EXHIBIT 99.95
-------------
NO SECURITIES REGULATORY AUTHORITY HAS EXPRESSED AN OPINION ABOUT THESE
SECURITIES AND IT IS AN OFFENCE TO CLAIM OTHERWISE.
THIS SHORT FORM PROSPECTUS CONSTITUTES A PUBLIC OFFERING OF THESE SECURITIES
ONLY IN THOSE JURISDICTIONS WHERE THEY MAY BE LAWFULLY OFFERED FOR SALE AND
THEREIN ONLY BY PERSONS PERMITTED TO SELL SUCH SECURITIES. THESE SECURITIES HAVE
NOT BEEN AND WILL NOT BE REGISTERED UNDER THE UNITED STATES SECURITIES ACT OF
1933, AS AMENDED, OR ANY STATE SECURITIES LAWS. ACCORDINGLY, THESE SECURITIES
MAY NOT BE OFFERED OR SOLD WITHIN THE UNITED STATES AND THIS SHORT FORM
PROSPECTUS DOES NOT CONSTITUTE AN OFFER TO SELL OR A SOLICITATION OF AN OFFER TO
BUY ANY OF THESE SECURITIES WITHIN THE UNITED STATES. SEE "PLAN OF
DISTRIBUTION".
NEW ISSUE SEPTEMBER 3, 2004
SHORT FORM PROSPECTUS
[GRAPHIC OMITTED]
[LOGO - ADVANTAGE ENERGY INCOME FUND]
$65,800,000
3,500,000 SUBSCRIPTION RECEIPTS,
EACH REPRESENTING THE RIGHT TO RECEIVE ONE TRUST UNIT
AND
$75,000,000
7.50% EXTENDIBLE CONVERTIBLE UNSECURED SUBORDINATED DEBENTURES
AND
$50,000,000
7.75% EXTENDIBLE CONVERTIBLE UNSECURED SUBORDINATED DEBENTURES
SUBSCRIPTION RECEIPTS
Advantage Energy Income Fund (the "TRUST" or "ADVANTAGE") is hereby qualifying
for distribution 3,500,000 subscription receipts ("SUBSCRIPTION RECEIPTS"), each
of which will entitle the holder thereof to receive, without payment of
additional consideration, one trust unit ("UNIT" or "TRUST UNIT") of the Trust
upon closing of the acquisition (the "ACQUISITION") by Advantage Oil & Gas Ltd.
("AOG"), a wholly-owned subsidiary of the Trust, of certain petroleum and
natural gas properties and related assets currently owned by Anadarko Canada
Corporation ("ANADARKO") described in more detail under "Recent Developments -
Acquisition". The proceeds from the sale of the Subscription Receipts (the
"ESCROWED FUNDS") will be held by Computershare Trust Company of Canada, as
escrow agent (the "ESCROW AGENT"), and invested in short-term obligations of, or
guaranteed by, the Government of Canada (and other approved investments) pending
completion of the Acquisition. Upon the Acquisition being completed on or before
November 1, 2004, the Escrowed Funds and the interest thereon will be released
to the Trust and the Units will be issued to the holders of Subscription
Receipts. The Trust will utilize the Escrowed Funds and the proceeds from the
sale of Debentures described below to pay a portion of the purchase price for
the Acquisition.
If the closing of the Acquisition does not take place by 5:00 p.m. (Calgary
time) on November 1, 2004, or if the Acquisition Agreement or any amendment
thereto is terminated at any earlier time or if the Trust has advised the
Underwriters or announced to the public that it does not intend to proceed with
the Acquisition (in any case, the "TERMINATION TIME"), holders of Subscription
Receipts shall be entitled to receive an amount equal to the full subscription
price therefor and their PRO RATA entitlements to interest on such amount. The
Escrowed Funds and interest earned thereon will be applied towards payment of
such amount.
If the closing of the Acquisition takes place prior to the Termination Time and
holders of Subscription Receipts become entitled to receive Units, such holders
will be entitled to receive an amount per Subscription Receipt equal to the
amount per Unit of any cash distributions for which record dates have occurred
during the period from the date of closing of the offering to the date
immediately preceding the date the Units are issued pursuant to the
2
Subscription Receipts. Accordingly, if the Acquisition closes on or before
September 30, 2004 as currently contemplated, holders of Subscription Receipts
will become holders of Units on or before September 30, 2004 and will be
entitled, provided they are the holders of record of Units received pursuant to
the Subscription Receipts on September 30, 2004, to receive the monthly
distribution expected to be paid on October 15, 2004 to Unitholders of record on
September 30, 2004. If the closing of the Acquisition occurs after September 30,
2004, but on or before November 1, 2004, holders of record of Subscription
Receipts on the date they are exchanged for Units will be entitled to receive a
payment equivalent to the distribution that will be paid by the Trust to
Unitholders of record on September 30, 2004 or any subsequent Unit distribution
record date (being on or about the last day of each month) prior to such
closing. See "Details of the Offering".
7.50% DEBENTURES
The Trust is also hereby qualifying for distribution 75,000 7.50% extendible
convertible unsecured subordinated debentures (the "7.50% DEBENTURES") of the
Trust at a price of $1,000 per Debenture. The 7.50% Debentures have an initial
maturity date of November 1, 2004 (the "INITIAL MATURITY DATE"). If the closing
of the Acquisition takes place by the Termination Time, the maturity date will
be automatically extended from the Initial Maturity Date to October 1, 2009 (the
"7.50% FINAL MATURITY DATE"). If closing of the Acquisition does not take place
by the Termination Time, the 7.50% Debentures will mature on the Initial
Maturity Date. See "Details of the Offerings".
The 7.50% Debentures bear interest at an annual rate of 7.50% payable
semi-annually on April 1 and October 1 in each year commencing April 1, 2005.
The 7.50% Debentures are redeemable by the Trust at a price of $1,050 per 7.50%
Debenture after October 1, 2007 and on or before October 1, 2008 and at a price
of $1,025 per 7.50% Debenture after October 1, 2008 and before maturity on
October 1, 2009, in each case, plus accrued and unpaid interest thereon, if any.
See "Details of the Offerings".
- --------------------------------------------------------------------------------
7.50% DEBENTURE CONVERSION PRIVILEGE
Each 7.50% Debenture will be convertible into Units at the option of the holder
at any time prior to the close of business on the earlier of maturity and the
business day immediately preceding the date specified by the Trust for
redemption of the 7.50% Debentures, at a conversion price of $20.25 per Unit,
subject to adjustment in certain events. Holders converting their 7.50%
Debentures will receive accrued and unpaid interest thereon. Notwithstanding the
foregoing, no Debentures may be converted during the three business days
preceding April 1 and October 1, in each year, commencing April 1, 2005, as the
registers of the Debenture Trustee will be closed during such periods.
- --------------------------------------------------------------------------------
7.75% DEBENTURES
The Trust is also hereby qualifying for distribution 50,000 7.75% extendible
convertible unsecured subordinated debentures (the "7.75% DEBENTURES") of the
Trust at a price of $1,000 per Debenture. The 7.75% Debentures have an initial
maturity date of November 1, 2004. If the closing of the Acquisition takes place
by the Termination Time, the maturity date will be automatically extended from
the Initial Maturity Date to December 1, 2011 (the "7.75% FINAL MATURITY DATE").
If closing of the Acquisition does not take place by the Termination Time, the
7.75% Debentures will mature on the Initial Maturity Date. See "Details of the
Offerings".
The 7.75% Debentures bear interest at an annual rate of 7.75% payable
semi-annually on June 1 and December 1 in each year commencing June 1, 2005. The
7.75% Debentures are redeemable by the Trust at a price of $1,050 per 7.75%
Debenture after December 1, 2007, and on or before December 1, 2008, at a price
of $1,025 per 7.75% Debenture after December 1, 2008 and on or before December
1, 2009 and at a price of $1,000 per 7.75% Debenture after December 1, 2009 and
before maturity on December 1, 2011, in each case, plus accrued and unpaid
interest thereon, if any. See "Details of the Offerings".
3
- --------------------------------------------------------------------------------
7.75% DEBENTURE CONVERSION PRIVILEGE
Each 7.75% Debenture will be convertible into Units at the option of the holder
at any time prior to the close of business on the earlier of maturity and the
business day immediately preceding the date specified by the Trust for
redemption of the 7.75% Debentures, at a conversion price of $21.00 per Unit,
subject to adjustment in certain events. Holders converting their 7.75%
Debentures will receive accrued and unpaid interest thereon. Notwithstanding the
foregoing, no 7.75% Debentures may be converted during the three business days
preceding June 1 and December 1, in each year, commencing June 1, 2005, as the
registers of the Debenture Trustee will be closed during such periods.
- --------------------------------------------------------------------------------
In the opinion of counsel, subject to the qualifications and assumptions
discussed under the headings "Canadian Federal Income Tax Considerations" and
"Eligibility for Investment", on the date of closing, the Subscription Receipts,
the Debentures and the Units issuable pursuant to the Subscription Receipts and
on conversion, redemption or maturity of the Debentures, will be qualified
investments under the INCOME TAX ACT (Canada) and the regulations thereunder for
trusts governed by registered retirement savings plans, registered retirement
income funds, deferred profit sharing plans (except, in the case of the
Debentures, a deferred profit sharing plan to which the Trust has made a
contribution) and registered education savings plans.
The issued and outstanding Units are listed on the Toronto Stock Exchange (the
"TSX") under the trading symbol AVN.UN. On August 23, 2004, the last trading day
prior to the public announcement of the offering, and on September 2, 2004, the
closing price of the Units on the TSX was $19.35 and $19.96, respectively. The
TSX has conditionally approved the listing of the Subscription Receipts, the
Debentures and the Units issuable pursuant to the Subscription Receipts and on
the conversion, redemption and maturity of the Debentures. Listing is subject to
the Trust fulfilling all of the listing requirements of the TSX on or before
November 24, 2004. The offering price of the Subscription Receipts and
Debentures was determined by negotiation between Advantage Investment Management
Ltd. (the "MANAGER") and AOG on behalf of the Trust, and Scotia Capital Inc., on
its own behalf and on behalf of BMO Nesbitt Burns Inc., National Bank Financial
Inc., RBC Dominion Securities Inc., CIBC World Markets Inc., FirstEnergy Capital
Corp. and Raymond James Ltd. (collectively, the "UNDERWRITERS").
NET PROCEEDS
PRICE TO THE PUBLIC UNDERWRITERS' FEE(1) TO THE TRUST (2)
------------------- -------------------- ----------------
Per Subscription Receipt $ 18.80 $ 0.94 $ 17.86
Total $ 65,800,000 $ 3,290,000 $ 62,510,000
Per 7.50% Debenture $ 1,000 $ 40 $ 960
Total $ 75,000,000 $ 3,000,000 $ 72,000,000
Per 7.75% Debenture $ 1,000 $ 40 $ 960
Total $ 50,000,000 $ 2,000,000 $ 48,000,000
TOTAL $190,800,000 $ 8,290,000 $182,510,000
Notes:
(1) The Underwriters' fee with respect to the Subscription Receipts is payable
as to 50% upon the closing of the offering and 50% on the release of the
Escrowed Funds to the Trust. If the Acquisition is not completed, the
Underwriters' fee with respect to the Subscription Receipts will be reduced
to the amount payable upon closing of the offering.
(2) Excluding interest, if any, on the Escrowed Funds and before deducting
expenses of the offering estimated to be $600,000, which will be paid from
the general funds of the Trust.
The Underwriters, as principals, conditionally offer the Subscription Receipts
and the Debentures, subject to prior sale, if, as and when issued by the Trust
and delivered and accepted by the Underwriters in accordance with the conditions
contained in the Underwriting Agreement referred to under "Plan of Distribution"
and subject to approval of certain legal matters relating to the offering on
behalf of the Trust by Burnet, Duckworth & Palmer LLP and on behalf of the
Underwriters by Macleod Dixon LLP.
4
SCOTIA CAPITAL INC., BMO NESBITT BURNS INC., NATIONAL BANK FINANCIAL INC. AND
RBC DOMINION SECURITIES INC., FOUR OF THE UNDERWRITERS, ARE INDIRECT
WHOLLY-OWNED SUBSIDIARIES OF CANADIAN CHARTERED BANKS WHICH ARE LENDERS TO THE
TRUST. CONSEQUENTLY, THE TRUST MAY BE CONSIDERED TO BE A CONNECTED ISSUER OF
THESE UNDERWRITERS FOR THE PURPOSES OF SECURITIES REGULATIONS IN CERTAIN
PROVINCES. A PORTION OF THE NET PROCEEDS OF THIS OFFERING RECEIVED BY THE TRUST
WILL BE USED TO REDUCE THE INDEBTEDNESS OF THE TRUST TO SUCH BANKS. SEE
"RELATIONSHIP AMONG THE TRUST AND CERTAIN UNDERWRITERS" AND "USE OF PROCEEDS".
THERE IS CURRENTLY NO MARKET THROUGH WHICH THE SUBSCRIPTION RECEIPTS OR
DEBENTURES MAY BE SOLD AND PURCHASERS MAY NOT BE ABLE TO RESELL SUBSCRIPTION
RECEIPTS OR DEBENTURES PURCHASED UNDER THIS SHORT FORM PROSPECTUS.
Subscriptions for Subscription Receipts and Debentures will be received subject
to rejection or allotment in whole or in part and the right is reserved to close
the subscription books at any time without notice. It is expected that closing
will occur on or about September 14, 2004 or such other date as the Trust and
the Underwriters may agree. The Subscription Receipts will be represented by a
global certificate issued in registered form to the Canadian Depository for
Securities Limited ("CDS") or its nominee under the book-based system
administered by CDS. Certificates for the aggregate principal amount of the
7.50% Debentures and 7.75% Debentures will be issued in registered form to CDS
and will be deposited with CDS on the date of closing. No certificates
evidencing the Subscription Receipts, 7.50% Debentures and 7.75% Debentures will
be issued to subscribers except in certain limited circumstances, and
registration will be made in the depositary service of CDS. Subscribers for
Subscription Receipts and Debentures will receive only a customer confirmation
from the Underwriter or other registered dealer who is a CDS participant and
from or through whom a beneficial interest in the Subscription Receipts or
Debentures is purchased. Subject to applicable laws, the Underwriters may, in
connection with the offering, effect transactions which stabilize or maintain
the market price of the Subscription Receipts, the Units or the Debentures at
levels other than those that might otherwise prevail on the open market. See
"Plan of Distribution".
THE SUBSCRIPTION RECEIPTS, THE UNITS AND THE DEBENTURES 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, IT 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.
5
TABLE OF CONTENTS
Page
SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS.............................6
SELECTED ABBREVIATIONS........................................................7
DEFINITIONS...................................................................7
NON-GAAP MEASURES............................................................13
DOCUMENTS INCORPORATED BY REFERENCE..........................................14
ADVANTAGE ENERGY INCOME FUND.................................................15
DESCRIPTION OF BUSINESS......................................................15
RECENT DEVELOPMENTS..........................................................16
INFORMATION CONCERNING THE ASSETS............................................18
EFFECT OF THE ACQUISITION ON THE TRUST.......................................28
DESCRIPTION OF TRUST UNITS...................................................30
EARNINGS COVERAGE............................................................31
CONSOLIDATED CAPITALIZATION OF THE TRUST.....................................32
PRICE RANGE AND TRADING VOLUME OF THE TRUST UNITS............................33
RECORD OF CASH DISTRIBUTIONS.................................................33
USE OF PROCEEDS..............................................................35
DETAILS OF THE OFFERINGS.....................................................35
PLAN OF DISTRIBUTION.........................................................43
RELATIONSHIP AMONG THE TRUST AND CERTAIN UNDERWRITERS........................44
INTEREST OF EXPERTS..........................................................44
CANADIAN FEDERAL INCOME TAX CONSIDERATIONS...................................44
ELIGIBILITY FOR INVESTMENT...................................................50
RISK FACTORS.................................................................50
MATERIAL CONTRACTS...........................................................52
LEGAL PROCEEDINGS............................................................52
AUDITORS, TRANSFER AGENT AND REGISTRAR.......................................52
STATUTORY AND CONTRACTUAL RIGHTS OF RESCISSION AND STATUTORY
RIGHTS OF WITHDRAWAL.........................................................52
AUDITORS' CONSENT............................................................53
AUDITORS' CONSENT............................................................53
AUDITORS' CONSENT............................................................53
SCHEDULE "A" - UNAUDITED PROFORMA CONSOLIDATED FINANCIAL STATEMENTS A-1
SCHEDULE "B" - SCHEDULE OF REVENUES AND EXPENSES B-1
SCHEDULE "C" - UNAUDITED FINANCIAL STATEMENTS OF MARKWEST RESOURCES
CANADA CORP. FOR THE NINE-MONTH PERIOD ENDED
SEPTEMBER 30, 2003 C-1
CERTIFICATE OF THE TRUST D-1
CERTIFICATE OF THE UNDERWRITERS D-2
6
SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS
Certain statements contained in this short form prospectus, and in certain
documents incorporated by reference into this short form prospectus, constitute
forward-looking statements. These statements relate to future events or the
Trust's 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. The
Trust and AOG believe the expectations reflected in those forward-looking
statements are reasonable but no assurance can be given that these expectations
will prove to be correct and such forward-looking statements included in, or
incorporated by reference into, this short form prospectus should not be unduly
relied upon. These statements speak only as of the date of this short form
prospectus or as of the date specified in the documents incorporated by
reference into this short form prospectus, as the case may be.
