.00 3,920
2008
====
January 99.00 93.00 4,170
February 99.00 98.00 2,370
Our 8.25% 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% Debentures as reported by
the TSX for the periods indicated.
Period High Low Volume
- --------------------- ------- ------- -----------
2007 (%) (%)
- ----
January 103.00 99.52 560
February 103.00 101.00 1,330
March 102.49 100.50 1,430
April 102.50 100.38 940
May 103.00 101.11 760
June 105.50 102.81 340
July 105.00 100.00 1,200
August 103.62 99.61 940
September 102.89 100.01 600
October 101.50 100.00 690
November 100.99 100.99 80
December 102.43 99.61 440
2008
====
January 101.00 99.76 1,870
February 101.75 101.40 750
Our 8.75% Debentures are listed for trading on the TSX under the symbol
"AVN.DB.F". The following table sets forth the high and low closing trading
prices and the aggregate trading volume of the 8.75% Debentures as reported by
the TSX for the periods indicated.
Period High Low Volume
- --------------------- ------- ------- -----------
2007 (%) (%)
- ----
September 103.50 100.51 55,680
October 103.25 100.00 39,410
November 101.48 100.01 8,790
December 101.99 95.00 4,520
2008
====
January 101.00 100.00 9,870
February 101.68 99.70 3,890
Our 9.00% 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 9.00% Debentures as reported by
the TSX for the periods indicated.
53
Period High Low Volume
- --------------------- ------- ------- -----------
2007 (%) (%)
- ----
January 103.25 103.00 860
February 104.00 104.00 150
March 105.02 104.65 780
April 103.01 98.00 480
May 101.31 101.31 50
June 105.06 102.47 650
July - - -
August 101.28 101.23 420
September 100.00 100.00 100
October 100.06 100.06 13
November 103.75 100.08 440
December 100.84 100.03 300
2008
====
January 102.65 101.00 760
February 101.47 101.42 830
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, 2007 are as follows:
NUMBER OF TRUST UNITS HELD IN
DESIGNATION OF CLASS ESCROW PERCENTAGE OF CLASS
-------------------- ------------------------------ -------------------
Trust Units 1,193,622(1) 0.9%
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.
REGULATORY ACTIONS
During the year ended December 31, 2007 there were (i) no penalties or
sanctions imposed against the Trust or AOG or by a court relating to securities
legislation or by a securities regulatory authority; (ii) no other penalties or
sanctions imposed by a court or regulatory body against the Trust or AOG that
would likely be considered important to a reasonable investor
54
in making an investment decision; and (iii) no settlement agreements the Trust
or AOG entered into before a court relating to a securities legislation or with
a securities regulatory authority.
INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS
There were no material interests, direct or indirect, of directors and
executive officers of AOG or nominees for director of AOG, any Unitholder who
beneficially owns or directs or controls more than 10% of the Trust Units or
any known associate or affiliate of such persons in any transaction during 2007
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 2007; 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, KPMG LLP, our former
auditors, and PricewaterhouseCoopers LLP, our current auditors. As at the date
hereof, none of the principals of Sproule Associates Limited had any registered
or beneficial interests, direct or indirect, in any securities or other
property of Advantage 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. PricewaterhouseCoopers LLP have confirmed
that they are 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 PricewaterhouseCoopers 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. Rodger
Tourigny and Ronald McIntosh and Ms. Carol Pennycook. 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.
55
NAME, PROVINCE AND COUNTRY OF FINANCIALLY
RESIDENCE INDEPENDENT LITERATE RELEVANT EDUCATION AND EXPERIENCE
- ------------------------------ ----------- ----------- ---------------------------------------------------------
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 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. Mr. McIntosh is also the
Chairman and member of the audit committee of Tasman
Energy, a private oil and gas company.
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
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 PricewaterhouseCoopers
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 PricewaterhouseCoopers 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
of AOG in fulfilling its responsibilities by reviewing: the financial reports
and other financial information provided by 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;
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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 the Corporation's
internal audit function and independent auditors; and
7. To assist the Board's oversight of the Corporation's compliance with
legal and regulatory requirements.
COMPOSITION
The Audit Committee shall be comprised of three or more directors as determined
by the Board of Directors, none of whom are members of management of AOG, or
the Trust and all of whom are "independent" (as such term is defined in (a)
National Instrument 52-110 -- Audit Committees ("NI 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
NI 52-110. 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 AOG 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 AOG's Audit Committee and will disclose such determination
in Advantage'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 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.
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.
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3. Review the reports to management prepared by the independent auditors and
management's responses.
4. Review with financial management and the independent auditors the
quarterly financial statements prior to their filing or prior to the
release of earnings. The Chair of the Audit Committee may represent the
entire Audit Committee for purposes of this review.
5. Review significant findings during the year, including the status of
previous significant audit recommendations.
6. Periodically assess the adequacy of procedures for the review of
corporate disclosure that is derived or extracted from the financial
statements.
7. Periodically discuss guidelines and policies to govern the processes by
which the Chief Executive Officer and senior management assess and manage
the Corporation's exposure to risk.
8. Report regularly to the Board any issues that arise with respect to the
quality or integrity of the Corporation's financial statements,
compliance with legal or regulatory requirements, performance and
independence of the Corporation's auditors, or performance of the
internal audit function.