In particular, this short form prospectus, and the documents incorporated by
reference, contain forward-looking statements pertaining to the following:
o the timing of the closing of the proposed Acquisition;
o the performance characteristics of the Trust's assets and the 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 short form prospectus:
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 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 short form prospectus and the documents incorporated by reference herein
are expressly qualified by this cautionary statement. Neither the Trust, the
Manager, nor AOG undertakes any obligation to publicly update or revise any
forward-looking statements.
7
SELECTED ABBREVIATIONS
In this short form prospectus, the abbreviations set forth below have the
meanings indicated:
"BBL" means one barrel "BOE/D" means barrels of oil equivalent per day
"BBLS" means barrels "MBBLS" means one thousand barrels
"BBLS/D" means barrels per day "MBOE" means one thousand barrels of oil equivalent
"BCF" means one billion cubic feet "MMBOE" means one million barrels of oil equivalent
"BOE" means barrels of oil equivalent. A "MCF" means one thousand cubic feet
barrel of oil equivalent is determined by
converting a volume of natural gas to barrels "MMCF" means one million cubic feet
using the ratio of six mcf to one barrel.
Boes may be misleading, particularly if used "MMCF/D" means one million cubic feet per day
in isolation. The boe conversion ratio of 6
mcf:1 bbl is based on an energy equivalency "NGL" means natural gas liquids
method primarily applicable at the burner tip
and does not represent a value equivalency at "$M" or "M$" means thousands of dollars
the wellhead.
DEFINITIONS
In this short form prospectus, the terms set forth below have the meanings
indicated:
"7.50% DEBENTURES" means the 7.50% extendible convertible unsecured subordinated
debentures of the Trust offered hereby;
"7.50% FINAL MATURITY DATE" means October 1, 2009;
"7.75% DEBENTURES" means the 7.75% extendible convertible unsecured subordinated
debentures of the Trust offered hereby;
"7.75% FINAL MATURITY DATE" means December 1, 2011;
"8.25% DEBENTURES" means the 8.25% convertible unsecured subordinated debentures
of the Trust due February 1, 2009;
"8.50% NOTES" means the 8.50% unsecured subordinated promissory notes of AOG
issued on December 2, 2003;
"9.00% DEBENTURES" means the 9.00% convertible unsecured subordinated debentures
of the Trust due August 1, 2008;
"9 3/8% NOTES" means the 9 3/8% unsecured promissory notes of AOG issued on July
8, 2003;
"10.00% DEBENTURES" means the 10.00% convertible unsecured subordinated
debentures of the Trust due November 1, 2007;
"10 3/8% NOTES" means the 10 3/8% unsecured promissory notes of AOG issued on
October 18, 2002;
"ABCA" means the BUSINESS CORPORATIONS ACT (Alberta), R.S.A. 2000, c. B-9, as
amended, including the regulations promulgated thereunder;
"ACQUISITION" means the acquisition by AOG, pursuant to the Acquisition
Agreement, of the Assets;
8
"ACQUISITION AGREEMENT" means the Agreement of Purchase and Sale dated August
24, 2004 between Anadarko and AOG pursuant to which Anadarko agreed to sell and
AOG agreed to purchase the Assets;
"AIF" means the Renewal Annual Information Form of the Trust for the year ended
December 31, 2003 dated May 12, 2004;
"ANADARKO" means Anadarko Canada Corporation, the managing partner of Anadarko
Canada Resources;
"AOG" 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;
"ARC" means credits or rebates in respect of Crown royalties which are paid or
credited by the Crown, including those paid or credited under the ALBERTA
CORPORATE TAX ACT which are commonly known as "Alberta Royalty Credits";
"ASSETS" means those petroleum and natural gas properties and related assets
that the Trust will indirectly own following completion of the Acquisition,
described in more detail under "Information Concerning the Assets";
"BUSINESS DAY" means a day, which is not a Saturday, Sunday or statutory
holiday, when banks in the place at which any action is required to be taken
hereunder are generally open for the transaction of commercial banking business;
"CONSTANT PRICES AND COSTS" means prices and costs used in an estimate that are:
(a) the issuer's prices and costs as at the effective date of the
estimation, held constant throughout the estimated lives of the
properties to which the estimate applies; and
(b) if, and only to the extent that, there are fixed or presently
determinable future prices or costs to which the issuer is legally
bound by a contractual or other obligation to supply a physical
product, including those for an extension period of a contract that is
likely to be extended, those prices or costs rather than the prices and
costs referred to in paragraph (a);
"CREDIT FACILITIES" has the meaning ascribed thereto in Note 1 to the table
under "Consolidated Capitalization of the Trust";
"DEBENTURE TRUSTEE" means Computershare Trust Company of Canada or its successor
as trustee under the Indenture;
"DEBENTURES" means collectively, the 7.50% Debentures and the 7.75% Debentures;
"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;
9
(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;
"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 certainty;
"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;
"DEVELOPMENT WELL" means a well drilled inside the established limits of an oil
and gas reservoir, or in close proximity to the edge of the reservoir, to the
depth of a stratigraphic horizon known to be productive;
"ESCROW AGENT" means Computershare Trust Company of Canada or its successor as
escrow agent under the Subscription Receipt Agreement;
"ESCROWED FUNDS" means the proceeds from the sale of the Subscription Receipts;
"EXPLORATION COSTS" means costs incurred in identifying areas that may warrant
examination and in examining specific areas that are considered to have
prospects that may contain oil and gas Reserves, including costs of drilling
exploratory wells and exploratory type stratigraphic test wells. Exploration
costs may be incurred both before acquiring the related property and after
acquiring the property. Exploration costs, which include applicable operating
costs of support equipment and facilities and other costs of exploration
activities, are:
(a) costs of topographical, geochemical, geological and geophysical
studies, rights of access to properties to conduct those studies, and
salaries and other expenses of geologists, geophysical crews and others
conducting those studies;
(b) costs of carrying and retaining unproved properties, such as delay
rentals, taxes (other than income and capital taxes) on properties,
legal costs for title defence, and the maintenance of land and lease
records;
(c) dry hole contributions and bottom hole contributions;
(d) costs of drilling and equipping exploratory wells; and
(e) costs of drilling exploratory type stratigraphic test wells;
"FORECAST PRICES AND COSTS" means future prices and costs that are:
(a) generally acceptable as being a reasonable outlook of the future; and
(b) if and only to the extent that, there are fixed or presently
determinable future prices or costs to which the issuer is legally
bound by a contractual or other obligation to supply a physical
product, including those for an extension period of a contract that is
likely to be extended, those prices or costs rather than the prices and
costs referred to in paragraph (a);
"GROSS" means:
(a) in relation to an issuer's interest in production or Reserves, its
"issuer gross Reserves", which are the issuer's working interest
(operating and non-operating) share before deduction of royalties and
without including any royalty interest of such issuer;
10
(b) in relation to wells, the total number of wells in which the issuer has
an interest; and
(c) in relation to properties, the total area of properties in which the
issuer has an interest;
"INDENTURE" means, collectively, the trust indenture dated July 8, 2003 between
the Trust, AOG and the Debenture Trustee and a second supplemental trust
indenture to be dated as of the date of closing of the offering between the
Trust, AOG and the Debenture Trustee governing the terms of the Debentures;
"INITIAL MATURITY DATE" means November 1, 2004;
"MANAGEMENT AGREEMENT" means the management, advisory and administration
agreement dated May 24, 2001, as amended, among 925212 Alberta Ltd., the Manager
and the Trustee, on behalf of the Trust;
"MANAGER" means Advantage Investment Management Ltd., a corporation incorporated
under the ABCA;
"MARKWEST" means MarkWest Resources Canada Corp., a corporation incorporated
under the ABCA which was acquired by AOG on December 2, 2003;
"NET" means:
(a) in relation to an issuer's interest in production or Reserves, its
"issuer gross Reserves", which are the issuer's working interest
(operating and non-operating) share after deduction of royalty
obligations, plus the issuer's royalty interest in production or
Reserves;
(b) in relation to wells, the number of wells obtained by aggregating the
issuer's working interest in each of its Gross wells; and
(c) in relation to the issuer's interest in a property, the total area in
which the issuer has an interest multiplied by the working interest
owned by the issuer;
"NOTES" means the 14% unsecured subordinated promissory notes of AOG originally
issued on May 24, 2001;
"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 the total assets of
the Trust (unless otherwise approved by AOG's 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 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;
"PROVED RESERVES" are those Reserves that can be estimated with a high degree of
certainty to be recoverable. There is believed to be at least a 90% probability
that the quantities actually recovered will equal or exceed the estimated Proved
Reserves;
11
"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 lesser than the sum of the estimated
Proved plus Probable Reserves. There is believed to be at least a 50 percent
probability that the quantities actually recovered will equal or exceed the sum
of the estimated Proved plus Probable Reserves;
"REDEMPTION NOTES" means notes issued in certain circumstances including by the
Trust on a redemption of Trust Units;
"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
(a) analysis of drilling, geological, geophysical and engineering data;
(b) the use of established technology; and
(c) specified economic conditions which are generally accepted as being
reasonable;
"ROYALTY" means the 95% interest in AOG's Petroleum Substances within, upon or
under certain of its Oil and Natural Gas Properties granted pursuant to the
Royalty Agreement;
"ROYALTY AGREEMENT" means the amended and restated royalty agreement entered
into between AOG and the Trust dated as of December 1, 2003 and providing for
the creation of the Royalty;
"SETTLED AMOUNT" means the amount of one hundred dollars in lawful money of
Canada paid by the settlor of the Trust to the Trustee for the purpose of
settling the Trust;
"SPROULE" means Sproule Associates Limited, independent geological and petroleum
engineering consultants of Calgary, Alberta;
"SPROULE ANADARKO REPORT" means the independent engineering evaluation effective
July 1, 2004 of the oil, NGL and natural gas Reserves and the present worth
value of these Reserves for the oil, NGL and natural gas interests of Anadarko
in the Assets prepared by Sproule, based on forecast and constant prices and
costs as at July 1, 2004;
"SUBSCRIPTION RECEIPT AGREEMENT" means the agreement to be dated the date of
closing of the offering among the Trust, the Underwriters and the Escrow Agent
governing the terms of the Subscription Receipts;
"SUBSCRIPTION RECEIPTS" means the subscription receipts of the Trust offered
hereby;
"TAX ACT" means the INCOME TAX ACT (Canada), R.S.C. 1985, c. 1 (5th Supp), as
amended, including the regulations promulgated thereunder;
"TRUST" or "ADVANTAGE" means Advantage Energy Income Fund, a trust established
under the laws of Alberta pursuant to the Trust Indenture. All references to the
"Trust" or "Advantage", unless the context otherwise requires, are references to
Advantage Energy Income Fund, its predecessors, and its subsidiaries;
"TRUSTEE" means Computershare Trust Company of Canada or such other trustee,
from time to time, of the Trust;
"TRUST INDENTURE" means the trust indenture between Computershare Trust Company
of Canada and AOG made as of April 17, 2001, supplemented as of May 22, 2002 and
amended and restated as of June 25, 2002, May 28, 2003 and May 26, 2004;
"TSX" means the Toronto Stock Exchange;
"UNDERWRITERS" means, collectively, Scotia Capital Inc., BMO Nesbitt Burns Inc.,
National Bank Financial Inc. RBC Dominion Securities Inc., CIBC World Markets
Inc., FirstEnergy Capital Corp. and Raymond James Ltd.;
12
"UNDERWRITING AGREEMENT" means the agreement dated August 24, 2004 among the
Trust, AOG, the Manager and the Underwriters in respect of this offering;
"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 (eg., Proved or
Probable) to which they are assigned;
"UNITED STATES" or "U.S." means the United States of America;
"UNITHOLDERS" means the holders from time to time of the Units; and
"UNITS" or "TRUST UNITS" means trust units of the Trust.
Words importing the singular number only include the plural, and VICE VERSA, and
words importing any gender include all genders.
All dollar amounts set forth in this short form prospectus are in Canadian
dollars, except where otherwise indicated.
13
NON-GAAP MEASURES
In this prospectus, the Trust uses the terms "cash flow", "funds flow from
operations" and "cash available for distribution" to refer to the amount of cash
available for distribution to Unitholders and as indicators of financial
performance. "Cash flow", "funds flow from operations" and "cash available for
distribution" are not measures recognized by Canadian generally accepted
accounting principles ("GAAP") and do not have standardized meanings prescribed
by GAAP. Therefore, "cash flow", "funds flow from operations" and "cash
available for distribution" of the Trust may not be comparable to similar
measures presented by other issuers, and investors are cautioned that "cash
flow", "funds flow from operations" and "cash available for distribution" should
not be construed as alternatives to net earnings, cash flow from operating
activities or other measures of financial performance calculated in accordance
with GAAP. All references to "cash flow" and "funds flow from operations" are
based on cash flow before changes in non-cash working capital related to
operating activities, as presented in the consolidated financial statements of
the Trust. Cash available for distribution cannot be assured and future
distributions may vary. The Trust uses such terms and, particularly, "cash
available for distribution" as an indicator of financial performance because
such terms are commonly utilized by investors to evaluate royalty trusts and
income funds in the oil and gas sector. The Trust believes that "cash available
for distribution" is a useful supplemental measure as it provides investors with
information of what cash is available for distribution from the Trust to
Unitholders in such periods.
14
DOCUMENTS INCORPORATED BY REFERENCE
INFORMATION HAS BEEN INCORPORATED BY REFERENCE IN THIS SHORT FORM PROSPECTUS
FROM DOCUMENTS FILED WITH SECURITIES COMMISSIONS OR SIMILAR AUTHORITIES IN
CANADA. Copies of the documents incorporated herein by reference may be obtained
on request without charge from the Vice President, Finance and Chief Financial
Officer of AOG at Suite 3100, 150 - 6th Avenue S.W., Calgary, Alberta T2P 3H7,
telephone (403) 261-8810. For the purpose of the Province of Quebec, this
simplified prospectus contains information to be completed by consulting the
permanent information record. A copy of the permanent information record may be
obtained from the Vice President, Finance and Chief Financial Officer of
Advantage at the above-mentioned address and telephone number.
The following documents of the Trust, filed with the various securities
commissions or similar authorities in the provinces of Canada, are specifically
incorporated by reference into and form an integral part of this short form
prospectus:
1. the Trust's Revised Renewal Annual Information Form (the "AIF") dated
May 12, 2004;
2. the audited comparative consolidated financial statements of the Trust
for the years ended December 31, 2003 and 2002, together with the
report of the auditors' thereon;
3. management's discussion and analysis of Advantage for the year ended
December 31, 2003;
4. the information circular - proxy statement of the Trust dated April 16,
2004 relating to the annual and special meeting of holders of Trust
Units held on May 26, 2004 (excluding those portions thereof which
appear under the headings "Performance Chart" and "Corporate
Governance"); and
5. the unaudited interim comparative consolidated financial statements of
the Trust and management's discussion and analysis of the financial
condition and operations of the Trust as at and for the three and six
month periods ended June 30, 2004 and 2003.
Any material change reports (excluding confidential reports), comparative
interim financial statements and information circulars (excluding those portions
that are not required pursuant to National Instrument 44-101 of the Canadian
Securities Administrators to be incorporated by reference herein) filed by the
Trust with the securities commissions or similar authorities in the provinces of
Canada subsequent to the date of this short form prospectus and prior to the
termination of this distribution shall be deemed to be incorporated by reference
in this short form prospectus.
ANY STATEMENT CONTAINED IN A DOCUMENT INCORPORATED OR DEEMED TO BE INCORPORATED
BY REFERENCE HEREIN SHALL BE DEEMED TO BE MODIFIED OR SUPERSEDED FOR THE
PURPOSES OF THIS SHORT FORM PROSPECTUS TO THE EXTENT THAT A STATEMENT CONTAINED
HEREIN OR IN ANY OTHER SUBSEQUENTLY FILED DOCUMENT WHICH ALSO IS, OR IS DEEMED
TO BE, INCORPORATED BY REFERENCE HEREIN MODIFIES OR SUPERSEDES SUCH STATEMENT.
THE MODIFYING OR SUPERSEDING STATEMENT NEED NOT STATE THAT IT HAS MODIFIED OR
SUPERSEDED A PRIOR STATEMENT OR INCLUDE ANY OTHER INFORMATION SET FORTH IN THE
DOCUMENT THAT IT MODIFIES OR SUPERSEDES. THE MAKING OF A MODIFYING OR
SUPERSEDING STATEMENT SHALL NOT BE DEEMED AN ADMISSION FOR ANY PURPOSES THAT THE
MODIFIED OR SUPERSEDED STATEMENT, WHEN MADE, CONSTITUTED A MISREPRESENTATION, AN
UNTRUE STATEMENT OF A MATERIAL FACT OR AN OMISSION TO STATE A MATERIAL FACT THAT
IS REQUIRED TO BE STATED OR THAT IS NECESSARY TO MAKE A STATEMENT NOT MISLEADING
IN LIGHT OF THE CIRCUMSTANCES IN WHICH IT WAS MADE. ANY STATEMENT SO MODIFIED OR
SUPERSEDED SHALL NOT BE DEEMED, EXCEPT AS SO MODIFIED OR SUPERSEDED, TO
CONSTITUTE A PART OF THIS SHORT FORM PROSPECTUS.
15
ADVANTAGE ENERGY INCOME FUND
ADVANTAGE ENERGY INCOME FUND, ADVANTAGE OIL & GAS LTD.
AND ADVANTAGE INVESTMENT MANAGEMENT LTD.
Advantage Energy Income Fund is an entity that provides monthly cash
distributions to its Unitholders. Advantage was created under the laws of the
Province of Alberta pursuant to the Trust Indenture. It is, for Canadian tax
purposes, an open-ended mutual fund trust and is categorized as a "natural
resource issuer" for the purposes of Canadian securities laws. The Trust is
administered by the Trustee. The beneficiaries of the Trust are the Unitholders.
AOG is an oil and natural gas exploitation and development company that is
wholly-owned by the Trust. It was originally incorporated in 1979 as Westrex
Energy Corp. ("WESTREX"). Through a plan of arrangement under the ABCA, Westrex
merged with Search Energy Inc. on December 31, 1996, and changed its name to
Search Energy Corp. ("SEARCH") on January 2, 1997.
Effective May 24, 2001, all of the issued and outstanding common shares of
Search were acquired by 925212 Alberta Ltd. ("ACQUISITIONCO"), a corporation
wholly-owned by the Trust. Search and AcquisitionCo were then amalgamated and
continued as "Search Energy Corp.". On July 26, 2001, Search acquired all of the
shares of Due West Resources Inc. ("DUE WEST"). Effective August 1, 2001, Search
and Due West were amalgamated and continued as "Search Energy Corp.". Effective
January 1, 2002, Search acquired a number of natural gas properties located
primarily in southern Alberta formerly administered by Gascan Resources Ltd. On
June 26, 2002, Search changed its name to Advantage Oil & Gas Ltd. On November
18, 2002, AOG acquired all of the issued and outstanding shares of Best Pacific
Resources Ltd. On December 2, 2003, AOG acquired MarkWest. MarkWest was
amalgamated with AOG on December 31, 2003.
In accordance with the Management Agreement, the Manager has agreed to act as
manager of the Trust and AOG. The Manager is a Canadian-owned energy advisory
management corporation, incorporated on March 19, 2001, pursuant to the
provisions of the ABCA.
The head office of the Trust and the Manager and the head office and the
registered office of AOG is located at Suite 3100, 150 - 6th Avenue S.W.,
Calgary, Alberta, T2P 3Y6. The registered office of the Manager is located at
Suite 3700, 400 - 3rd Avenue S.W., Calgary, Alberta, T2P 4H2.
DESCRIPTION OF BUSINESS
ADVANTAGE ENERGY INCOME FUND
The principal undertaking of the Trust is to indirectly acquire and hold,
through its wholly-owned subsidiary, AOG, interests in petroleum and natural gas
properties and assets related thereto. The Trust's primary assets are currently
the common shares of AOG, the Royalty, the Notes, the 10 3/8% Notes, the 9 3/8%
Notes and the 8.50% Notes.
In accordance with the terms of the Trust Indenture, the Trust will make cash
distributions to Unitholders of the interest income earned from the Notes, the
10 3/8% Notes, the 9 3/8% Notes, the 8.50% Notes, royalty income earned on the
Royalty, dividends (if any) received on, and amounts, if any, received on
redemption of, AOG's common shares, non-voting 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.
ADVANTAGE OIL & GAS LTD.
AOG is actively engaged in the business of oil and gas exploitation,
development, acquisition and production in the Provinces of Alberta, British
Columbia and Saskatchewan.
ADVANTAGE INVESTMENT MANAGEMENT LTD.
Pursuant to the Management Agreement, the Manager has agreed to act as manager
of the Trust and AOG. The board of directors of AOG has retained the Manager to
provide comprehensive management services and has
16
delegated certain authority to the Manager to assist in the administration and
regulation of the day-to-day operations of the Trust and AOG and assist in
executive decisions which conform to the general policies and general principles
previously established by the board of directors of AOG. The Manager is entitled
to designate two directors to serve on the board of directors of AOG. The
Manager also provides executive officers to AOG, subject to the approval of the
board of directors of AOG.
RECENT DEVELOPMENTS
PROPOSED ACQUISITION
OVERVIEW
On August 24, 2004, AOG entered into the Acquisition Agreement with Anadarko
providing for the acquisition of the Assets for a purchase price (the "PURCHASE
PRICE") of approximately $186,000,000 (subject to adjustment). AOG has paid an
$18,600,000 deposit (the "DEPOSIT") to Anadarko in connection with the proposed
acquisition. The Acquisition is expected to close on or before the later of
September 30, 2004 and two Business Days following receipt of approvals under
the COMPETITION ACT (Canada) or such other date as Anadarko and AOG may agree in
writing. The acquisition will have an effective date of July 1, 2004. AOG is
currently conducting a title and an environmental review in respect of the
Assets.
Concurrently with the announcement of the Acquisition, the Trust announced an
increase in the distributions payable on the Trust Units. See "Recent
Developments - Distribution Announcement".
ASSETS
The Assets consist of oil, natural gas and NGL assets located in central
Alberta, southern Alberta and southeast Saskatchewan with production weighted
approximately 49% light oil and NGLs, 40% natural gas and 11% heavy oil (23o
API), which are currently producing approximately 6,250 boe/d, before deduction
of royalties owed to others (comprised of approximately 15,500 mcf/d of natural
gas, 3,138 bbl/d of oil and 529 bbl/d of NGLs). Approximately 60% of the
production from the properties is currently operated by Anadarko with nine
properties representing approximately 87% of current production. The Manager
believes that the Assets offer numerous low risk infill and development drilling
locations and optimization opportunities to enhance production and Reserves.
Approximately 8.5% of the current production from the Assets is subject to
rights of first refusal. The Acquisition Agreement provides for an adjustment to
the Purchase Price to the extent that such rights of first refusal are exercised
prior to the closing of the Acquisition. Any excess funds resulting from the
exercise of rights of first refusal will be used to reduce bank indebtedness.
The Sproule Anadarko Report assigned approximately 13.9 million boe of Proved
and Probable Reserves to the Assets effective as at July 1, 2004.
Included in the Assets are approximately 149,000 gross (80,000 net) acres of
undeveloped land at an average 53% working interest as well as a licensed copy
of approximately 1,626 kilometres of 2D seismic data and 407 square kilometres
of 3D seismic data to assist the Trust in ongoing identification and evaluation
of upside potential associated with the Assets.
For more detail regarding the Assets, see "Information Concerning the Assets"
and "Effect of the Acquisition on the Trust" for additional information on the
Assets.
CLOSING CONDITIONS, DEPOSIT AND LIABILITY ARRANGEMENTS
Conditions to closing of the Acquisition under the Acquisition Agreement include
the following: the continued accuracy of representations and warranties; receipt
of customary approvals under the COMPETITION ACT (Canada); and no substantial
physical damage of the Assets having occurred prior to closing which would,
after deducting amounts Anadarko has agreed to pay and any insurance proceeds in
respect of such damages, adversely affect the value of the Assets by more than
$2,000,000. In accordance with the terms of the Acquisition Agreement, if the
Acquisition is
17
completed, the Deposit will be credited to the Purchase Price. If the
Acquisition does not occur due to a failure of AOG to satisfy specified
conditions to closing, Anadarko shall be entitled as its sole remedy to retain
the Deposit. If the closing does not occur due to a failure of Anadarko to
satisfy certain closing conditions, the Deposit will be returned to AOG.
In connection with the Acquisition, Anadarko has indemnified AOG in respect of
certain liabilities that are a direct result of the breach of the Acquisition
Agreement, including any breaches of the representations and warranties made by
Anadarko, subject to certain exceptions. The aggregate liability of Anadarko
under the Acquisition Agreement is limited to the Purchase Price and Anadarko
shall not be liable to AOG unless the aggregate amount of such liability exceeds
a deductible equal to 2% of the unadjusted Purchase Price, after which point,
AOG will be entitled to recover from Anadarko only with respect to the amount
which exceeds such deductible.
AOG has indemnified Anadarko for certain liabilities that are a direct result of
the breach of the Acquisition Agreement by AOG including, any breaches of the
representations and warranties of AOG, subject to certain exceptions. In
addition, AOG has indemnified Anadarko for all liabilities which relate to the
Assets which occur or accrue on or after July 1, 2004 and for all past, present
and future environmental liabilities, in each case, subject to certain limited
exceptions.
STATUS OF UNITHOLDER LIMITED LIABILITY LEGISLATION
In May 2004 the Alberta legislature passed Bill 34, which would enact a new
statute, to be called the INCOME TRUSTS LIABILITY ACT, to create a statutory
limitation on the liability of unitholders of Alberta income trusts such as the
Trust. The Bill received Royal Assent on May 19, 2004 and came into force July
1, 2004. The legislation provides that a unitholder will not be, as a
beneficiary, liable for any act, default, obligation or liability of the trustee
that arises after the legislation comes into force.
DISTRIBUTION ANNOUNCEMENT
On August 24, 2004 the Trust announced that, subject to the closing of the
Acquisition on or before September 30, 2004 its distribution to be paid on
November 15, 2004 for Unitholders of record on October 29, 2004 will be $0.25
per Trust Unit, being an increase of 8.7% from the previous distribution level
of $0.23 per Trust Unit.
OPERATIONAL UPDATE ON THE NEVIS PROPERTY
The Trust's Nevis property is situated 50 kilometers east of the City of Red
Deer Alberta. The majority of the production from this property has historically
consisted of natural gas from over 32 sections of land with varying working
interests. The Trust's primary development target from the area is light crude
oil presently being produced from the Wabamun formation. To develop the Wabamun
reservoir, the Trust is primarily utilizing horizontal drilling. The horizontal
drilling targets have been and will be guided by the use of existing 3D seismic
that covers the majority of the property. The Trust is also proposing that
portions of the property not currently covered with 3D seismic will be shot
during the third quarter, with a program covering in excess of 10 sections of
land.
During the first six months of 2004 the Trust drilled five horizontal oil wells,
one standing horizontal well, one vertical oil well, one vertical natural gas
well and one dry vertical well, all with a 100% working interest to the Trust.
During the third quarter to date, four horizontal oil wells and four vertical
oil wells have been drilled. These oil wells are expected to be on production by
the end of the third quarter. Two additional horizontal wells are currently
drilling, with an additional eight horizontal wells scheduled for the remainder
of the year. The Trust has acquired a 100% working interest in an additional 16
sections of land through a successful program of freehold leasing, crown land
acquisitions, acreage swaps and a farmin arrangement and has extended the oil
bearing area an additional three miles to the southeast and to the southwest
from the discovery oil wells. The drilling program in the third quarter has
satisfied the earning component of the farmin arrangement. Daily production from
the Nevis property is currently at 1,240 boe/d of which 360 boe/d was added from
three newly drilled horizontal oilwells brought into production during the
second quarter.
18
POTENTIAL TRANSACTIONS
The Trust continues to evaluate potential acquisitions of all types of petroleum
and natural gas and other energy-related assets as part of its ongoing
acquisition program. The Trust is normally in the process of evaluating several
potential acquisitions at any one time which individually or together could be
material. As of the date hereof, other than as otherwise disclosed herein, the
Trust has not reached agreement on the price or terms of any potential material
acquisitions. The Trust cannot predict whether any current or future
opportunities will result in one or more acquisitions for the Trust. In
addition, the Trust continues to review and evaluate opportunities to dispose of
or rationalize its non-core assets where favourable opportunities arise.
INFORMATION CONCERNING THE ASSETS
As the Trust does not currently own the Assets, the following information has
been summarized from information obtained from Anadarko and other third parties.
The Reserves data for the Assets set forth below is based upon an evaluation by
Sproule with an effective date of July 1, 2004 contained in the Sproule Anadarko
Report. The Reserves data summarizes the natural gas Reserves of the Assets and
the net present values of future net revenue for these Reserves using Constant
prices and costs and Forecast prices and costs. References to production herein
indicate the relevant party's working interest share prior to the deduction of
royalties owned by others. Except where otherwise indicated, the Reserves data
conforms to the requirements of National Instrument 51-101 - Standards of
Disclosure for Oil and Gas Activities ("NI 51-101").
All Reserves associated with the Assets are located in Canada and, specifically,
in the provinces of Alberta and Saskatchewan.
IT SHOULD NOT BE ASSUMED THAT THE ESTIMATES OF FUTURE NET REVENUES PRESENTED IN
THE TABLES BELOW REPRESENT THE FAIR MARKET VALUE OF THE RESERVES. THERE IS NO
ASSURANCE THAT THE CONSTANT OR FORECAST PRICES AND COSTS OR OTHER ASSUMPTIONS
WILL BE ATTAINED AND VARIANCES COULD BE MATERIAL.
RESERVES DATA (FORECAST PRICES AND COSTS)
The following tables provide Reserves data and future net revenues associated
with the Assets based on the Sproule Anadarko Report using Forecast prices and
costs.
SUMMARY OF OIL AND GAS RESERVES
AND NET PRESENT VALUES OF FUTURE NET REVENUE
AS OF JULY 1, 2004
FORECAST PRICES AND COSTS
RESERVES
-------------------------------------------------------------------------------------------------------
LIGHT AND NATURAL GAS
MEDIUM OIL HEAVY OIL NATURAL GAS LIQUIDS BOE
------------------ ----------------- ------------------- --------------- ------------------
GROSS NET GROSS NET GROSS NET GROSS NET GROSS NET
RESERVES CATEGORY (MBBL) (MBBL) (MBBL) (MBBL) (MMCF) (MMCF) (MBBL) (MBBL) (MBOE) (MBOE)
- ------------------------- -------- ------- ------- ------- -------- -------- ------ ------ ------- -------
Proved
Developed Producing 3,757.8 3,110.3 1,254.6 1,149.0 16,424.2 11,741.2 513.6 369.2 8,263.4 6,585.3
Developed Non-Producing 45.6 42.4 - - 1,262.0 1,005.3 30.7 23.5 286.6 233.4
Undeveloped 641.9 593.1 - - 145.3 132.6 7.6 7.5 673.7 622.8
-------- ------- ------- ------- -------- -------- ------ ------ ------- -------
Total Proved 4,445.3 3,745.8 1,254.6 1,149.0 17,831.6 12,879.0 552.0 400.2 9,223.8 7,441.5
Probable 2,725.8 2,366.6 261.4 237.8 8,517.2 6,082.4 251.6 176.0 4,658.3 3,794.1
-------- ------- ------- ------- -------- -------- ------ ------ ------- -------
Total Proved Plus Probable 7,171.1 6,112.4 1,515.9 1,386.7 26,348.8 18,961.5 803.6 576.2 13,882.1 11,235.6
======== ======= ======= ======= ======== ======== ====== ====== ======= =======
19
NET PRESENT VALUES OF FUTURE NET REVENUE(1)
-----------------------------------------------------------------------------------------------------
BEFORE INCOME TAXES DISCOUNTED AT (%/YEAR) AFTER INCOME TAXES DISCOUNTED AT (%/YEAR)
-------------------------------------------------- -------------------------------------------------
0 5 10 15 20 0 5 10 15 20
RESERVES CATEGORY (M$) (M$) (M$) (M$) (M$) (M$) (M$) (M$) (M$) (M$)
- -------------------------- -------- -------- -------- -------- -------- -------- -------- -------- -------- --------
Proved
Developed Producing 148,447 126,868 112,172 101,382 93,042 148,447 126,868 112,172 101,382 93,042
Developed Non-Producing 5,289 4,646 4,134 3,717 3,370 5,289 4,646 4,134 3,717 3,370
Undeveloped 9,506 7,912 6,644 5,610 4,751 9,506 7,912 6,644 5,610 4,751
-------- -------- -------- -------- -------- -------- -------- -------- -------- --------
Total Proved 163,242 139,299 122,740 110,446 100,867 163,242 139,299 122,740 110,446 100,867
Probable 83,422 59,541 45,762 36,922 30,808 83,422 59,541 45,762 36,922 30,808
-------- -------- -------- -------- -------- -------- -------- -------- -------- --------
Total Proved Plus Probable 246,665 198,840 168,502 147,367 131,676 246,665 198,840 168,502 147,367 131,676
======== ======== ======== ======== ======== ======== ======== ======== ======== ========
Note:
(1) The numbers shown are as represented in the Sproule Anadarko Report. Slight
differences may be due to rounding.
TOTAL FUTURE NET REVENUE
(UNDISCOUNTED)
AS OF JULY 1, 2004
FORECAST PRICES AND COSTS(1)
FUTURE NET FUTURE NET
WELL REVENUE REVENUE
OPERATING DEVELOPMENT ABANDONMENT BEFORE INCOME AFTER
RESERVES CATEGORY REVENUE ROYALTIES COSTS COSTS COSTS INCOME TAXES TAXES INCOME TAXES
- ----------------- ------- --------- --------- ---------- ----------- ------------ -------- ------------
(m$) (m$) (m$) (m$) (m$) (m$) (m$) (m$)
Proved Reserves 362,300 72,077 115,000 10,598 - 163,200 - 163,200
Proved Plus 545,900 104,800 176,300 14,999 - 246,700 - 246,700
Probable Reserves
Note:
(1) The numbers shown are as represented in the Sproule Anadarko Report. Slight
differences may be due to rounding.
FUTURE NET REVENUE
BY PRODUCTION GROUP
AS OF JULY 1, 2004
FORECAST PRICES AND COSTS
FUTURE NET REVENUE
BEFORE INCOME TAXES
(DISCOUNTED AT
10%/YEAR)
RESERVES CATEGORY PRODUCTION GROUP (M$)
- --------------------------- ----------------------------------------------------------------------------- -------------------
Proved Reserves Light and Medium Crude Oil (including solution gas and other by-products) 53,387
Heavy Oil (including solution gas and other by-products) 7,441
Natural Gas (including by-products but excluding solution gas from oil wells) 61,912
Proved Plus Probable Light and Medium Crude Oil (including solution gas and other by-products) 75,248
Reserves Heavy Oil (including solution gas and other by-products) 9,354
Natural Gas (including by-products but excluding solution gas from oil wells) 83,899
20
RESERVES DATA (CONSTANT PRICES AND COSTS)
The following tables provide Reserves data and future net revenue of the Assets
based on the Sproule Anadarko Report using Constant prices and costs.