9. To prepare, if required, an Audit Committee report to be included in
Advantage'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
the Corporation's risk management processes and system of internal
controls.
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20. Review the audit scope and plan of the independent auditor.
21. Oversee the work of the external auditors engaged for the purpose of
preparing or issuing an auditor's report or performing other audit,
review or attest services for the Trust.
22. Pre-approve the completion of any non-audit services by the external
auditors and determine which non-audit services the external auditor is
prohibited from providing. The Audit Committee may delegate to one or
more members of the Audit Committee authority to pre-approve non-audit
services in satisfaction of this requirement and if such delegation
occurs, the pre-approval of non-audit services by the Audit Committee
member to whom authority has been delegated must be presented to the
Audit Committee at its first scheduled meeting following such
pre-approval. The Audit Committee shall be entitled to adopt specific
policies and procedures for the engagement of non-audit services if:
(a) the pre-approval policies and procedures are detailed as to the
particular service;
(b) the Audit Committee is informed of each non-audit service; and
(c) the procedures do not include delegation of the Audit Committee's
responsibilities to management.
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.
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29. Following completion of the annual audit, review separately with each of
management and the independent auditors any significant difficulties
encountered during the course of the audit, including any restrictions on
the scope of work or access to required information.
30. Review any significant disagreements among management and the independent
auditors in connection with the preparation of the financial statements.
31. Review with the independent auditors and management the extent to which
changes or improvements in financial or accounting practices, as approved
by the Audit Committee, have been implemented. (This review should be
conducted at an appropriate time subsequent to implementation of changes
or improvements, as decided by the Audit Committee.)
32. Conduct and authorize investigations into any matters brought to the
Audit Committee's attention and within the Audit Committee's scope of
responsibilities. The Audit Committee shall be empowered to retain and to
approve compensation for any independent counsel and other professionals
to assist in the conduct of any investigation.
33. Review the systems that identify and manage principal business risks.
34. Establish a procedure for:
(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.
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AUDIT SERVICE FEES
AUDITOR SERVICES FEES
The following table discloses fees billed to us by our former auditors, KPMG
LLP.
TYPE OF SERVICE PROVIDED 2007 2006
- ------------------------ -------- --------
Audit Fees (these services included prospectus work and audit or review of financials $203,089 $617,000
forming part of such prospectus, U.S. GAAP reconciliation, and work related to the Sound
Acquisition)
Audit-Related Fees (these services included French translation in connection with $57,508 $144,500
prospectus offerings)
Tax Fees (these services included review/completion of tax returns and general tax $110,725 $36,040
consultations)
The following table discloses fees billed to us by our current auditors,
PricewaterhouseCoopers LLP.
TYPE OF SERVICE PROVIDED 2007
- ------------------------ --------
Audit Fees (these services included U.S. GAAP reconciliation and work related to the Sound Acquisition) $694,119
Audit-Related Fees $-
Tax Fees (these services included review/completion of tax returns and general tax consultations) $25,930
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 (other than propane, butane and ethane) 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
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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.
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,
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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
19.5% effective January 1, 2008 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 October 2007 Economic Statement and
Notice of Ways and Means Motion, the federal corporate income tax rate will
decrease to 15% in three steps: 19% on January 1, 2009, 18% on January 1, 2010,
18.5% on January 1, 2011, and 15% on January 1, 2012.
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 the pool was discovered
prior to March 31, 1974 it is considered "old oil", if it was 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 programs affected by this announcement 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 was May 31, 2007. The
successful applicants have not yet been announced and it appears, based on the
previous two rounds, that the selection process can take at least 8 months. The
technical information gathered from this program is to be made public once a
two year confidentiality period expires.
On October 25, 2007, the Alberta government released a report entitled "The New
Royalty Framework" (the "NRF") containing the government's proposals for
Alberta's new royalty regime, which is scheduled to be effective on January 1,
2009. The proposed NRF includes new royalty formulas for conventional oil and
natural gas that will operate on sliding scales that are determined by
commodity prices and well productivity. Substantial legislative, regulatory and
systems updates will be introduced before changes become fully effective in
January 2009.
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
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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
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. For this purpose, on December 18, 2007 proposals were
sought for applications to the Innovative Clean Energy Fund, in order to
attract new technologies that will help solve energy and environmental issues.
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 establishment 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) new the Oil and Gas Technology Transfer Incentive Program that encourages
the research, development and use of innovative technologies to increase
recoveries 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
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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:
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.
On June 19, 2007, the Government of Saskatchewan introduced the Orphan Well and
Facility Liability Management Program pursuant to the amendment of the OIL AND
GAS CONSERVATION ACT and the OIL AND GAS CONSERVATION REGULATIONS, 1985. The
program includes a security deposit, which has two purposes: (i) preventing the
individual with insufficient financial capability from acquiring oil and gas
wells or facilities; and (ii) in the case of a bankrupt company, the funds
cover for the decommissioning and reclaiming of orphan property. An additional
change introduced is the mandatory licensing of all upstream oil and gas
facilities in Saskatchewan.