SUMMARY OF OIL AND GAS RESERVES
AND NET PRESENT VALUES OF FUTURE NET REVENUE
AS OF JULY 1, 2004
CONSTANT PRICES AND COSTS
RESERVES
------------------------------------------------------------------------------------------------------
LIGHT AND NATURAL GAS
MEDIUM OIL HEAVY OIL NATURAL GAS LIQUIDS BOE
------------------ ----------------- ------------------- --------------- ------------------
GROSS NET GROSS NET GROSS NET GROSS NET GROSS NET
RESERVES CATEGORY (MBBL) (MBBL) (MBBL) (MBBL) (MMCF) (MMCF) (MBBL) (MBBL) (MBOE) (MBOE)
- ------------------------- -------- ------- ------- ------- -------- -------- ------ ------ ------- -------
Proved
Developed Producing 3,879.6 3,187.6 1,281.4 1,168.8 17,271.0 12,310.4 522.4 373.5 8,561.9 6,781.7
Developed Non-Producing 47.2 43.7 - - 1,308.6 1,047.6 31.3 24.0 296.6 242.3
Undeveloped 655.7 604.1 - - 159.6 145.9 7.7 7.6 690.1 636.0
-------- ------- ------- ------- -------- -------- ------ ------ ------- -------
Total Proved 4,582.5 3,835.4 1,281.4 1,168.8 18,739.1 13,503.9 561.5 405.1 9,548.6 7,660
Probable 2,939.3 2,526.2 285.2 258.1 9,107.0 6,483.9 258.4 179.3 5,000.7 4,044.3
-------- ------- ------- ------- -------- -------- ------ ------ ------- --------
Total Proved Plus Probable 7,521.8 6,361.6 1,566.6 1,426.9 27,846.1 19,987.8 819.9 584.5 14,549.3 11,704.3
======== ======= ======= ======= ======== ======== ====== ====== ======= ========
NET PRESENT VALUES OF FUTURE NET REVENUE(1)
-----------------------------------------------------------------------------------------------------
BEFORE INCOME TAXES DISCOUNTED AT (%/YEAR) AFTER INCOME TAXES DISCOUNTED AT (%/YEAR)
-------------------------------------------------- -------------------------------------------------
0 5 10 15 20 0 5 10 15 20
RESERVES CATEGORY (M$) (M$) (M$) (M$) (M$) (M$) (M$) (M$) (M$) (M$)
- -------------------------- -------- -------- -------- -------- -------- -------- -------- -------- -------- --------
Proved
Developed Producing 186,326 155,258 134,739 120,010 108,832 186,326 155,258 134,739 120,010 108,832
Developed Non-Producing 7,013 6,010 5,249 4,652 4,172 7,013 6,010 5,249 4,652 4,172
Undeveloped 12,904 10,723 9,043 7,699 6,598 12,904 10,723 9,043 7,699 6,598
-------- -------- -------- -------- -------- -------- -------- -------- -------- --------
Total Proved 206,243 171,809 148,739 132,002 119,203 206,243 171,809 148,739 132,002 119,203
Probable 110,566 77,535 58,641 46,649 38,450 110,566 77,535 58,641 46,649 38,450
-------- -------- -------- -------- -------- -------- -------- -------- -------- --------
Total Proved Plus Probable 316,810 249,344 207,380 178,651 157,653 316,810 249,344 207,380 178,651 157,653
======== ======== ======== ======== ======== ======== ======== ======== ======== ========
TOTAL FUTURE NET REVENUE
(UNDISCOUNTED)
AS OF JULY 1, 2004
CONSTANT PRICES AND COSTS
FUTURE NET FUTURE NET
WELL REVENUE REVENUE
OPERATING DEVELOPMENT ABANDONMENT BEFORE INCOME AFTER
RESERVES CATEGORY REVENUE ROYALTIES COSTS COSTS COSTS INCOME TAXES TAXES INCOME TAXES
- ----------------- ------- --------- --------- ---------- ----------- ------------ -------- ------------
(m$) (m$) (m$) (m$) (m$) (m$) (m$) (m$)
Proved Reserves 424,000 90,307 115,000 10,560 - 206,200 - 206,200
Proved Plus 650,300 135,300 179,000 14,946 - 316,800 - 316,800
Probable Reserves
21
FUTURE NET REVENUE
BY PRODUCTION GROUP
AS OF JULY 1, 2004
CONSTANT PRICES AND COSTS
FUTURE NET REVENUE
BEFORE INCOME TAXES
(DISCOUNTED AT
10%/YEAR)
RESERVES CATEGORY PRODUCTION GROUP (M$)
- --------------------------- -------------------------------------------------------------------------------- ------------------
Proved Reserves Light and Medium Crude Oil (including solution gas and other by-products 65,384
Heavy Oil (including solution gas and other by-products) 10,762
Natural Gas (including by-products but excluding solution gas from oil wells) 72,594
Proved Plus Probable Light and Medium Crude Oil (including solution gas and other by-products 94,467
Reserves Heavy Oil (including solution gas and other by-products) 13,373
Natural Gas (including by-products but excluding solution gas from oil wells) 99,539
from oil wells)
PRICING ASSUMPTIONS
The following tables set forth the benchmark reference prices and pricing
assumptions used in preparing the Reserves data for the Assets and, in the case
of Forecast prices and costs, the inflation rate assumptions.
SUMMARY OF PRICING ASSUMPTIONS
AS OF JULY 1, 2004
CONSTANT PRICES AND COSTS
OIL
--------------------------------------------------
EDMONTON HARDISTY CROMER
WTI PAR PRICE HEAVY MEDIUM NATURAL
CUSHING 40(DEGREE) 12(DEGREE) 29.3(DEGREE) AECO GAS EDMONTON EDMONTON EDMONTON EXCHANGE
OKLAHOMA API API API PRICE PROPANE BUTANE PENTANES RATE
- ---------- -------- ---------- ---------- ----------- ----------- --------- --------- -------- ----------
($US/bbl) ($Cdn/bbl) ($Cdn/bbl) ($Cdn/bbl) ($Cdn/mmbtu) ($Cdn/bbl) ($Cdn/bbl) ($Cdn/bbl) ($US/$Cdn)
2004 38.49 49.81 32.07 44.31 7.64 31.18 37.13 51.02 0.75
(6 mths)
22
SUMMARY OF PRICING AND INFLATION RATE ASSUMPTIONS
AS OF JULY 1, 2004
FORECAST PRICES AND COSTS
OIL
--------------------------------------------------
EDMONTON HARDISTY CROMER
PAR PRICE HEAVY MEDIUM NATURAL
WTI 40(DEGREE) 12(DEGREE) 29.3(DEGREE) AECO GAS EDMONTON INFLATION EXCHANGE
NYMEX API API API PRICE HENRY HUB BUTANE RATES RATE
- ---------- -------- ---------- ---------- ----------- ----------- --------- --------- ---------- ----------
($US/bbl) ($Cdn/bbl) ($Cdn/bbl) ($Cdn/bbl) ($Cdn/mmbtu) ($Cdn/bbl) ($Cdn/bbl) ($Cdn/bbl) ($US/$Cdn)
Forecast
2004
(6 mths) 37.17 49.76 39.28 47.29 6.93 6.52 39.53 1.5 0.750
2005 35.08 46.88 36.24 44.37 6.85 6.28 36.85 1.5 0.750
2006 33.42 44.59 33.79 42.04 6.27 5.78 34.71 1.5 0.750
2007 32.42 43.51 32.47 40.90 5.80 5.36 33.62 1.5 0.750
2008 31.83 42.68 31.48 40.04 5.50 5.13 32.79 1.5 0.750
2009 31.55 42.36 31.13 39.88 5.40 5.02 32.58 1.5 0.750
2010 31.57 42.05 30.74 39.56 5.27 4.95 32.26 1.5 0.750
2011 31.92 42.82 31.25 40.27 5.24 4.91 32.83 1.5 0.750
2012 33.75 45.35 33.60 42.75 5.21 4.89 35.01 1.5 0.750
2013 33.54 45.35 33.34 42.70 5.27 4.92 34.88 1.5 0.750
2014 34.69 46.60 34.51 43.93 5.31 4.99 35.97 1.5 0.750
2016+ +1.5%/yr +1.5%/yr +1.5%/yr +1.5%/yr +1.5%/yr +1.5%/yr +1.5%/yr 1.5 0.750
OIL AND GAS PROPERTIES
The following is a description of the principal oil and natural gas properties
to be acquired by AOG pursuant to the Acquisition Agreement. The Assets are
focused in central Alberta, southern Alberta and southeast Saskatchewan. The
term "net", when used to describe Anadarko's share of production, means the
aggregate of Anadarko's working interest share before deduction of royalties
owned by others.
CENTRAL ALBERTA
BRAZEAU RIVER
The Brazeau River property is located approximately 30 miles west of the town of
Drayton Valley, Alberta. The property produces sour light oil and natural gas
primarily from Devonian aged Nisku pinnacle reefs. The majority of the
production is from a non-operated 50% working interest in the Nisku C, D and E
pools and a 17% working interest in the Nisku A unit. Sweet natural gas is also
produced from eight natural gas wells out of reservoirs in either of the
Cretaceous aged Cardium, Viking or Lower Mannville Formations. Major facility
interests include a 25.7% working interest in the West Pembina Sour Gas Plant
and a 31.6% working interest in the Brazeau River Gas Plant. The net production
from the property at July 1, 2004 was 1,222 boe/d consisting of 5,693 mcf/d
natural gas, 63 bbl/d NGLs and 211 bbl/d of crude oil. The Sproule Anadarko
Report assigned Proved plus Probable Reserves of 1,884 mboe to the property as
at July 1, 2004.
OPEN LAKE
The Open Lake property is located approximately 20 miles north of the town of
Rocky Mountain House, Alberta. Anadarko operates and has a 100% working interest
in the Open Lake property. Oil and natural gas production from this property is
multi-zoned from various Cretaceous and Jurassic reservoirs including the Rock
Creek, Ellerslie, Ostracod, Viking, Second White Specks and Belly River
Formations. The net production from the property at July 1, 2004 was 716 boe/d
consisting of 2,297 mcf/d natural gas, 135 bbl/d NGLs and 199 bbl/d of crude
oil. The Sproule Anadarko Report assigned Proved plus Probable Reserves of 1,342
mboe to the property as at July 1, 2004.
23
CARSTAIRS
The Carstairs property is situated in the town of Carstairs, Alberta. The
property produces from carbonates in the Mississippian aged Elkton Formation.
The property is operated by Anadarko with a 70.8% (oil) and 62.7% (gas) working
interest in the East Crossfield Elkton G Pool Unit #1. A 65.9% working interest
is held in the oil processing facility. The net production from the property at
July 1, 2004 was approximately 579 boe/d consisting of 2,553 mcf/d natural gas,
91 bbl/d NGLs and 63 bbl/d oil. The Sproule Anadarko Report assigned total
Proved plus Probable Reserves of 970 mboe to the property as at July 1, 2004.
GULL LAKE
The Gull Lake property consists of production from a number of sections north of
the City of Red Deer, Alberta. The net production was 24 boe/d as of July 1,
2004 from properties with reserves assigned. The Sproule Anadarko Report
assigned total Proved plus Probable reserves of 38 mboe. One newly drilled well
at a 50% non-operated working interest began producing late in May 2004. It is
currently producing 1.3 mmcf/d of natural gas net to Anadarko. No reserve
assignments have been made to this well due to the early stage of production.
FIR
The Fir property is located approximately 40 miles northwest of the town of
Edson, Alberta. This property is comprised of two wells with an average working
interest of 71% producing co-mingled natural gas from Triassic aged Montney
Formations. The property is operated by Anadarko with a 43.6% working interest
in the compressor facility. The net natural gas production from the property at
July 1, 2004 was 2,072 mcf/d. The Anadarko Sproule Report assigned total Proved
plus Probable Reserves of 684 mboe to the property as at July 1, 2004.
WINDFALL
Windfall is an area consisting of certain blocks of land east of the Fir
property, located approximately 35 miles north of the town of Edson, Alberta.
Light oil and natural gas is produced from a wide range of geological intervals
with interests ranging from overriding royalties to 100% working interest. The
majority of the production is operated and originates from the Cretaceous aged
Gething Formation. Anadarko has a 100% working interest in two gas compressor
facilities and a 50% working interest in a 2 phase separator. The net production
from the property at July 1, 2004 was 163 boe/d consisting of 814 mcf/d natural
gas, 22 bbl/d of NGLs and 6 bbl/d crude oil. The Sproule Anadarko Report
assigned total Proved plus Probable Reserves of 437 mboe to the property as at
July 1, 2004.
SOUTHERN ALBERTA
RETLAW
The Retlaw property is located approximately 30 miles north of the City of
Lethbridge. It is a medium gravity crude oil property which is operated at an
average 40% working interest. Production occurs from Cretaceous aged Glauconite
channels defined with 3D seismic. There is a 50% working interest in the oil
battery which includes water injection facilities. The net production as of July
1, 2004 is 367 boe/d consisting of 514 mcf/d of natural gas and 282 bbls/d of
crude oil. The Sproule Anadarko Report assigned total Proved plus Probable
Reserves of 506 mboe to the property as at July 1, 2004.
LOST LAKE
The Lost Lake property is located approximately 45 miles north of the City of
Lethbridge. It is a heavy gravity crude oil property which as of July 1, 2004
had net production of 358 boe/d consisting of 117 mcf/d natural gas and 338
bbls/d crude oil. Oil production occurs primarily from the Cretaceous aged
Glauconite channels. The working interest in the property is 76% and 87.5% in
the oil battery and water injection facility. The Sproule Anadarko Report
assigned Proved plus Probable Reserves of 601 mboe to the property as at July 1,
2004.
24
LITTLE BOW
The Little Bow property is located west of the Lost Lake property, north of the
City of Lethbridge. The property produces heavy gravity crude oil which as of
July 1, 2004 had net production of 265 boe/d consisting of 185 mcf/d of natural
gas and 234 bbls/d of crude oil. It produces from Cretaceous aged Glauconite
channels. The working interest is operated by Anadarko at 63%. Anadarko's
interest in the oil treating and water injection facilities is 68.1%. The
Sproule Anadarko Report assigned total Proved plus Probable Reserves of 1,226
mboe to the property as at July 1, 2004.
SOUTHEASTERN SASKATCHEWAN
MIDALE
The Midale property is located north of the town of Midale, Saskatchewan. This
property produces primarily from the Ordovician aged Red River Formation. Light
oil production occurs from more than a dozen pools within reservoirs which occur
as carbonate buildups in this formation. Anadarko operates the property and has
an average working interest of 76% in the area. A 100% working interest is held
in the oil battery. The net production from the property at July 1, 2004 was 602
bbl/d of crude oil. The Sproule Anadarko Report assigned total Proved plus
Probable Reserves of 1,145 mboe to the property as at July 1, 2004.
STEELMAN
The Steelman property is located south of the town of Browning, Saskatchewan and
has an average working interest of 85% consisting of light oil production.
Production is taken from Ordovician aged Red River Formation, Devonian aged
Winnipegosis Formation and Mississippian aged Frobisher Formation. Anadarko has
a 100% working interest in the oil battery. The net production at July 1, 2004
was 492 bbls/d of crude oil from the property. The Sproule Anadarko Report
assigned total Proved plus Probable Reserves of 1,382 mboe to the property as at
July 1, 2004.
WEYBURN
The Weyburn property is located southeast of the town of Weyburn, Saskatchewan.
This property consists of an extensive land base, including operated interests
adjacent to the CO2 miscible flood as well as operated interests with active
area partners. Net production consisting of 236 bbls/d of light crude oil
originates primarily from the Mississippian aged Frobisher Formation. Anadarko
has a 100% working interest in the sour battery. The Sproule Anadarko Report
assigned total Proved plus Probable Reserves of 528 mboe to the property as at
July 1, 2004.
FROUDE
The Froude property is located approximately two miles west of Froude,
Saskatchewan. The operated production at an average working interest of 93%
occurs from the Ordovician Red River, Devonian Winnipegosis and Mississippian
Frobisher formations. Net production as of July 1, 2004 was 203 bbls/d of light
crude oil. Facilities are 100% owned. The Sproule Anadarko Report assigned total
Proved plus Probable Reserves of 669 mboe to the property as at July 1, 2004.
UNDEVELOPED RESERVES
The Proved Undeveloped Reserves by product type, attributed to the Assets are
641.9 mbbl of light/medium crude oil, 145.3 mmcf of natural gas and 7.6 mbbl of
NGL and the Probable Undeveloped Reserves by product type attributed to the
Assets are 759.1 mmbl of light/medium crude oil and 126.6 mmcf of natural gas,
in each case as estimated in the Sproule Anadarko Report, based on company
interest Reserves and based on Forecast prices and costs.
AOG plans to continue pursuing development opportunities on the Assets such as
drilling, completions, and facilities upgrades in order to move Proved
Undeveloped and Probable Reserves into Proved Developed Producing Reserves. In
instances where land rights are expected to expire within one year, AOG may
engage in farmout
25
arrangements, which would likely eliminate the potential expiry and possibly
result in some Proved Undeveloped and Probable Reserves becoming Proved
Developed Producing Reserves.
SIGNIFICANT FACTORS AND UNCERTAINTIES
The process of evaluating Reserves is inherently complex. It requires
significant judgements and decisions based on available geological, geophysical,
engineering and economic data. These estimates may change substantially as
additional data from ongoing development activities and production performance
becomes available and as economic conditions impacting oil and gas prices and
costs change. The Reserve estimates contained herein are based on current
production forecasts, prices and economic conditions. AOG's Reserves and the
Reserves set forth in the Sproule Anadarko Report have been evaluated by
Sproule, an independent engineering firm. These factors and assumptions include
among others: (i) historical production in the area compared with production
rates from analogous producing areas; (ii) initial production rates; (iii)
production decline rates; (iv) ultimate recovery of Reserves; (v) success of
future development activities; (vi) marketability of production; (vii) effects
of government regulations; and (viii) other government levies imposed over the
life of the Reserves.
AS CIRCUMSTANCES CHANGE AND ADDITIONAL DATA BECOMES AVAILABLE, RESERVE ESTIMATES
ALSO CHANGE. ESTIMATES ARE REVIEWED AND REVISED, EITHER UPWARD OR DOWNWARD, AS
WARRANTED BY THE NEW INFORMATION. REVISIONS ARE OFTEN REQUIRED DUE TO CHANGES IN
WELL PERFORMANCE, PRICES, ECONOMIC CONDITIONS AND GOVERNMENTAL RESTRICTIONS.
REVISIONS TO RESERVE ESTIMATES CAN ARISE FROM CHANGES IN YEAR-END PRICES,
RESERVOIR PERFORMANCE AND GEOLOGIC CONDITIONS OR PRODUCTION. THESE REVISIONS CAN
BE EITHER POSITIVE OR NEGATIVE.
FUTURE DEVELOPMENT COSTS
The following table sets forth development costs deducted in the estimation of
the future net revenue attributable to the Assets in the Sproule Anadarko Report
in the Reserve categories noted below.
FORECAST PRICES AND COSTS (M$) CONSTANT PRICES AND COSTS (M$)
------------------------------------------------------- -----------------------------
Year PROVED RESERVES PROVED PLUS PROBABLE RESERVES PROVED RESERVES
--------------------- ----------------------------- -----------------------------
0% 10% 0% 10% 0% 10%
------- ------- ------- ------- -------- -------
2004 10,340 10,098 13,662 13,398 10,340 10,098
2005 147 134 1,227 1,118 145 132
2006 - - - - - -
2007 - - - - - -
2008 - - - - - -
Thereafter 111 20 111 20 75 14
------- ------- ------- ------- -------- -------
Total 10,598 10,252 14,999 14,536 10,560 10,244
The future development costs are capital expenditures required in the future for
the Assets to convert Proved Undeveloped Reserves and Probable Reserves into
Proved Developed Producing Reserves. AOG anticipates using a combination of
internally generated cash flow, debt and equity financing to fund these future
development costs. Based on the commodity price and cost assumptions adopted for
both the Constant prices and costs case and the Forecast prices and costs case,
all the expenditures included in the future development costs are economic as
they enhance the net present values of the Proved Developed Reserves.
26
OIL AND GAS WELLS
The following table sets forth the number and status of wells in which AOG will
acquire a working interest pursuant to the Acquisition.
OIL WELLS NATURAL GAS WELLS
----------------------------------------- -------------------------------------------
PRODUCING NON-PRODUCING(1) PRODUCING NON-PRODUCING(1)
------------------- ----------------- ------------------ ------------------
GROSS (2) NET GROSS NET GROSS (2) NET GROSS NET
--------- ------ ----- ------ --------- ------ ----- -----
Alberta 155 88.2 6 4.7 88 21.2 5 4.3
Saskatchewan 97 78.4 16 14.5 - - - -
--------- ------ ----- ------ --------- ------ ----- -----
Total 252 166.6 22 19.2 88 21.2 5 4.3
========= ====== ===== ====== ========= ====== ===== =====
Notes:
(1) Non-Producing wells means wells which have encountered and are capable of
producing crude oil or natural gas but which are not producing due to lack
of available transportation facilities, available markets or other reasons.
(2) Gross wells include unit wells.
PROPERTIES WITH NO ATTRIBUTED RESERVES
The following table sets out for the Assets the total land holdings of Proved
and unproved properties to be acquired by AOG. Approximately 30,355 gross
(18,213 net) acres will expire by August 2005.
UNPROVED
DEVELOPED (ACRES) PROPERTIES (ACRES) TOTAL (ACRES)
----------------- -------------------- --------------------
GROSS NET GROSS NET GROSS NET
------ ----- -------- ------- ------- ------
Alberta 12,524 9,138 85,682 34,667 98,206 43,805
Saskatchewan 1,081 832 63,667 44,168 64,448 45,000
------ ----- -------- ------- ------- ------
Total 13,605 9,970 149,349 78,835 162,654 88,805
====== ===== ======== ======= ======= ======
COSTS INCURRED
A total of $6.5 million and $1.2 million, respectively, in costs were incurred
in respect of the Assets for the year ended December 31, 2003 and the six months
ended June 30, 2004, as follows:
SIX MONTHS ENDED YEAR ENDED
JUNE 30, 2004 DECEMBER 31, 2003
---------------- -----------------
(unaudited) (unaudited)
Property Acquisitions - -
Development Expenditures 1,157,713 6,544,593
Exploration Expenditures - -
TOTAL 1,157,713 6,544,593
EXPLORATION AND DEVELOPMENT ACTIVITIES
The following table sets forth the Gross and Net exploratory and development
wells drilled on the Assets during the periods indicated.
SIX MONTHS ENDED JUNE 30, 2004 YEAR ENDED DECEMBER 31, 2003
------------------------------ ----------------------------
GROSS NET GROSS NET
-------------- ------------ ----------- -----------
Light and Medium Oil 1 0.4 11 6.0
Natural Gas 1 0.5 - -
-------------- ------------ ----------- -----------
Total 2 0.9 11 6.0
============== ============ =========== ===========
27
PRODUCTION ESTIMATES
The following table sets out the volume of production estimated for the period
from July 1, 2004 to December 31, 2004 for the Assets, which is reflected in the
estimate of future net revenue disclosed in the tables contained under
"Information Concerning the Assets - Reserves Data".
LIGHT AND
MEDIUM OIL HEAVY OIL NATURAL GAS NATURAL GAS LIQUIDS BOE
---------- --------- ----------- ------------------- -------
(bbls/d) (bbls/d) (mcf/d) (bbls/d) (boe/d)
2004 (6 months) 3,008 652 14,012 459 6,454
PRODUCTION HISTORY
The following tables summarize certain information in respect of production,
product prices received, royalties paid, operating expenses and resulting
netback in respect of the Assets for the periods indicated. Current production
from the Assets is approximately 6,250 boe/d consisting of 15.5 mmcf/d of
natural gas, 3,138 bbls/d of crude oil and 529 bbls/d of NGLs.
QUARTER ENDED
-------------------------------------------------------------------------
2004 2003
-------------------- -----------------------------------------------
JUNE 30 MAR. 31 DEC. 31 SEPT. 30 JUNE 30 MAR. 31
------- ------- ------- -------- ------- -------
Average Daily Production
Light and Medium Crude Oil 3,054 3,396 3,540 3,796 3,958 4,097
(bbls/d)
Gas (mcf/d) 14,619 15,149 15,921 17,024 17,653 17,854
NGL (bbls/d) 485 551 774 806 881 515
Combined (boe/d) 5,975 6,472 6,968 7,440 7,782 7,588
Average Price Received
Light and Medium Crude Oil 44.17 40.14 34.94 36.86 35.40 40.65
($/bbls)
Gas ($/mcf) 7.16 6.90 5.72 6.18 7.02 8.10
NGL ($/bbls) 38.93 36.69 24.16 24.45 21.30 39.28
Combined ($/boe) 43.26 40.33 33.50 35.61 36.35 43.67
Royalties
Light and Medium Crude Oil 20.5% 23.0% 23.6% 23.6% 21.8% 22.7%
($bbls/d)
Gas (mcf/d) 24.1% 26.2% 27.2% 25.7% 24.8% 28.4%
NGL (bbls/d) 19.8% 25.7% 25.1% 25.5% 24.4% 27.3%
Combined (boe/d) 21.9% 24.5% 25.1% 24.5% 23.3% 25.5%
Operating expenses
Combined ($/boe) 11.44 9.04 10.55 9.87 8.59 8.47
Netback Received
Combined ($/boe) 22.34 21.42 14.54 17.00 19.30 24.09
The following table indicates the average daily production from the important
fields associated with the Assets for the year ended December 31, 2003:
CRUDE OIL NATURAL GAS NGL TOTAL
--------- ----------- -------- ---------
(bbls/d) (mcf/d) (bbls/d) (boe/d)
CENTRAL ALBERTA
Brazeau River 233 6,773 161 1,523
Open Lake 212 2,919 179 878
Carstairs 67 2,012 153 555
Fir 1 1,757 49 343
Windfall 6 1,344 16 246
Gull Lake 1 103 4 22
Other 133 990 191 489
--------- ----------- -------- ---------
TOTAL CENTRAL ALBERTA 653 15,898 753 4,056
28
CRUDE OIL NATURAL GAS NGL TOTAL
--------- ----------- -------- ---------
(bbls/d) (mcf/d) (bbls/d) (boe/d)
SOUTHERN ALBERTA
Retlaw 352 392 13 430
Lost Lake 405 210 1 441
Little Bow 4-25 195 111 0 214
Little Bow 16-20 67 370 1 130
Other 207 - 207
TOTAL SOUTHERN ALBERTA 1,226 1,083 15 1,422
SOUTHEAST SASKATCHEWAN
Midale 678 57 - 688
Weyburn 248 - - 248
Froude 218 - - 218
Steelman 605 66 - 616
Other 218 3 - 219
TOTAL SOUTHEAST SASKATCHEWAN 1,967 126 - 1,988
TOTAL 3,846 17,107 768 7,465
Note:
(1) Production numbers reflect total production averaged over the course of
the year.
EFFECT OF THE ACQUISITION ON THE TRUST
The following table sets out certain operational information for the Trust and
the Assets and certain pro forma combined operational information after giving
effect to the Acquisition.
SELECTED PRO FORMA COMBINED OPERATIONAL INFORMATION
TRUST ASSETS PRO FORMA COMBINED
----------- --------- ------------------
AVERAGE DAILY PRODUCTION (before royalties, for the six
months ended June 30, 2004)
Crude oil and NGL (bbls/d) 2,974 3,743 6,717
Natural Gas (mcf/d) 74,466 14,884 89,350
Oil equivalent (boe/d) 15,385 6,223 21,608
AVERAGE DAILY PRODUCTION (1)
(before royalties, for the year ended December 31, 2003)
Crude oil and NGL (bbls/d) 2,756 4,614 7,370
Natural gas (mcf/d) 57,631 17,107 74,738
Oil equivalent (boe/d) 12,361 7,465 19,826
PROVED RESERVES (2)
(before royalties, as at December 31, 2003, except the
Assets which are as at July 1, 2004)
Crude oil and NGL (mbbls) 8,261 6,252 14,513
Natural gas (bcf) 184.4 17.8 202.2
Oil equivalent (mboe) 38,998 9,224 48,222
29
TRUST ASSETS PRO FORMA COMBINED
----------- --------- ------------------
PROVED PLUS PROBABLE RESERVES (2)
(before royalties, as at December 31, 2003, except the
Assets which are as at July 1, 2004)
Crude oil and NGL (mbbls) 13,697 9,491 23,188
Natural gas (bcf) 237.4 26.3 263.7
Oil equivalent (mboe) 53,271 13,882 67,153
Notes:
(1) Average daily production for the Trust for the year ended December 31, 2003
includes production from the properties acquired pursuant to the
acquisition of MarkWest from the date of closing of such acquisition.
(2) Reserve information for the Assets is as at July 1, 2004, using Sproule's
July 1, 2004 price forecast and the Trust's Reserve information is as at
December 31, 2003, using Sproule's December 31, 2003 price forecast.
SELECTED PRO FORMA CONSOLIDATED FINANCIAL INFORMATION
Certain selected pro forma consolidated financial information is set forth in
the following tables. SUCH INFORMATION SHOULD BE READ IN CONJUNCTION WITH THE
UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS OF THE TRUST AFTER GIVING
EFFECT TO THE ACQUISITION AS AT AND FOR THE SIX MONTHS ENDED JUNE 30, 2004 AND
THE YEAR ENDED DECEMBER 31, 2003 INCLUDED IN THIS SHORT FORM PROSPECTUS.
The pro forma adjustments are based upon the assumptions described in the notes
to the unaudited pro forma consolidated financial statements. The pro forma
consolidated financial statements are presented for illustrative purposes only
and are not necessarily indicative of the operating or financial results that
would have occurred had the Acquisition actually occurred at the times
contemplated by the notes to the unaudited pro forma consolidated financial
statements or of the results expected in future periods.
The information presented below and in the unaudited pro forma consolidated
financial statements of the Trust assumes completion of the Acquisition and the
issuance of 3,500,000 Subscription Receipts, $75,000,000 aggregate principal
amount of 7.50% Debentures and $50,000,000 aggregate principal amount of 7.75%
Debentures pursuant to the offering.
AS AT AND FOR THE SIX MONTHS ENDED JUNE 30, 2004
---------------------------------------------------------
PRO FORMA
TRUST (4) ASSETS(6) CONSOLIDATED (7)
----------- ----------- ---------------
(stated in thousands of dollars, except unit amounts)
Revenue - net (1) 86,887 37,643 124,530
Net income 18,734 4,639 23,373
Funds from operations (2) 64,353 24,056 88,409
Total assets 595,862 183,198 779,060
Long term debt and working capital (3) 186,380 (5,910) 180,470
Equity 288,675 182,510 471,185
Units outstanding (thousands as at June 30, 2004) 39,952 3,500 43,452
30
FOR THE YEAR ENDED DECEMBER 31, 2003
----------------------------------------------------------------------
PRO FORMA
ADJUSTMENTS PRO FORMA
TRUST (4) BEFORE ASSETS(5) ASSETS(6) CONSOLIDATED(7)
------------ ---------------- --------- ---------------
(restated)(8) (stated in thousands of dollars)
Revenue - net (1) 137,584 33,172 80,058 250,814
Net income 44,024 10,061 13,475 67,560
Funds from operations(2) 99,440 21,909 53,800 175,149
Notes:
(1) Revenue - net consists of gross revenue net of applicable royalties.
(2) Funds from operations is before changes in non-cash working capital. As
such, it is not a measure recognized by Canadian generally accepted
accounting principles ("GAAP") and does not have a standardized meaning
prescribed by GAAP. Therefore, funds from operations of the Trust may not
be comparable to similar measures presented by other issuers, and investors
are cautioned that it should not be construed as an alternative to net
income, cash flow from operating activities or other measures of financial
performance calculated in accordance with GAAP.
(3) Long term debt and working capital includes bank indebtedness, all current
liabilities (net of current assets) and hedging.
(4) The Trust's financial information for the year ended December 31, 2003 was
obtained from the Trust's audited consolidated financial statements for the
year ended December 31, 2003 and as at and for the six months ended June
30, 2004 was obtained from the Trust's unaudited consolidated financial
statements as at and for the six months ended June 30, 2004.
(5) See Note 2 to the unaudited pro forma consolidated financial statement of
operations for the year ended December 31, 2003 set forth herein.
(6) The Anadarko properties financial information for the year ended December
31, 2003 was obtained from the audited schedules of revenues and expenses
for the Assets for the year ended December 31, 2003 set forth herein and
for the six months ended June 30, 2004 was obtained from the unaudited
schedules of revenues and expenses for the Assets for the six months ended
June 30, 2004 set forth herein, and reflects the pro forma adjustments as
noted in the Pro Forma Consolidated Financial Statements set forth herein.
(7) See the notes to the unaudited pro forma consolidated financial statements
set forth herein for assumptions and adjustments. The unaudited pro forma
consolidated financial statements may not be indicative of results that
actually would have occurred if the events reflected herein had been in
effect on the dates indicated or of the results expected in future periods.
(8) Advantage's consolidated financial statements for the year ended December
31, 2003 have been restated to reflect a change in accounting policy with
respect to asset retirement obligations. The change in policy is more fully
described in Advantage's unaudited interim consolidated financial
statements as at and for the three and six months ended June 30, 2004.
DESCRIPTION OF TRUST UNITS
TRUST UNITS
An unlimited number of Trust Units may be created and issued pursuant to the
Trust Indenture. As at July 30, 2004, 40,080,956 Trust Units were issued and
outstanding. Each Trust Unit represents an equal fractional undivided beneficial
interest in any distributions from, and in any net assets of, the Trust in the
event of termination or winding up of the Trust. The beneficial interests in the
Trust are divided into interests in two classes as follows: (i) described and
designated as "Trust Units", which are entitled to the rights, subject to
limitations, restrictions and conditions set out in the Trust Indenture; and
(ii) described and designated as "Special Voting Units", which shall be issued
to a trustee and shall be entitled to such number of votes at meetings of Trust
Unitholders as is equal to the number of Trust Units reserved for issuance that
such Special Voting Units represent, such number of votes and any other rights
or limitations to be prescribed by the board of directors of AOG. The Special
Voting Units give AOG the flexibility to acquire the securities of another
issuer in consideration for securities which are ultimately exchangeable for
Trust Units. There are currently no Special Voting Units outstanding. All Trust
Units are of the same class with equal rights and privileges. Each Trust Unit is
transferable, entitles the holder thereof to participate equally in
distributions, including the distributions of net income and net realized
capital gains of the Trust, and distributions on liquidation, is fully paid and
non-assessable and entitles the holder thereof to one vote at all meetings of
Trust Unitholders for each Trust Unit held.