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
65
operations including the oil and gas industry. In addition, the reduction
emission guidelines outlined in the CLIMATE CHANGE AND EMISSIONS MANAGEMENT
AMENDMENT ACT came into effect on July 1, 2007. Under this legislation, Alberta
facilities emitting more than 100,000 tonnes of greenhouse gases a year must
reduce their emissions intensity by 12%. Industries have three options to
choose from in order to meet the reduction requirements outlined in this
legislation, and these are: (i) by making improvement to operations that result
in reductions; (ii) by purchasing emission credits from other sectors or
facilities that have emissions below the 100,000 tonne threshold and are
voluntarily reducing their emission; or (iii) by contributing to the Climate
Change and Emissions Management Fund. Industries can either choose one of these
options or a combination thereof. We will be 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.
In January 24, 2008, the Alberta Government announced a new climate change
action plan that will cut Alberta's projected 400 million tonnes of emissions
in half by 2050. This plan is based on three areas: (i) carbon capture and
storage, which will be mandatory for IN SITU oil sand facilities that use heavy
fuels for steam generation; (ii) energy conservation and efficiency; and (iii)
greening production through increased investment in clean energy technology,
including supporting research on new oil sands extraction processes, as well as
the funding of projects that reduce the cost of separating CO2 from other
emissions supporting carbon capture and storage.
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. 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. For this
purpose, on December 18, 2007 proposals were sought for applications to the
Innovative Clean Energy Fund, in order to attract new technologies that will
help solve energy and environmental issues. 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 establishment 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) new the
Oil and Gas Technology Transfer Incentive Program that encourages the research,
development and use of innovative technologies to increase recoveries from
existing reserves and promotes responsible development of new oil and gas
reserves. Furthering these initiatives, on February 19, 2008 the provincial
Government announced that starting on July 1, 2008, provided the legislation is
approved; a revenue-neutral carbon tax will be applied to all fossil fuels used
in the Province. The tax would be phased in, and the initial rate would be
based on CO2e of $10 per tonne for the first six months of 2009 and $15 per
tonne for the last six months of 2009, following $5 per tonne increases on July
of every year until 2012. Tax credits and reductions will be used in order to
offset the tax revenues that the Government would receive otherwise.
In December, 2002, the Government of Canada ratified the Kyoto Protocol (the
"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 Protocol, was passed by the House of Commons on
February 14, 2007. On April 26, 2007, the Federal Government released its
Action Plan to Reduce Greenhouse Gases and Air Pollution (the "ACTION PLAN")
also known as ecoACTION which includes the regulatory framework for air
emissions. This Action Plan covers not only large industry, but regulates the
fuel efficiency of vehicles and the strengthening of energy standards for a
number of energy using products. The Government of Canada and the Province of
Alberta released on January 31, 2008 the final report of the Canada-Alberta
ecoENERGY Carbon Capture and Storage Task Force, which recommends among others:
(i) incorporating carbon capture and storage into Canada's clean air
regulations; (ii) allocating new funding into projects through competitive
process; and targeting research to lower the cost of technology.
66
Given the evolving nature of the debate related to climate change and the
control of greenhouse gases and resulting requirements, it is not currently
possible to predict either the nature of those requirements or the impact on us
and our operations and financial condition at this time. 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
enactment of the SIFT Tax legislation relating to trusts, such as the Trust.
Under the legislation, trusts such as the Trust 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 - SIFT
TAX".
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 enactment
of the SIFT Tax. 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.
RISK FACTORS
The following is a summary of certain risk factors relating to the business of
AOG and the Trust. The following information is a summary only of certain risk
factors and is qualified in its entirety by reference to, and must be read in
conjunction with, the detailed information appearing elsewhere in this annual
information form.
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DEPENDENCE ON AOG
We are an open-ended, limited purpose trust which will be entirely dependent
upon the operations and assets of AOG through our ownership of the Common
Shares, the Notes and the Royalty. Accordingly, the cash distributions to our
Unitholders will be dependent upon the ability of AOG to meet its interest and
principal repayment obligations under the Notes to declare and pay dividends on
the Common Shares, and to pay the Royalty. AOG's income will be received from
the production of oil and natural gas from AOG's existing Canadian resource
properties and will be susceptible to the risks and uncertainties associated
with the oil and natural gas industry generally. AOG is generally not involved
in the exploration for oil and natural gas. As a result, if the oil and natural
gas reserves associated with AOG's Canadian resource properties are not
supplemented through additional development or the acquisition of additional
Oil and Natural Gas Properties, the ability of AOG to meet its obligations to
us may be adversely affected.
OIL AND NATURAL GAS PRICES
AOG's results of operations and financial condition and the monthly cash
distributions we pay to Unitholders are highly dependent upon the prices
received for AOG's oil and natural gas production. Oil and natural gas prices
can fluctuate widely on a month-to-month basis in response to a variety of
factors that are beyond the control of us and AOG. These factors include, among
others:
o global energy policy, including the ability of OPEC to set and maintain
production levels and prices for oil;
o political conditions throughout the world, including the risk of
hostilities in the Middle East and global terrorism;
o worldwide economic conditions;
o weather conditions;
o the supply and price of foreign oil and natural gas;
o the level of consumer demand;
o the price and availability of alternative fuels;
o the proximity to, and capacity of, transportation facilities;
o the effect of worldwide energy conservation measures; and
o government regulations.
Declines in oil or natural gas prices will have an adverse effect upon our
operations, financial condition, reserves and ultimately on our ability to pay
distributions to Unitholders.