31
Corporate law does not govern the Trust and the rights of Unitholders. 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.
CASH DISTRIBUTIONS
The board of directors of AOG intends for the Trust to make monthly cash
distributions. Cash distributions will be made monthly to the Unitholders of
record on the last day of each month (unless such day is not a Business Day, in
which case the date of record shall be the next following Business Day; provided
that December 31 shall always be a date of record) and shall be payable on the
15th day of each month or, if such day is not a Business Day, the next following
Business Day or such other date as determined from time to time by the Trustee.
For additional information respecting the Trust Units, including information
respecting Unitholders' limited liability, cash distributions, the redemption
right attached to the Trust Units, meetings of Unitholders, and amendments to
the Trust Indenture, see "Additional Information Respecting Advantage Energy
Income Fund" at pages 29 through 35, inclusive, of the Trust's AIF.
EARNINGS COVERAGE
The earnings coverage ratios set forth below have been prepared in accordance
with Canadian disclosure requirements. These ratios have been prepared using
financial information prepared in accordance with Canadian generally accepted
accounting principles. The ratios and notes have been prepared for each of the
twelve month periods ended December 31, 2003 and June 30, 2004, after giving
effect to the offering of Subscription Receipts and Debentures. The ratios for
the twelve month period ended June 30, 2004 are based on unaudited financial
information. Additional information is provided in the notes to the following
table.
TWELVE MONTHS ENDED TWELVE MONTHS ENDED
DECEMBER 31, 2003 JUNE 30, 2004
------------------- -------------------
Earnings coverage(1)(2)(3)(4)(5) 5.0 3.4
Notes:
(1) Earnings coverage is equal to net income before interest expense on all
long term debt, including the Debentures, the 8.25% Debentures, the 9.00%
Debentures and the 10.00% Debentures, and before income taxes, all divided
by interest expense on all long term debt, excluding the Debentures, the
8.25% Debentures, the 9.00% Debentures and the 10.00% Debentures. Under
Canadian generally accepted accounting principles the 10.00% Debentures,
the 9.00% Debentures and the 8.25% Debentures are, and the Debentures will
be, included in Unitholders' equity and the associated interest payments
will be charged to equity.
(2) The Trust's interest requirements amount to $6.4 million for the 12 month
period ended December 31, 2003 and $5.7 million for the 12 month period
ended June 30, 2004. The Trust's earnings before interest and income tax
for the 12 month period ended December 31, 2003 and the 12 month period
ended June 30, 2004 was $32.2 million and $19.4 million, respectively. The
earnings in the coverage ratios are not assumed to change as a result of
net proceeds from the offering.
(3) If the interest from the Debentures, the 8.25% Debentures, the 9.00%
Debentures and the 10.00% Debentures were included in interest expense, the
earnings coverage ratios would be 1.5 and less than 1 (with a coverage
deficiency of $1.6 million) for the 12 month periods ended December 31,
2003 and June 30, 2004, respectively. The Trust's interest requirements
after giving effect to the issue of the Debentures amounted to $21.7
million for the 12 months ended December 31, 2003 and $21.0 million for the
12 months ended June 30, 2004. The Trust's earnings before interest and
income tax for the 12 months ended December 31, 2003 was $32.2 million and
for the 12 months ended June 30, 2004 was $19.4 million, which is 1.5 times
and less than one times Advantage's interest requirements for the
respective periods.
(4) After giving effect to the Acquisition and if the interest from the
Debentures, the 8.25% Debentures, the 9.00% Debentures and the 10.00%
Debentures were included in interest expense, the PRO FORMA earnings
coverage ratio would be 2.4 times for the twelve month period ended
December 31, 2003.
(5) Financial information for the year ended December 31, 2003 is based on
amounts as revised to reflect changes in the accounting for asset
retirement obligations.
32
CONSOLIDATED CAPITALIZATION OF THE TRUST
The following table sets forth the consolidated capitalization of the Trust as
at December 31, 2003 and as at June 30, 2004, both before and after giving
effect to the offering and the Acquisition:
AS AT JUNE 30, 2004 BEFORE
GIVING EFFECT TO THE AS AT JUNE 30, 2004 AFTER
OFFERING AND THE GIVING EFFECT TO THE OFFERING
AS AT ACQUISITION(4) AND THE ACQUISITION(1)(2)
DESIGNATION (AUTHORIZED) DECEMBER 31, 2003 (UNAUDITED) (UNAUDITED)
-------------------------------------------------------------------------------------------------------------------------
($ thousands except unit amounts)
Bank Debt $102,968 $161,707 $156,397(6)
($220 million)(1)
Unitholders' Equity
Trust Units(3)(5) $302,496 $339,279 $401,789
(unlimited) (36,717,206 Trust Units) (39,952,085 Trust Units) (43,452,085 Trust Units)
10.00% Debentures $10,214 $6,756 $6,756
($55,000)
9.00% Debentures $30,000 $27,055 $27,055
($30,000)
8.25% Debentures $59,770 $32,585 $32,585
($60,000)
7.50% Debentures Nil Nil $75,000
($75,000)
7.75% Debentures Nil Nil $50,000
($50,000)
Special Voting Units Nil Nil Nil
(unlimited)
Notes:
(1) Advantage has credit facilities (the "CREDIT FACILITIES") which provide for
a $210 million extendible revolving loan facility and a $10 million
operating loan facility. The loan's interest rate is based on either prime
or bankers acceptance rates at the Trust's option subject to certain basis
point or stamping fee adjustments ranging from 0% to 2.0% depending on the
Trust's debt to cash flow ratio. The Credit Facilities are secured by a
$250 million floating charge demand debenture, a general security agreement
and a subordination agreement from the Trust covering all assets and cash
flows. The Credit Facilities are subject to review on an annual basis, with
the next review anticipated to take place in May 2005. Various borrowing
options are available under the Credit Facilities, including prime
rate-based advances and bankers' acceptances loans. The Credit Facilities
constitute a revolving facility for a 364 day term which is extendible
annually for a further 364 day revolving period, subject to a one year term
maturity as to lenders not agreeing to such annual extension. The Credit
Facilities contain standard commercial covenants for facilities of this
nature, and distributions by AOG to the Trust (and effectively by the Trust
to Unitholders) are subordinated to the repayment of any amounts owing
under the Credit Facilities. Distributions to Unitholders are not permitted
if the Trust is in default of such Credit Facilities or if the amount of
the Trust's outstanding indebtedness under such facilities exceeds the then
existing current borrowing base. The current borrowing base under the
Credit Facilities is $220 million. Interest payments under the Debentures
are also subordinated to indebtedness under the Credit Facilities and
payments under the Debentures are similarly restricted.
(2) Based on the issuance of 3,500,000 Subscription Receipts (and the issue of
3,500,000 Units pursuant thereto), $75,000,000 aggregate principal amount
of 7.50% Debentures and $50,000,000 aggregate principal amount of 7.75%
Debentures for aggregate gross proceeds of $190,800,000 less the
Underwriters' fee of $8,290,000 and expenses of the issue estimated to be
$600,000, the net proceeds from this issue are estimated to be
$181,910,000, and which will be applied to satisfy a portion of the
purchase price of the Acquisition.
(3) In addition, as at June 30, 2004, 295,000 incentive rights are outstanding
under the Trust's trust unit incentive rights plan.
(4) As at June 30, 2004, Unitholders' equity of the Trust incorporated
Unitholders' capital of $339,279,000, contributed surplus of $1,036,000,
accumulated cash distributions up to June 30, 2004 of $206,080,000 and
accumulated income of $80,044,000.
33
(5) The amount recorded for the Trust Units at December 31, 2003 includes
$19,592,000 for the accrual of the non-cash performance incentive amounts
which were subsequently settled through the issuance of 1,099,104 Trust
Units.
(6) Assumes net proceeds from the offering of $181,910,000 (net of costs of the
offering of $600,000 and the Underwriters' commissions of $8,290,000) and
assuming a Purchase Price, net of adjustments, on closing of the
Acquisition of $176,600,000.
PRICE RANGE AND TRADING VOLUME OF THE TRUST UNITS
The outstanding Trust Units are traded on the TSX under the trading symbol
"AVN.UN". The following table sets forth the price range and trading volume of
the Trust Units as reported by the TSX for the periods indicated.
Period High Low Volume
2001
May 29 - 31(1) $12.55 $12.30 117,537
June $12.40 $9.25 1,219,309
Third Quarter $10.50 $7.42 2,226,952
Fourth Quarter $8.40 $7.05 7,381,300
2002
First Quarter $11.35 $7.91 11,207,717
Second Quarter $12.14 $10.00 7,006,294
Third Quarter $13.25 $10.40 7,350,914
Fourth Quarter $13.75 $11.65 7,582,352
2003
First Quarter $15.59 $11.80 7,622,480
Second Quarter $16.95 $14.15 7,995,072
Third Quarter $17.15 $14.92 8,001,055
Fourth Quarter $17.95 $15.65 9,684,205
2004
First Quarter $19.00 $16.01 7,666,480
April $19.84 $18.80 4,120,250
May $20.08 $19.05 3,367,746
June $19.37 $17.80 3,169,079
July $19.65 $18.63 2,095,637
August $19.70 $18.51 3,219,044
September 1 and 2 $19.99 $19.60 347,000
Note:
(1) The Trust Units commenced trading on the TSX on May 29, 2001.
On August 23, 2004, the last trading day prior to the public announcement of the
offering, the closing price of the Trust Units on the TSX was $19.35. On
September 2, 2004, the closing price of the Trust Units on the TSX was $19.96.
RECORD OF CASH DISTRIBUTIONS
The following is a summary of the distributions declared by Advantage from its
inception in May 2001 to August 25, 2004.
- --------------------------------------------------------------------------------
FOR THE 2001 PERIOD ENDED DISTRIBUTIONS PER UNIT PAYMENT DATE
- --------------------------------------------------------------------------------
June 30 $0.28 July 16, 2001
July 31 $0.28 August 15, 2001
August 31 $0.22 September 17, 2001
September 30 $0.22 October 15, 2001
October 31 $0.15 November 15, 2001
November 30 $0.15 December 17, 2001
December 31 $0.15 January 15, 2002
-----
Total $1.45
34
- --------------------------------------------------------------------------------
FOR THE 2001 PERIOD ENDED DISTRIBUTIONS PER UNIT PAYMENT DATE
- --------------------------------------------------------------------------------
January 31 $0.15 February 15, 2002
February 28 $0.13 March 15, 2002
March 31 $0.13 April 15, 2002
April 30 $0.13 May 15, 2002
May 31 $0.13 June 17, 2002
June 30 $0.13 July 15, 2002
July 31 $0.13 August 15, 2002
August 31 $0.13 September 16, 2002
September 30 $0.13 October 15, 2002
October 31 $0.18 November 15, 2002
November 30 $0.18 December 16, 2002
December 31 $0.18 January 15, 2003
-----
Total $1.73
- --------------------------------------------------------------------------------
FOR THE 2001 PERIOD ENDED DISTRIBUTIONS PER UNIT PAYMENT DATE
- --------------------------------------------------------------------------------
January 31 $0.18 February 18, 2003
February 28 $0.23 March 17, 2003
March 31 $0.23 April 15, 2003
April 30 $0.23 May 15, 2003
May 31 $0.23 June 16, 2003
June 30 $0.23 July 15, 2003
July 31 $0.23 August 15, 2003
August 31 $0.23 September 15, 2003
September 30 $0.23 October 15,2003
October 31 $0.23 November 17, 2003
November 30 $0.23 December 15, 2003
December 31 $0.23 January 15, 2004
-----
Total $2.71
- --------------------------------------------------------------------------------
FOR THE 2001 PERIOD ENDED DISTRIBUTIONS PER UNIT PAYMENT DATE
- --------------------------------------------------------------------------------
January 31 $0.23 February 17, 2004
February 29 $0.23 March 15, 2004
March 31 $0.23 April 15, 2004
April 30 $0.23 May 17, 2004
May 31 $0.23 June 15, 2004
June 30 $0.23 July 15, 2004
July 31 $0.23 August 16, 2004
August 31(1) $0.23 September 15, 2004
-----
Total $1.84
Note:
(1) The Trust announced on August 17, 2004 that a distribution of $0.23 per
Trust Unit will be paid on September 15, 2004 to Unitholders of record on
August 31, 2004.
On August 24, 2004 the Trust announced that subject to closing the Acquisition
on or before September 30, 2004, the monthly distribution of distributable cash
to be paid on November 15, 2004 to Unitholders of record on October 29, 2004
will be $0.25 per Unit.
The Trust intends to make cash distributions on the 15th day of each month (or
the first Business Day thereafter) to holders of Trust Units of record on the
immediately preceding record date.
35
Accordingly, if the Acquisition closes on or before September 30, 2004 as
currently contemplated, holders of Subscription Receipts will become holders of
Units on or before September 30, 2004 and will be entitled as Unitholders,
provided they are the holders of record of Units received pursuant to the
Subscription Receipts on September 30, 2004, to receive the monthly distribution
expected to be paid on October 15, 2004 to Unitholders of record on September
30, 2004. If the closing of the Acquisition occurs after September 30, 2004, but
on or before November 1, 2004, holders of record of Subscription Receipts on the
date they are exchanged for Units will be entitled to receive a payment
equivalent to the distribution that will be paid by the Trust to Unitholders of
record on September 30, 2004 or any subsequent Unit distribution record date
(being on or about the last day of each month) prior to such closing. See
"Details of the Offering".
USE OF PROCEEDS
The net proceeds to the Trust from the sale of the Subscription Receipts and the
Debentures hereunder are estimated to be $181,910,000 after deducting the fees
of $8,290,000 payable to the Underwriters and the estimated expenses of the
issue of $600,000. The net proceeds of the offering will be used by the Trust to
pay the purchase price of the Acquisition and to repay indebtedness under the
Credit Facilities. See "Recent Developments" and "Relationship Among the Trust
and Certain Underwriters".
DETAILS OF THE OFFERINGS
SUBSCRIPTION RECEIPTS
The following is a summary of the material attributes and characteristics of the
Subscription Receipts. This summary does not purport to be complete and is
subject to, and qualified in its entirety by, reference to the terms of the
Subscription Receipt Agreement.
At closing, a certificate representing the Subscription Receipts will be issued
in registered form to CDS or its nominee, CDS & Co., and will be deposited with
CDS on the closing date of this offering pursuant to the book-entry only system.
Unless the book-entry only system is terminated, and except in certain limited
circumstances, owners of beneficial interests in Subscription Receipts shall not
receive a certificate for subscription receipts or, unless requested, for the
Trust Units issuable on the exchange of the Subscription Receipts. Beneficial
interests in Subscription Receipts will generally be represented solely through
the book-entry only system and such interests will be evidenced by customer
confirmations of purchase from the Underwriters.
The Escrowed Funds will be delivered to and held by the Escrow Agent and
invested in short-term obligations of, or guaranteed by, the Government of
Canada (and other approved investments) pending the closing of the Acquisition.
Provided that the closing of the Acquisition occurs by 5:00 p.m. (Calgary time)
on November 1, 2004, the Escrowed Funds and the interest earned thereon will be
released to the Trust and the Units will be issued to holders of Subscription
Receipts who will receive, without payment of additional consideration or
further action, one Unit for each Subscription Receipt held.
Forthwith upon the closing of the Acquisition, the Trust will execute and
deliver to the Escrow Agent a notice thereof, and will issue and deliver the
Units to the Escrow Agent. Contemporaneously with the delivery of such notice,
the Trust will issue a press release specifying that the Units have been issued.
If the closing of the Acquisition does not take place by 5:00 p.m. (Calgary
time) on November 1, 2004, the Acquisition is terminated at any earlier time or
the Trust has advised the Underwriters or announced to the public that it does
not intend to proceed with the Acquisition (in any case, the "TERMINATION
TIME"), holders of Subscription Receipts shall be entitled to receive an amount
equal to the full subscription price therefor and their PRO RATA entitlements to
interest on such amount. The Escrowed Funds and interest earned thereon will be
applied toward payment of such amount.
If the closing of the Acquisition takes place prior to the Termination Time and
holders of Subscription Receipts become entitled to receive Units pursuant to
the Subscription Receipt Agreement, holders of record of Subscription Receipts
on the date they are exchanged for Units will be entitled to receive an amount
per Subscription Receipt equal to the amount per Unit of any cash distributions
for which record dates have occurred during the period from the date of closing
of the offering to the date immediately preceding the date the Units are issued
pursuant to the Subscription Receipts (the "SPECIAL INTEREST"). All or a portion
of this amount will be satisfied by the payment by
36
the Escrow Agent to holders of Subscription Receipts of interest earned on the
Escrowed Funds. The difference, if any, between the amount of interest earned on
the Escrowed Funds and the Special Interest will be paid by the Trust. If
holders of Subscription Receipts become entitled to receive Units, the Escrow
Agent and the Trust will pay such amounts to holders of record of Subscription
Receipts on the date they are exchanged for Units on the later of the date the
Units are issued and the date such distribution(s) is paid to Unitholders. For
greater certainty, if the closing of the Acquisition takes place on a date that
is a Unit distribution record date, holders of record of Subscription Receipts
on such date shall not be entitled as such to receive a payment in respect of
the cash distribution for such record date but shall instead be deemed to be
holders of record of Units on such date and will be entitled as Unitholders to
receive such monthly distribution.
Accordingly, if the Acquisition closes on or before September 30, 2004 as
currently contemplated, holders of Subscription Receipts will become holders of
Units on or before September 30, 2004 and will be entitled as Unitholders,
provided they are the holders of record of Units received pursuant to the
Subscription Receipts on September 30, 2004, to receive the monthly distribution
expected to be paid on October 15, 2004 to Unitholders of record on September
30, 2004. If the closing of the Acquisition occurs after September 30, 2004, but
on or before November 1, 2004, holders of record of Subscription Receipts on the
date they are exchanged for Units will be entitled to receive a payment
equivalent to the distribution that will be paid by the Trust to Unitholders of
record on September 30, 2004 or any subsequent Unit distribution record date
(being on or about the last day of each month) prior to such closing.
Under the Subscription Receipt Agreement, original purchasers of Subscription
Receipts under the offering will have a contractual right of rescission
following the issuance of Units to such purchaser upon the exchange of the
Subscription Receipts to receive the amount paid for the Subscription Receipts
if this short form prospectus (including documents incorporated by reference)
and any amendment contains a misrepresentation or is not delivered to such
purchaser, provided such remedy for rescission is exercised within 180 days of
closing of the offering.
HOLDERS OF SUBSCRIPTION RECEIPTS ARE NOT UNITHOLDERS. HOLDERS OF SUBSCRIPTION
RECEIPTS ARE ENTITLED ONLY TO RECEIVE UNITS ON SURRENDER OF THEIR SUBSCRIPTION
RECEIPTS TO THE ESCROW AGENT OR TO A RETURN OF THE SUBSCRIPTION PRICE FOR THE
SUBSCRIPTION RECEIPTS TOGETHER WITH ANY PAYMENTS IN LIEU OF INTEREST OR
DISTRIBUTIONS, AS APPLICABLE, AS DESCRIBED ABOVE.
DEBENTURES
The offering of Debentures consists of 75,000 7.50% Debentures and 50,000 7.75%
Debentures, each at a price of $1,000 per Debenture. The following is a summary
of the material attributes and characteristics of the Debentures. This summary
does not purport to be complete and is subject to, and qualified in its entirety
by, reference to the terms of the Indenture referred to below.
GENERAL
The Debentures will be issued under the Indenture. The Debentures authorized for
issue immediately will be limited in aggregate principal amount to $75,000,000
7.50% Debentures and $50,000,000 7.75% Debentures. The Trust may, however, from
time to time, without the consent of the holders of the Debentures but subject
to the limitations described herein, issue additional debentures of the same
series or of a different series under the Indenture, in addition to the
Debentures offered hereby. The Debentures will be issuable only in denominations
of $1,000 and integral multiples thereof.
The 7.50% Debentures will be dated as of the closing date of the offering and
will have an initial maturity date of November 1, 2004. If the closing of the
Acquisition takes place by the Termination Time in all material respects as
contemplated in the Acquisition Agreement, the maturity date will be
automatically extended from the Initial Maturity Date to October 1, 2009. If the
closing of the Acquisition does not take place by the Termination Time, the
7.50% Debentures will mature on the Initial Maturity Date.
37
The 7.50% Debentures will bear interest from the date of issue at 7.50% per
annum, which will be payable semi-annually in arrears on April 1 and October 1
in each year, commencing with April 1, 2005. The first interest payment will
include interest accrued from the closing of the offering to but excluding April
1, 2005.
The 7.75% Debentures will be dated as of the closing date of the offering and
will have an initial maturity date of November 1, 2004. If the closing of the
Acquisition takes place by the Termination Time in all material respects as
contemplated in the Acquisition Agreement, the maturity date will be
automatically extended from the Initial Maturity Date to December 1, 2011. If
the closing of the Acquisition does not take place by the Termination Time, the
7.75% Debentures will mature on the Initial Maturity Date.
The 7.75% Debentures will bear interest from the date of issue at 7.75% per
annum, which will be payable semi-annually in arrears on June 1 and December 1
in each year, commencing with June 1, 2005. The first interest payment will
include interest accrued from the closing of the offering to but excluding June
1, 2005.
The principal amount of the Debentures will be payable in lawful money of Canada
or, at the option of the Trust and subject to applicable regulatory approval, by
payment of Units as further described under "Payment upon Redemption or
Maturity" and "Redemption and Purchase". The interest on the Debentures will be
payable in lawful money of Canada including, at the option of the Trust and
subject to applicable regulatory approval, in accordance with the Unit Interest
Payment Obligation as described under "Interest Payment Option".
The Debentures will be direct obligations of the Trust and will not be secured
by any mortgage, pledge, hypothec or other charge and will be subordinated to
other liabilities of the Trust as described under "Subordination". Other than as
described herein, the Indenture will not restrict the Trust from incurring
additional indebtedness for borrowed money or from mortgaging, pledging or
charging its properties to secure any indebtedness.
CONVERSION PRIVILEGE
The 7.50% Debentures will be convertible at the holder's option into fully paid
and non-assessable Units at any time prior to 5:00 p.m. (Calgary time) on the
earlier of the maturity date, being the Initial Maturity Date or the 7.50% Final
Maturity Date, as applicable, and the business day immediately preceding the
date specified by the Trust for redemption of the 7.50% Debentures, at a
conversion price of $20.25 per Unit (the "7.50% CONVERSION PRICE"), being a
conversion rate of 49.3827 Units for each $1,000 principal amount of 7.50%
Debentures. No adjustment will be made for distributions on Units issuable upon
conversion or for interest accrued on 7.50% Debentures surrendered for
conversion; however, holders converting their 7.50% Debentures will receive
accrued and unpaid interest thereon. Notwithstanding the foregoing, no 7.50%
Debentures may be converted during the three business days preceding April 1 and
October 1 in each year, commencing April 1, 2005, as the registers of the
Debenture Trustee will be closed during such periods.
The 7.75% Debentures will be convertible at the holder's option into fully paid
and non-assessable Units at any time prior to 5:00 p.m. (Calgary time) on the
earlier of the maturity date, being the Initial Maturity Date or the 7.75% Final
Maturity Date, as applicable, and the business day immediately preceding the
date specified by the Trust for redemption of the 7.75% Debentures, at a
conversion price of $21.00 per Unit (the "7.75% CONVERSION PRICE"), being a
conversion rate of 47.6190 Units for each $1,000 principal amount of 7.75%
Debentures. No adjustment will be made for distributions on Units issuable upon
conversion or for interest accrued on 7.75% Debentures surrendered for
conversion; however, holders converting their 7.75% Debentures will receive
accrued and unpaid interest thereon. Notwithstanding the foregoing, no 7.75%
Debentures may be converted during the three business days preceding June 1 and
December 1 in each year, commencing June 1, 2005, as the registers of the
Debenture Trustee will be closed during such periods. "CONVERSION PRICE" means
the 7.50% Conversion Price in respect of the 7.50% Debentures and the 7.75%
Conversion Price in respect of the 7.75% Debentures.
Subject to the provisions thereof, the Indenture will provide for the adjustment
of the Conversion Price in certain events including: (a) the subdivision or
consolidation of the outstanding Units; (b) the distribution of Units to holders
of Units by way of distribution or otherwise other than an issue of securities
to holders of Units who have elected to receive distributions in securities of
the Trust in lieu of receiving cash distributions paid in the ordinary course;
(c) the issuance of options, rights or warrants to holders of Units entitling
them to acquire Units or other securities convertible into Units at less than
95% of the then current market price (as defined below under "Payment upon
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Redemption or Maturity") of the Units; and (d) the distribution to all holders
of Units of any securities or assets (other than cash distributions and
equivalent distributions in securities paid in lieu of cash distributions in the
ordinary course). There will be no adjustment of the Conversion Price in respect
of any event described in (b), (c) or (d) above if the holders of the Debentures
are allowed to participate as though they had converted their Debentures prior
to the applicable record date or effective date. The Trust will not be required
to make adjustments in the Conversion Price unless the cumulative effect of such
adjustments would change the conversion price by at least 1%.
The term "current market price" will be defined in the Indenture to mean the
weighted average trading price of the Units on the TSX for the 20 consecutive
trading days ending on the fifth trading day preceding the date fixed for
redemption or the maturity date, as the case may be.
In the case of any reclassification or capital reorganization (other than a
change resulting from consolidation or subdivision) of the Units or in the case
of any consolidation, amalgamation or merger of the Trust with or into any other
entity, or in the case of any sale or conveyance of the properties and assets of
the Trust as, or substantially as, an entirety to any other entity, or a
liquidation, dissolution or winding-up of the Trust, the terms of the conversion
privilege shall be adjusted so that each holder of a Debenture shall, after such
reclassification, capital reorganization, consolidation, amalgamation, merger,
sale, conveyance, liquidation, dissolution or winding up, be entitled to receive
the number of Units or other securities or property such holder would be
entitled to receive if on the effective date thereof, it had been the holder of
the number of Units into which the Debenture was convertible prior to the
effective date of such reclassification, capital reorganization, consolidation,
amalgamation, merger, sale, conveyance, liquidation, dissolution or winding up.
No fractional Units will be issued on any conversion but in lieu thereof the
Trust shall satisfy fractional interests by a cash payment equal to the current
market price of any fractional interest.
REDEMPTION AND PURCHASE
The 7.50% Debentures will not be redeemable on or before October 1, 2007. After
October 1, 2007 and prior to maturity, the 7.50% Debentures may be redeemed in
whole or in part from time to time at the option of the Trust on not more than
60 days and not less than 30 days prior notice, at a redemption price of $1,050
per 7.50% Debenture after October 1, 2007 and on or before October 1, 2008 and
at a redemption price of $1,025 per 7.50% Debenture after October 1, 2008 and
before maturity (each a "7.50% REDEMPTION PRICE"), in each case, plus accrued
and unpaid interest thereon, if any.
The 7.75% Debentures will not be redeemable on or before December 1, 2007. After
December 1, 2007 and prior to maturity, the 7.75% Debentures may be redeemed in
whole or in part from time to time at the option of the Trust on not more than
60 days and not less than 30 days prior notice, at a redemption price of $1,050
per 7.75% Debenture after December 1, 2007 and on or before December 1, 2008, at
a redemption price of $1,025 per 7.75% Debenture after December 1, 2008 and on
or before December 1, 2009 and at a redemption price of $1,000 per 7.75%
Debenture after December 1, 2009 and before maturity (each a "7.75% REDEMPTION
PRICE"), in each case, plus accrued and unpaid interest thereon, if any.
"REDEMPTION PRICE" means the 7.50% Redemption Price in respect of the 7.50%
Debentures and the 7.75% Redemption Price in respect of the 7.75% Debentures.
In the case of redemption of less than all of the Debentures, the Debentures to
be redeemed will be selected by the Debenture Trustee on a PRO RATA basis or in
such other manner as the Debenture Trustee deems equitable, subject to the
consent of the TSX.
The Trust will have the right to purchase Debentures in the market, by tender or
by private contract.
PAYMENT UPON REDEMPTION OR MATURITY
On redemption or at maturity, the Trust will repay the indebtedness represented
by the Debentures by paying to the Debenture Trustee in lawful money of Canada
an amount equal to the aggregate Redemption Price of the outstanding Debentures
which are to be redeemed or the principal amount of the outstanding Debentures
which have matured, as the case may be, together with accrued and unpaid
interest thereon. The Trust may, at its option, on not
39
more than 60 days and not less than 40 days prior notice and subject to
applicable regulatory approval, elect to satisfy its obligation to pay the
Redemption Price of the Debentures which are to be redeemed or the principal
amount of the Debentures which have matured, as the case may be, by issuing
Units to the holders of the Debentures. Any accrued and unpaid interest thereon
will be paid in cash. The number of Units to be issued will be determined by
dividing the aggregate Redemption Price of the outstanding Debentures which are
to be redeemed or the principal amount of the outstanding Debentures which have
matured, as the case may be, by 95% of the current market price on the date
fixed for redemption or the maturity date, as the case may be. Although the
Trust will have the option to satisfy its obligation to pay the principal amount
of the Debentures due on the Initial Maturity Date by issuing Trust Units, if
the Acquisition is not completed prior to the Termination Time, the Trust
currently intends to repay the amounts due on the Initial Maturity Date with
cash. No fractional Units will be issued on redemption or maturity but in lieu
thereof the Trust shall satisfy fractional interests by a cash payment equal to
the current market price of any fractional interest.
SUBORDINATION
The payment of the principal of, and interest on, the Debentures will be
subordinated in right of payment, as set forth in the Indenture, to the prior
payment in full of all Senior Indebtedness of the Trust and indebtedness to
trade creditors of the Trust. "Senior Indebtedness" of the Trust will be defined
in the Indenture as the principal of and premium, if any, and interest on and
other amounts in respect of all indebtedness of the Trust (whether outstanding
as at the date of the Indenture or thereafter incurred), other than indebtedness
evidenced by the Debentures and all other existing and future debentures or
other instruments of the Trust which, by the terms of the instrument creating or
evidencing the indebtedness, is expressed to be PARI PASSU with, or subordinate
in right of payment to, the Debentures.
The Indenture will provide that in the event of any insolvency or bankruptcy
proceedings, or any receivership, liquidation, reorganization or other similar
proceedings relative to the Trust, or to its property or assets, or in the event
of any proceedings for voluntary liquidation, dissolution or other winding-up of
the Trust, whether or not involving insolvency or bankruptcy, or any marshalling
of the assets and liabilities of the Trust, then those holders of Senior
Indebtedness, including any indebtedness to trade creditors, will receive
payment in full before the holders of Debentures will be entitled to receive any
payment or distribution of any kind or character, whether in cash, property or
securities, which may be payable or deliverable in any such event in respect of
any of the Debentures or any unpaid interest accrued thereon. The Indenture will
also provide that the Trust will not make any payment, and the holders of the
Debentures will not be entitled to demand, institute proceedings for the
collection of, or receive any payment or benefit (including, without any
limitation, by set-off, combination of accounts or realization of security or
otherwise in any manner whatsoever) on account of indebtedness represented by
the Debentures (a) in a manner inconsistent with the terms (as they exist on the
date of issue) of the Debentures or (b) at any time when an event of default has
occurred under the Senior Indebtedness and is continuing and the notice of such
event of default has been given by or on behalf of the holders of Senior
Indebtedness to the Trust, unless the Senior Indebtedness has been repaid in
full.
The Debentures will also be effectively subordinate to claims of creditors of
the Trust's subsidiaries except to the extent the Trust is a creditor of such
subsidiaries ranking at least PARI PASSU with such other creditors. The
Debentures will also be subordinated in right of payment to the prior payment in
full of all indebtedness under the Credit Facilities.
PRIORITY OVER TRUST DISTRIBUTIONS
The Trust Indenture provides that certain expenses of the Trust must be deducted
in calculating the amount to be distributed to the Unitholders. Accordingly, the
funds required to satisfy the interest payable on the Debentures, as well as the
amount payable upon redemption or maturity of the Debentures or upon an Event of
Default (as defined below), will be deducted and withheld from the amounts that
would otherwise be payable as distributions to Unitholders.
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CHANGE OF CONTROL OF THE TRUST
Within 30 days following the occurrence of a change of control of the Trust
involving the acquisition of voting control or direction over 66?% or more of
the Units (a "CHANGE OF CONTROL"), the Trust will be required to make an offer
in writing to purchase all of the Debentures then outstanding (the "DEBENTURE
OFFER"), at a price equal to 101% of the principal amount thereof plus accrued
and unpaid interest (the "DEBENTURE OFFER PRICE").
The Indenture contains notification and repurchase provisions requiring the
Trust to give written notice to the Debenture Trustee of the occurrence of a
Change of Control within 30 days of such event together with the Debenture
Offer. The Debenture Trustee will thereafter promptly mail to each holder of
Debentures a notice of the Change of Control together with a copy of the
Debenture Offer to repurchase all the outstanding Debentures.
If 90% or more of the aggregate principal amount of the Debentures outstanding
on the date of the giving of notice of the Change of Control have been tendered
to the Trust pursuant to the Debenture Offer, the Trust will have the right and
obligation to redeem all the remaining Debentures at the Debenture Offer Price.
Notice of such redemption must be given by the Trust to the Debenture Trustee
within 10 days following the expiry of the Debenture Offer, and as soon as
possible thereafter, by the Debenture Trustee to the holders of the Debentures
not tendered pursuant to the Debenture Offer.
INTEREST PAYMENT OPTION
The Trust may elect, from time to time, to satisfy its obligation to pay all or
any part of the interest on the Debentures (the "INTEREST OBLIGATION"), on the
date it is payable under the Indenture (an "INTEREST PAYMENT Date"), by
delivering sufficient Units to the Debenture Trustee to satisfy all or the part,
as the case may be, of the Interest Obligation in accordance with the Indenture
(the "UNIT INTEREST PAYMENT ELECTION"). The Indenture will provide that, upon
such election, the Debenture Trustee shall (a) accept delivery from the Trust of
Units, (b) accept bids with respect to, and consummate sales of, such Units,
each as the Trust shall direct in its absolute discretion, (c) invest the
proceeds of such sales in short-term permitted government securities (as defined
in the Indenture) which mature prior to the applicable Interest Payment Date,
and use the proceeds received from such permitted government securities,
together with any proceeds from the sale of Units not invested as aforesaid, to
satisfy the Interest Obligation, and (d) perform any other action necessarily
incidental thereto.