We may manage the risk associated with changes in commodity prices by entering
into oil or natural gas price hedges. If we hedge our commodity price exposure,
we will forego the benefits it would otherwise experience if commodity prices
were to increase. In addition, commodity hedging activities could expose us to
losses. To the extent that we engage in risk management activities related to
commodity prices, we will be subject to credit risks associated with
counterparties with which we contract.
Oil prices were relatively high throughout 2007 averaging US$72.37 WTI as
compared to an average of US$66.35 WTI in 2006, an increase of 9%.
AECO monthly index prices averaged $6.61/Mcf in 2007 as compared to $6.98/Mcf
in 2006, a decrease of 5%. The price of oil and natural gas will fluctuate and
price and demand are factors beyond our control. Such fluctuations will have a
positive or negative effect upon the revenue to be received by it. Such
fluctuations will also have an effect upon the acquisition costs of any future
Oil and Natural Gas Properties that we may acquire. As well, cash distributions
from us will be highly sensitive to the prevailing price of crude oil and
natural gas.
EXPLOITATION AND DEVELOPMENT
Exploitation and development risks are due to the uncertain results of
searching for and producing oil and natural gas using imperfect scientific
methods. These risks are mitigated by using highly skilled staff, focusing
exploitation efforts in areas in which we have existing knowledge and expertise
or access to such expertise, using up-to-date technology to enhance methods,
and controlling costs to maximize returns. Advanced oil and natural gas related
technologies such as three-
68
dimensional seismography, reservoir simulation studies and horizontal drilling
have been and will be used by us to improve our ability to find, develop and
produce oil and natural gas.
OPERATING COSTS AND PRODUCTION DECLINES
Higher operating costs for the underlying properties of AOG will directly
decrease the amount of cash flow received by us and, therefore, may reduce
distributions to our Unitholders. Electricity, chemicals, supplies, reclamation
and abandonment and labour costs are a few of AOG's operating costs that are
susceptible to material fluctuation.
The level of production from AOG's existing properties may decline at rates
greater than anticipated due to unforeseen circumstances, many of which are
beyond AOG's control. A significant decline in production could result in
materially lower revenues and cash flow and, therefore, could reduce the amount
available for distributions to Unitholders.
OPERATIONS
AOG's operations are subject to all of the risks normally incident to the
operation and development of Oil and Natural Gas Properties and the drilling of
oil and natural gas wells, including encountering unexpected formations or
pressures, blow-outs, craterings and fires, all of which could result in
personal injuries, loss of life and damage to the property of AOG and others.
AOG has both safety and environmental policies in place to protect its
operators and employees, as well as to meet the regulatory requirements in
those areas where it operates. In addition, AOG has liability insurance
policies in place, in such amounts as it considers adequate, however, it will
not be fully insured against all of these risks, nor are all such risks
insurable. Costs incurred to repair any of such damage or pay any of such
liabilities will reduce Royalty Income.
Continuing production from a property, and, to some extent the marketing of
production therefrom, are largely dependent upon the ability of the operator of
the property. To the extent the operator fails to perform these functions
properly, revenue may be reduced. Payments from production generally flow
through the operator and there is a risk of delay and additional expense in
receiving such revenues if the operator becomes insolvent. Although
satisfactory title reviews are generally conducted in accordance with industry
standards, such reviews do not guarantee or certify that a defect in the chain
of title may not arise to defeat the claim of AOG to certain Properties. A
reduction of the income from the Royalty could result in such circumstances.
MARKETING
The marketability and price of oil and natural gas that may be acquired or
discovered by us will be affected by numerous factors beyond our control. These
factors include demand for oil and natural gas, market fluctuations, the
proximity and capacity of oil and natural gas pipelines and processing
equipment and government regulations, including regulations relating to
environmental protection, royalties, allowable production, pricing, importing
and exporting of oil and natural gas.
CAPITAL INVESTMENT
To the extent that AOG uses cash flow to finance acquisitions, development
costs and other significant expenditures, the net cash flow of the Trust will
be reduced. Hence, the timing and amount of capital expenditures may affect the
amount of net cash flow available to us and, as a consequence, the amount of
cash available to distribute to Unitholders. Therefore, distributions may be
reduced, or even eliminated, at times when significant capital or other
expenditures are made.
The AOG Board of Directors has the discretion to determine the extent to which
cash flow will be allocated to the payment of debt service charges as well as
the repayment of outstanding debt, including under the credit facility. As a
consequence, the amount of funds retained by AOG to pay debt services charges
or reduce debt will reduce the amount of cash distributed to Unitholders during
those periods in which funds are so retained.
ASSESSMENTS OF VALUE OF ACQUISITIONS
Acquisitions of resource issuers and resource assets will be based in large
part upon engineering and economic assessments made by independent engineers.
These assessments will include a series of assumptions regarding such factors
as recoverability and marketability of oil and gas, future prices of oil and
gas and operating costs, future capital expenditures
69
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 $710,000,000. 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 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.
On March 10, 2008, the Government of Canada released "Turning the Corner -
Taking Action to Fight Climate Change" (the "UPDATED ACTION PLAN") which
provides some additional guidance with respect to the Government's plan to
reduce greenhouse gas emissions by 20% by 2020 and by 60% to 70% by 2050.
The Updated Action Plan is primarily directed towards industrial emissions from
certain specified industries including the oil sands, oil and gas and refining.
The Updated Action Plan is intended to create a carbon emissions trading
market, including an offset system, to provide incentive to reduce greenhouse
gas emission and establish a market price for carbon. There are mandatory
reductions of 18% from the 2006 baseline starting in 2010 and an additional 2%
in subsequent years
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for existing facilities. This target will be applied to regulated sectors on a
facility-specific, sector-wide or corporate basis; in the case of oils sands
production, petroleum refining, natural gas pipelines and upstream oil and gas
the target will be considered facility-specific (sectors in which the
facilities are complex and diverse, or where emissions are affected by factors
beyond the control of the facility operator). Emissions from new facilities,
which are those built between 2004 and 2011, will be based on a cleaner fuel
standard to encourage continuous emissions intensity reductions over time, and
will be granted a 3-year grace period during which no emissions intensity
targets will apply. Targets will begin to apply on the fourth year of
commercial operation and the baseline will be the third year's emissions
intensity, with a 2% continuous annual emission intensity improvement required.
The definition of new facility also includes greenfield facilities, major
expansions constituting more than a 25% increase in a facility's physical
capacity, as well as transformations to a facility that involve significant
changes to its processes. For upstream oil and gas and natural gas pipelines,
it will be applied using a sector-specific approach. For the oil sands, its
application will be process-specific, oil sands plants built in 2012 and later,
those which use heavier hydrocarbons, up-graders and IN-SITU production will
have mandatory standards in 2018 that will be based on carbon capture and
storage.
In the following regulated sectors, the Updated Action Plan will apply only to
facilities exceeding a minimum annual emissions threshold: (i) 50,000 tonnes of
CO2 equivalent per year for natural gas pipelines; (ii) 3,000 tonnes of CO2
equivalent per upstream oil and gas facilities; and (iii) 10,000 boe/d/company.
These proposed thresholds are significantly stricter than the current Alberta
regulatory threshold of 100,000 tonnes of CO2 equivalent per year per facility.
Four separate compliance mechanisms are provided in respect of the above
targets: Technology Fund contributions, offset credits, clean development
credits and credits for early action. The most significant of these compliance
mechanisms, at least initially, will be the Technology Fund and for which
regulated entities will be able to contribute in order to comply with emissions
intensity reductions. The contribution rate will increase over time, beginning
at $15 for the 2010-12 period, rising to $20 in 2013, and thereafter increasing
at the nominal rate of GDP growth. Contribution limits will correspondingly
decline from 70% in 2010 to 0% in 2018. Monies raised through contributions to
the Technology Fund will be used to invest in technology to reduce greenhouse
gas emissions. Alternatively, regulated entities may be able to receive credits
for investing in large-scale and transformative projects at the same
contribution rate and under similar requirements as mentioned above.
The offset system is intended to encourage emissions reductions from activities
outside of the regulated sphere, allowing non-regulated entities to participate
in and benefit from emissions reduction activities. In order to generate offset
credits, project proponents must propose and receive approval for emissions
reduction activities that will be verified before offset credits will be issued
to the project proponent. Those credits can then be sold to regulated entities
for use in compliance or non-regulated purchasers that wish to either cancel
the offset credits or bank them for future use or sale.
Under the Updated Action Plan, regulated entities will also be able to purchase
credits created through the Clean Development Mechanism of the Protocol. The
purchase of such Emissions Reduction Credits will be restricted to 10% of each
firm's regulatory obligation, with the added restriction that credits generated
through forest sink projects will not be available for use in complying with
the Canadian regulations.
Finally, a one-time credit of up to 15 Mt worth of emissions credits will be
awarded to regulated entities for emissions reduction activities undertaken
between 1992 and 2006. These credits will be both tradable and bankable.
Implementation of strategies for reducing greenhouse gases whether to meet the
limits required by the Protocol or the new regulatory framework, 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 at this time either the nature of those requirements or
the impact on the Trust and its operations and financial 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
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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 2007, 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 2007 to an
average $0.94 US/Cdn compared to $0.88 US/Cdn in 2006. 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 and the NYSE.
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.
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;
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o assumptions about future commodity prices, production and development
costs, severance and excise taxes, and capital expenditures;
o initial production rates;
o production decline rates;
o ultimate recovery of reserves;
o timing and amount of capital expenditures;
o marketability of production;
o future prices of oil and natural gas;
o operating costs and royalties; and
o other government levies that may be imposed over the producing life of
reserves.
These factors and assumptions were based upon prices at the date the relevant
evaluations were prepared. If these factors and assumptions prove to be
inaccurate, actual results may vary materially from the reserve estimates. Many
of these factors are subject to change and are beyond our control. For example,
evaluations are based in part upon the assumed success of exploitation
activities intended to be undertaken in future years. Actual reserves and
estimated cash flows will be less than those contained in the evaluations to
the extent that such exploitation activities do not achieve the level of
success assumed in the evaluations. Furthermore, cash flows may differ from
those contained in the evaluations depending upon whether capital expenditures
and operating costs differ from those estimated in the evaluations.
DEPLETION OF RESERVES
We have certain unique attributes that differentiate it from other oil and gas
industry participants. Distributions of distributable income in respect of
Properties, absent commodity price increases or cost effective acquisition and
development activities will decline over time in a manner consistent with
declining production from typical oil, natural gas and natural gas liquids
reserves. AOG will not be reinvesting cash flow in the same manner as other
industry participants. Accordingly, absent capital injections, AOG's initial
production levels and reserves will decline.
AOG's future oil and natural gas reserves and production, and therefore its
cash flows, will be highly dependent upon AOG's success in exploiting its
reserve base and acquiring additional reserves. Without reserve additions
through acquisition or development activities, AOG's reserves and production
will decline over time as reserves are exploited.
To the extent that external sources of capital, including the issuance of
additional Trust Units, become limited or unavailable, AOG's ability to make
the necessary capital investments to maintain or expand its oil and natural gas
reserves will be impaired. To the extent that AOG is required to use cash flow
to finance capital expenditures or property acquisitions, the level of
distributable income will be reduced.
There can be no assurance that we will be successful in developing or acquiring
additional reserves on terms that meet our investment objectives.
RELIANCE UPON THIRD PARTY OPERATORS
Continuing production from a property and marketing of product produced from
the property are dependent to a large extent upon the ability of the operator
of the property. We currently operate properties that represent approximately
85% of our total daily production. To the extent the operator fails to perform
these functions properly or becomes insolvent, revenue may be reduced.
ENFORCEMENT OF OPERATING AGREEMENTS
Operations of the wells on properties not operated by us are generally governed
by operating agreements, which typically require the operator to conduct
operations in a good and workmanlike manner. Operating agreements generally
provide, however, that the operator will have no liability to the other
non-operating working interest owners for losses sustained or liabilities
incurred, except such as may result from gross negligence or wilful misconduct.
In addition, third-party operators are generally not fiduciaries with respect
to us or our Unitholders. As an owner of working interests in 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
73
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 - SIFT TAX
New legislation passed in June 2007 will apply a tax ("SIFT TAX") at the trust
level on distributions of certain income from publicly traded mutual fund
trusts, known as specified investment flow-through ("SIFT") trusts at rates
comparable to the combined federal and provincial corporation tax, and will
treat such distributions as dividends to the unitholders. The Trust is a SIFT
and will be subject to the SIFT Tax. The SIFT Tax results in adverse
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.
Trusts that were in existence on October 31, 2006 will generally have a
four-year transition period, and will not be subject to the SIFT Tax until
January 1, 2011. However, the new legislation provides that there are
circumstances under which an existing trust may lose its transitional relief
before 2011, including where the "normal growth" of a trust existing on October
31, 2006 is exceeded.
"Normal growth" includes 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, the safe harbour limits are cumulative, so that any unused
limit for a period carries over into the subsequent period. The Trust's market
capitalization was approximately $1.6 billion as at October 31, 2006, which
means that the Trust's safe harbour amount for the period ending December 31,
2007 was approximately $640 million, and is an additional $320 million for each
of 2008, 2009 and 2010. The Trust's growth since October 31, 2006 has not been
in excess of "normal growth".
While it is unlikely that the restrictions on "normal growth" will affect our
ability to raise the capital required to maintain and grow our existing
operations in the ordinary course, they could adversely affect the cost of
raising capital and our ability to undertake more significant acquisitions.
Currently, the SIFT Rules provide that the SIFT Tax rate will be the federal
general corporate income tax rate (which is anticipated to be 16.5% in 2011,
and 15% in 2012) plus the provincial SIFT tax factor (which is set at a fixed
rate of 13%), for a combined SIFT tax rate of 29.5% in 2011, and 28% in 2012.
On February 26, 2008, the Minister of Finance announced, and on March 11, 2008,
draft legislation was introduced (the "PROVINCIAL SIFT TAX PROPOSAL"), under
which the effect will be that instead of basing the provincial component of the
SIFT tax on a flat rate of 13%, the provincial component will instead be based
on the general provincial corporate income tax rate in each province in which
the SIFT has a permanent establishment. For purposes of calculating this
component of the tax, the general corporate taxable income allocation formula
will be used. Specifically, the Trust's taxable distributions will be allocated
to provinces by taking half of the aggregate of:
o that proportion of the Trust's taxable distributions for the year
that the Trust's wages and salaries in the province are of its
total wages and salaries in Canada; and
o that proportion of the Trust's taxable distributions for the year
that the Trust's gross revenues in the province are of its total
gross revenues in Canada.
Under the Provincial SIFT Tax Proposal the Trust would likely be considered to
have a permanent establishment in Alberta, where the provincial tax rate in
2011 is expected to be 10%, which will result in an effective SIFT Tax rate of
26.5% in 2011 and 25% in 2012. Taxable distributions that are not allocated to
any province would instead be subject to a 10% rate constituting the provincial
component. There can be no assurance, however, that the Provincial SIFT Tax
Proposal will be enacted as proposed.
74
The new legislation has reduced the value of the Trust Units, which has
increased the cost to the Trust of raising capital in the public capital
markets. In addition management of AOG believes that the SIFT Tax: (a)
substantially eliminates the competitive advantage that the Trust and other
Canadian energy trusts enjoyed relative to their corporate peers in raising
capital in a tax-efficient manner, and (b) places 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 SIFT Tax also makes the Trust Units less
attractive as an acquisition currency. As 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 SIFT Tax.
No assurance can be provided that the SIFT Tax will not apply to the Trust
prior to 2011, or that the income tax legislation will not be further changed
in a manner which affects the Trust and its Unitholders.
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.
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
75
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 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
76
be economically recovered and sold. Accordingly, the distributions received
over the life of the investment may not be equal to or greater than the initial
capital investment.
THE TRUST UNITS ARE NOT "DEPOSITS" WITHIN THE MEANING OF THE CANADA DEPOSIT
INSURANCE CORPORATION ACT (CANADA) AND ARE NOT INSURED UNDER THE PROVISIONS OF
THAT ACT OR ANY OTHER LEGISLATION. FURTHERMORE, THE TRUST IS NOT A TRUST
COMPANY AND, ACCORDINGLY, IS NOT REGISTERED UNDER ANY TRUST AND LOAN COMPANY
LEGISLATION AS IT DOES NOT CARRY ON OR INTEND TO CARRY ON THE BUSINESS OF A
TRUST COMPANY.
NET ASSET VALUE
The net asset value of our assets from time to time will vary depending upon a
number of factors beyond the control of management, including oil and gas
prices. The trading prices of the Trust Units from time to time is also
determined by a number of factors which are beyond the control of management
and such trading prices may be greater than the net asset value of our assets.
ADDITIONAL FINANCING
In the normal course of making capital investments to maintain and expand our
oil and gas reserves, additional Trust Units are issued from treasury which may
result in a decline in production per Trust Unit and reserves per Trust Unit.
Additionally, from time to time we issue Trust Units from treasury in order to
reduce debt and maintain a more optimal capital structure. To the extent that
external sources of capital, including the issuance of additional Trust Units,
become limited or unavailable, our ability and AOG's ability to make the
necessary capital investments to maintain or expand our oil and gas reserves
will be impaired. To the extent that the Trust and AOG are required to use cash
flow to finance capital expenditures or property acquisitions or to pay debt
service charges or to reduce debt, the level of distributable income will be
reduced.
COMPETITION
There is strong competition relating to all aspects of the oil and gas
industry. There are numerous trusts in the oil and gas industry, who are
competing for the acquisitions of properties with longer life reserves and
properties with exploitation and development opportunities. As a result of such
increasing competition, it will be more difficult to acquire reserves on
beneficial terms. The Trust and AOG also compete for reserve acquisitions and
skilled industry personnel with a substantial number of other oil and gas
companies, many of which have significantly greater financial and other
resources than the Trust and AOG.
RETURN OF CAPITAL
Trust Units will have no value when reserves from the Properties can no longer
be economically produced and, as a result, cash distributions do not represent
a "yield" in the traditional sense and are not comparable to bonds or other
fixed yield securities, where investors are entitled to a full return of the
principal amount of debt on maturity in addition to a return on investment
through interest payments. Distributions represent a blend of a return of
Unitholders' initial investment and a return on Unitholders' initial
investment.
Unitholders have a limited right to require us to repurchase their Trust Units,
which is referred to as a redemption right. See "INFORMATION RELATING TO THE
TRUST - RIGHT OF REDEMPTION". It is anticipated that the redemption right will
not be the primary mechanism for Unitholders to liquidate their investment. The
right to receive cash in connection with a redemption is subject to
limitations. Any securities which may be distributed IN SPECIE to Unitholders
in connection with a redemption may not be listed on any stock exchange and a
market may not develop for such securities. In addition, there may be resale
restrictions imposed by law upon the recipients of the securities pursuant to
the redemption right.
REDEMPTION RIGHT
It is anticipated that the redemption right will not be the primary mechanism
for Unitholders to liquidate their investments. Long Term Notes or Redemption
Notes which may be distributed IN SPECIE to Unitholders in connection with a
redemption will not be listed on any stock exchange and no established market
is expected to develop for such Long Term Notes or
77
Redemption Notes. Cash redemptions are subject to limitations. See "ADDITIONAL
INFORMATION RESPECTING ADVANTAGE ENERGY INCOME FUND - REDEMPTION RIGHT".
UNITHOLDER LIMITED LIABILITY
The Trust Indenture provides that no Unitholder will be subject to any
liability in connection with us or our affairs or obligations and, in the event
that a court determines that Unitholders are subject to any such liabilities,
the liabilities will be enforceable only against, and will be satisfied only
out of, such Unitholder's share of our assets.
The Trust Indenture provides that all written instruments signed by or on
behalf of us must contain a provision to the effect that such obligation will
not be binding upon Unitholders personally. Notwithstanding the provisions of
the Trust Indenture and the fact that Alberta (our governing jurisdiction) has
adopted legislation purporting to limit trust unitholder liability, because of
uncertainties in the law relating to investment trusts, there is a risk that a
Unitholder could be held personally liable for obligations of the Trust in
respect of contracts or undertakings which the Trust enters into and for
certain liabilities arising otherwise than out of contracts including claims in
tort, claims for taxes and possibly certain other statutory liabilities. The
possibility of any personal liability of this nature arising is considered
unlikely.
FUTURE DILUTION
One of our objectives is to continually add to our reserves through
acquisitions and through development, and because we does not reinvest our cash
flow, our success is in part dependent upon our ability to raise capital from
time to time. Holders of Trust Units may also suffer dilution in connection
with future issuances of Trust Units, whether issued pursuant to a financing or
acquisition or otherwise.
REGULATORY MATTERS
Our operations are subject to a variety of federal and provincial laws and
regulations, including laws and regulations relating to the protection of the
environment.
THE ECONOMIC IMPACT ON ADVANTAGE OF CLAIMS OF ABORIGINAL TITLE IS UNKNOWN.
Aboriginal people have claimed aboriginal title and rights to a substantial
portion of western Canada. We are unable to assess the effect, if any, that any
such claim would have on our business and operations.
EXPANSION OF OPERATIONS
The operations and expertise of our management are currently focused on
conventional oil and gas production and development in the Western Canadian
Sedimentary Basin. In the future, we may acquire oil and gas properties outside
this geographic area. In addition, the Trust Indenture does not limit our
activities to oil and gas production and development, and we could acquire
other energy related assets, such as oil and natural gas processing plants or
pipelines, or an interest in an oil sands project. Expansion of our activities
into new areas may present new additional risks or alternatively, may
significantly increase the exposure to one or more of the present risk factors
which may result in our future operational and financial conditions being
adversely affected.
CONFLICTS OF INTEREST
The directors and officers of AOG 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 AOG 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.
78
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, the SIFT Tax is anticipated to result in adverse tax consequences
to certain Unitholders including non-resident Unitholders. See "RISK FACTORS -
CHANGES IN LEGISLATION - SIFT TAX".
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
are only required to comply with four 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; 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; and 4) submit an
executed annual written affirmation, as well as an interim affirmation each
time a change occurs to the Audit Committee. We have reviewed the NYSE listing
standards and confirm that our corporate governance practices do not differ
significantly from such standards.
79
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, 2007. Documents affecting the rights of securityholders,
along with additional information relating to Advantage, may be found on SEDAR
at www.sedar.com.
79
SCHEDULE "A"
REPORT OF MANAGEMENT AND DIRECTORS ON RESERVES DATA AND OTHER INFORMATION
(FORM 51-101F3)
Management of Advantage Oil & Gas Ltd. ("AOG") on behalf of Advantage Energy
Income Fund (collectively, the "TRUST") is 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 are estimates of proved reserves and probable reserves and
related future net revenue as at December 31, 2007, estimated using forecast
prices and costs.
An independent qualified reserves evaluator has evaluated the Trust's reserves
data. The report of the independent qualified reserves evaluator is presented
below.
The independent reserves evaluation committee of the Trust has:
(a) reviewed the Trust's procedures for providing information to the
independent qualified reserves evaluator;
(b) met with the independent qualified reserves evaluator to determine
whether any restrictions affected the ability of the independent
qualified reserves evaluator to report without reservation; and
(c) reviewed the reserves data with management and the independent
qualified reserves evaluator.
The 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:
(a) the content and filing with securities regulatory authorities of
Form 51-101F1 containing reserves data and other oil and gas
information;
(b) the filing of Form 51-101F2 which is the report of the independent
qualified reserves evaluator on the reserves data; and
(c) the content and filing of this report.
Because the reserves data are based on judgments regarding future events,
actual results will vary and the variations may be material. However, any
variations should be consistent with the fact that reserves are categorized
according to the probability of their recovery.
(signed) "KELLY I. DRADER" (signed) "PETER A. HANRAHAN"
Kelly I. Drader Peter A. Hanrahan
Chief Executive Officer Vice President, Finance and Chief
Financial Officer
(signed) "RONALD A. MCINTOSH" (signed) "JOHN HOWARD"
Ronald A. McIntosh John Howard Director Director
February 21, 2008
SCHEDULE "B"
REPORT ON RESERVES DATA
BY INDEPENDENT QUALIFIED RESERVES EVALUATOR OR AUDITOR
(FORM 51-101 F2)
To the Board of Directors of Advantage Oil & Gas Ltd., on behalf of Advantage
Energy Income Fund (the "TRUST"):
1. We have evaluated the Trust's Reserves Data as at December 31, 2007. The
reserves data are estimates of proved reserves and probable reserves and
related future net revenue as at December 31, 2007, estimated using
forecast prices and costs.
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 on a before tax basis and calculated using a discount
rate of 10%, included in the reserves data of the Trust evaluated by us
as of December 31, 2007, 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:
Net Present Value of Future Net Revenue
Before Income Taxes (10% Discount Rate)
Independent Qualified --------------------------------------------
Reserves Evaluator or Description and Preparation Location of Audited Evaluated Reviewed Total
Auditor Date of Evaluation Report Reserves (County) (M$) (M$) (M$) (M$)
- -------------------------- --------------------------- ----------------- ------- --------- -------- -----
Evaluation of the P&NG
Reserves of Advantage Oil &
Sproule Associates Gas Ltd.,
Limited Canada
As of December 31, 2007,
prepared September 2007 to
February 2008
TOTAL 261,420 2,201,190 NIL 2,462,610
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 on judgements regarding future
events, actual results will vary and the variations may be material.
However, any variations should be consistent with the fact that reserves
are categorized according to the probability of their recovery.
(signed) "SPROULE ASSOCIATES LIMITED"
Sproule Associates Limited
Calgary, Alberta
February 21, 2008