The Indenture will set forth the procedures to be followed by the Trust and the
Debenture Trustee in order to effect the Unit Interest Payment Election. If a
Unit Interest Payment Election is made, the sole right of a holder of Debentures
in respect of interest will be to receive cash from the Debenture Trustee out of
the proceeds of the sale of Units (plus any amount received by the Debenture
Trustee from the Trust attributable to any fractional Units) in full
satisfaction of the Interest Obligation, and the holder of such Debentures will
have no further recourse to the Trust in respect of the Interest Obligation.
Neither the Trust's making of the Unit Interest Payment Election nor the
consummation of sales of Units will (a) result in the holders of the Debentures
not being entitled to receive on the applicable Interest Payment Date cash in an
aggregate amount equal to the interest payable on such Interest Payment Date, or
(b) entitle such holders to receive any Units in satisfaction of the Interest
Obligation.
EVENTS OF DEFAULT
The Indenture will provide that an event of default ("EVENT OF DEFAULT") in
respect of the Debentures will occur if any one or more of the following
described events has occurred and is continuing with respect of the Debentures:
(a) failure for 10 days to pay interest on the Debentures when due; (b) failure
to pay principal or premium, if any, on the Debentures when due, whether at
maturity, upon redemption, by declaration or otherwise; (c) certain events of
bankruptcy, insolvency or reorganization of the Trust under bankruptcy or
insolvency laws; or (d) default in the observance or performance of any material
covenant or condition of the Indenture and continuance of such default for a
period of 30 days after notice in writing has been given by the Debenture
Trustee to the Trust specifying such default and requiring the Trust to rectify
the same. If an Event of Default has occurred and is continuing, the Debenture
Trustee may, in its discretion, and shall upon request of holders of not less
than 25% of the principal amount of Debentures then outstanding, declare the
principal of and interest on all outstanding Debentures to be
41
immediately due and payable. In certain cases, the holders of more than 50% of
the principal amount of the Debentures then outstanding may, on behalf of the
holders of all such Debentures, waive any Event of Default and/or cancel any
such declaration upon such terms and conditions as such holders shall prescribe.
Certain Events of Default under the Indenture may only be Events of Default in
relation to a particular series of debentures in which case such provisions
would apply only in relation to such series.
OFFERS FOR DEBENTURES
The Indenture will contain provisions to the effect that if an offer is made for
the Debentures which is a take-over bid for Debentures within the meaning of the
SECURITIES ACT (Alberta) and not less than 90% of the Debentures (other than
Debentures held at the date of the take-over 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 Debentures held by the
holders of Debentures who did not accept the offer on the terms offered by the
offeror.
MODIFICATION
The rights of the holders of the Debentures as well as any other series of
debentures that may be issued under the Indenture may be modified in accordance
with the terms of the Indenture. For that purpose, among others, the Indenture
will contain certain provisions which will make binding on all Debenture holders
resolutions passed at meetings of the holders of Debentures by votes cast
thereat by holders of not less than 66?% of the principal amount of the
Debentures present at the meeting or represented by proxy, or rendered by
instruments in writing signed by the holders of not less than 66?% of the
principal amount of the Debentures then outstanding. In certain cases, the
modification will, instead or in addition, require assent by the holders of the
required percentage of Debentures of each particularly affected series.
LIMITATION ON ISSUANCE OF ADDITIONAL DEBENTURES
The Indenture will provide that the Trust shall not issue additional convertible
debentures of equal ranking if the principal amount of all issued and
outstanding convertible debentures of the Trust exceeds 25% of the Total Market
Capitalization of the Trust immediately after the issuance of such additional
convertible debentures. "Total Market Capitalization" will be defined in the
Indenture as the total principal amount of all issued and outstanding debentures
of the Trust which are convertible at the option of the holder into Units of the
Trust plus the amount obtained by multiplying the number of issued and
outstanding Units of the Trust (including Trust Units represented by
Subscription Receipts) by the current market price of the Units on the relevant
date.
LIMITATION ON NON-RESIDENT OWNERSHIP
AOG may, at any time and from time to time, in its sole discretion, request that
the Debenture Trustee make reasonable efforts, as practicable in the
circumstances, to obtain declarations as to beneficial ownership of Debentures,
perform residency searches of holders of Debentures and beneficial holders of
Debentures mailing address lists and take such other steps specified by AOG to
determine or estimate as best possible the residence of the beneficial owners of
Debentures. If at any time the board of directors of AOG, in its sole
discretion, determines that it is in the best interest of the Trust, AOG may:
(i) require the Debenture Trustee to refuse to accept a subscription for the
Debentures from, or issue or register a transfer of Trust Units to, a person
unless the person provides a declaration to AOG that the Debentures to be issued
or transferred to such person will not when issued or transferred be
beneficially owned by a non-resident of Canada; (ii) to the extent practicable
in the circumstances, send a notice to registered holders of the Debentures
which are beneficially owned by non-residents of Canada, chosen in inverse order
to the order of acquisition or registration of such Debentures beneficially
owned by non-residents of Canada or in such other manner as AOG may consider
equitable and practicable, requiring them to sell their Debentures which are
beneficially owned by non-residents of Canada or a specified portion thereof
within a specified period of not less than 60 days. If the holders of Debentures
receiving such notice have not sold the specified number of such Debentures or
provided AOG with satisfactory evidence that such Debentures are not
beneficially owned by non-residents within such period, AOG may, on behalf of
such registered holder of Debentures, sell such Debentures and, in the interim,
suspend the rights attached to such Debentures; and (iii) take such other
actions as the board of directors of AOG determines, in its sole discretion, are
appropriate in the
42
circumstances that will reduce or limit the number of Debentures held by
non-residents to ensure that the Trust is not maintained primarily for the
benefit of non-residents of Canada.
BOOK-ENTRY SYSTEM FOR DEBENTURES
The Debentures will be issued in "book-entry only" form and must be purchased or
transferred through a participant in the depository service of CDS (a
"PARTICIPANT"). On the closing date of the offering, the Debenture Trustee will
cause the Debentures to be delivered to CDS and registered in the name of its
nominee. The Debentures will be evidenced by a single book-entry only
certificate. Registration of interests in and transfers of the Debentures will
be made only through the depository service of CDS.
Except as described below, a purchaser acquiring a beneficial interest in the
Debentures (a "BENEFICIAL OWNER") will not be entitled to a certificate or other
instrument from the Debenture Trustee or CDS evidencing that purchaser's
interest therein, and such purchaser will not be shown on the records maintained
by CDS, except through a Participant. Such purchaser will receive a confirmation
of purchase from the Underwriter or other registered dealer from whom Debentures
are purchased.
Neither the Trust nor the Underwriters will assume any liability for: (a) any
aspect of the records relating to the beneficial ownership of the Debentures
held by CDS or the payments relating thereto; (b) maintaining, supervising or
reviewing any records relating to the Debentures; or (c) any advice or
representation made by or with respect to CDS and contained in this short form
prospectus and relating to the rules governing CDS or any action to be taken by
CDS or at the direction of its Participants. The rules governing CDS provide
that it acts as the agent and depositary for the Participants. As a result,
Participants must look solely to CDS and Beneficial Owners must look solely to
Participants for the payment of the principal and interest on the Debentures
paid by or on behalf of the Trust to CDS.
As indirect holders of Debentures, investors should be aware that they (subject
to the situations described below): (a) may not have Debentures registered in
their name; (b) may not have physical certificates representing their interest
in the Debentures; (c) may not be able to sell the Debentures to institutions
required by law to hold physical certificates for securities they own; and (d)
may be unable to pledge Debentures as security.
The Debentures will be issued to Beneficial Owners in fully registered and
certificate form (the "DEBENTURE CERTIFICATES") only if: (a) required to do so
by applicable law; (b) the book-entry only system ceases to exist; (c) the Trust
or CDS advises the Debenture Trustee that CDS is no longer willing or able to
properly discharge its responsibilities as depositary with respect to the
Debentures and the Trust is unable to locate a qualified successor; (d) the
Trust, at its option, decides to terminate the book-entry only system through
CDS; or (e) after the occurrence of an Event of Default (as defined herein),
provided that Participants acting on behalf of Beneficial Owners representing,
in the aggregate, more than 25% of the aggregate principal amount of the
Debentures then outstanding advise CDS in writing that the continuation of a
book-entry only system through CDS is no longer in their best interest, and
provided further that the Debenture Trustee has not waived the Event of Default
in accordance with the terms of the Indenture.
Upon the occurrence of any of the events described in the immediately preceding
paragraph, the Debenture Trustee must notify CDS, for and on behalf of
Participants and Beneficial Owners, of the availability through CDS of Debenture
Certificates. Upon surrender by CDS of the single certificate representing the
Debentures and receipt of instructions from CDS for the new registrations, the
Debenture Trustee will deliver the Debentures in the form of Debenture
Certificates and thereafter the Trust will recognize the holders of such
Debenture Certificates as debentureholders under the Indenture.
Interest on the Debentures will be paid directly to CDS while the book-entry
only system is in effect. If Debenture Certificates are issued, interest will be
paid by cheque drawn on the Trust and sent by prepaid mail to the registered
holder or by such other means as may become customary for the payment of
interest. Payment of principal, including payment in the form of Units if
applicable, and the interest due, at maturity or on a redemption date, will be
paid directly to CDS while the book-entry only system is in effect. If Debenture
Certificates are issued, payment of principal, including payment in the form of
Units if applicable, and interest due, at maturity or on a redemption date, will
be paid upon surrender thereof at any office of the Debenture Trustee or as
otherwise specified in the Indenture.
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PLAN OF DISTRIBUTION
Pursuant to the Underwriting Agreement, the Trust has agreed to issue and sell
an aggregate of 3,500,000 Subscription Receipts, an aggregate of 75,000 7.50%
Debentures and an aggregate of 50,000 7.75% Debentures to the Underwriters, and
the Underwriters have severally agreed to purchase such Subscription Receipts
and Debentures on September 14, 2004, or such other date as may be agreed among
the parties to the Underwriting Agreement. Delivery of the Subscription Receipts
and Debentures is conditional upon payment on closing of $18.80 per Subscription
Receipt by the Underwriters to the Escrow Agent and $1,000 per Debenture by the
Underwriters to the Trust. The Underwriting Agreement provides that the Trust
will pay the Underwriters' fee of $0.94 per Subscription Receipt for
Subscription Receipts issued and sold by the Trust and $40 per Debenture for
Debentures issued and sold by the Trust, for an aggregate fee payable by the
Trust of $8,290,000, in consideration for their services in connection with the
offering. The Underwriters' fee in respect of the Subscription Receipts is
payable as to 50% upon the closing of the offering and 50% upon closing of the
Acquisition. If the Acquisition is not completed by November 1, 2004, the
Underwriters' fee in respect of the Subscription Receipts will be reduced to the
amount payable upon closing of the offering. The Underwriters' fee in respect of
the Debentures is payable on closing of the offering. The terms of the offering
were determined by negotiation between AOG and the Manager, on behalf of the
Trust, and Scotia Capital Inc., on its own behalf and on behalf the other
Underwriters.
The obligations of the Underwriters under the Underwriting Agreement are several
and not joint, and may be terminated at their discretion upon the occurrence of
certain stated events. THE OBLIGATIONS OF THE TRUST AND THE UNDERWRITERS UNDER
THE UNDERWRITING AGREEMENT TO COMPLETE THE PURCHASE AND SALE OF THE SUBSCRIPTION
RECEIPTS AND DEBENTURES WILL TERMINATE AUTOMATICALLY IF THE ACQUISITION IS
TERMINATED OR THE TRUST HAS ADVISED THE UNDERWRITERS OR ANNOUNCED TO THE PUBLIC
THAT IT DOES NOT INTEND TO PROCEED WITH THE ACQUISITION. If an Underwriter fails
to purchase the Subscription Receipts or the Debentures that it has agreed to
purchase, the other Underwriters may, but are not obligated to, purchase such
Subscription Receipts or Debentures. The Underwriters are, however, obligated to
take up and pay for all Subscription Receipts and Debentures if any are
purchased under the Underwriting Agreement. The Underwriting Agreement also
provides that the Trust and AOG will indemnify the Underwriters and their
directors, officers, agents, shareholders and employees against certain
liabilities and expenses.
Except in certain limited circumstances, the Subscription Receipts and the
Debentures will be issued in "book-entry only" form and must be purchased or
transferred through a participant in the depository service of CDS. See "Details
of the Offering - Subscription Receipts" and "Details of the Offering -
Book-Entry System for Debentures".
The Trust has been advised by the Underwriters that, in connection with the
offering, the Underwriters may effect transactions that stabilize or maintain
the market price of the Subscription Receipts, the Units or the Debentures at
levels other than those that might otherwise prevail in the open market. Such
transactions, if commenced, may be discontinued at any time.
The Trust has agreed that, subject to certain exceptions, it will not offer or
issue, or enter into an agreement to offer or issue, Units or any securities
convertible or exchangeable into Units for a period of 90 days subsequent to the
closing date of the offering without the consent of Scotia Capital Inc., on
behalf of the Underwriters, which consent may not be unreasonably withheld.
The TSX has conditionally approved the listing of the Subscription Receipts,
7.50% Debentures and the 7.75% Debentures offered hereunder and the Units
issuable pursuant to the Subscription Receipts and on the conversion, redemption
and maturity of the Debentures. Listing will be subject to the Trust fulfilling
all of the listing requirements of the TSX on or before November 24, 2004.
THE SUBSCRIPTION RECEIPTS AND THE DEBENTURES OFFERED HEREBY AND THE UNITS
ISSUABLE PURSUANT TO THE SUBSCRIPTION RECEIPTS AND ON CONVERSION, REDEMPTION OR
MATURITY OF THE DEBENTURES (THE "SECURITIES") HAVE NOT BEEN AND WILL NOT BE
REGISTERED UNDER THE UNITED STATES SECURITIES ACT OF 1933, AS AMENDED (THE "U.S.
44
SECURITIES ACT"), OR ANY STATE SECURITIES LAWS, AND, ACCORDINGLY, THE
SUBSCRIPTION RECEIPTS AND THE DEBENTURES MAY NOT BE OFFERED OR SOLD WITHIN THE
UNITED STATES OR TO U.S. PERSONS (AS SUCH TERM IS DEFINED IN REGULATION S UNDER
THE U.S. SECURITIES ACT). EACH UNDERWRITER HAS AGREED THAT IT WILL NOT OFFER OR
SELL THE SUBSCRIPTION RECEIPTS OR DEBENTURES WITHIN THE UNITED STATES OR TO, OR
FOR THE ACCOUNT OF, UNITED STATES PERSONS, AND WILL NOT CONDUCT ANY DIRECTED
SELLING EFFORTS IN THE UNITED STATES (AS SUCH TERM IS DEFINED IN REGULATION S TO
THE U.S. SECURITIES ACT) OR ANY OTHER JURISDICTION OUTSIDE OF CANADA.
RELATIONSHIP AMONG THE TRUST AND CERTAIN UNDERWRITERS
Four of the Underwriters, are direct or indirect wholly owned subsidiaries of
four of the lenders of the Trust pursuant to the Credit Facilities. Accordingly,
the Trust may be considered a connected issuer of Scotia Capital Inc., BMO
Nesbitt Burns Inc., National Bank Financial Inc. and RBC Dominion Securities
Inc. under applicable securities laws.
As at June 30, 2004, approximately $161,707,000 was outstanding under the Credit
Facilities. See "Consolidated Capitalization of the Trust". The Trust is in
compliance with all material terms of the agreement governing the Credit
Facilities and none of the lenders under the Credit Facilities has waived any
breach by the Trust of that agreement since its execution. Neither the financial
position of the Trust nor the value of the security under the Credit Facilities
has changed substantially since the indebtedness under the Credit Facilities was
incurred.
The decision to distribute the Subscription Receipts and Debentures offered
hereunder and the determination of the terms of the distribution were made
through negotiations primarily between the Manager and AOG, on behalf of the
Trust, and Scotia Capital Inc. on its own behalf and on behalf of the other
Underwriters. The lenders under the Credit Facilities did not have any
involvement in such decision or determination, but have been advised of the
issuance and terms thereof. As a consequence of this issuance, Scotia Capital
Inc., BMO Nesbitt Burns Inc., National Bank Financial Inc. and RBC Dominion
Securities Inc. will receive their respective share of the Underwriters' fee. In
addition, the Trust currently intends to utilize any proceeds from the offering
not used for the Acquisition to repay a portion of its indebtedness under the
Credit Facilities.
INTEREST OF EXPERTS
Certain legal matters relating to the offering will be passed upon by Burnet,
Duckworth & Palmer LLP on behalf of the Trust, and by Macleod Dixon LLP on
behalf of the Underwriters. As at the date hereof, the partners and associates
of Burnet, Duckworth & Palmer LLP, as a group and Macleod Dixon LLP, as a group,
each own, directly or indirectly, less than 1% of the Trust Units. Reserves
estimates contained herein and in the AIF, incorporated by reference into this
short form prospectus, are based upon a reports prepared by Sproule. As of the
date hereof, the principles of Sproule, as a group, beneficially own, directly
or indirectly, less than 1% of the Trust Units.
CANADIAN FEDERAL INCOME TAX CONSIDERATIONS
In the opinion of Burnet, Duckworth & Palmer LLP and Macleod Dixon LLP
(collectively, "COUNSEL"), the following summary fairly describes the principal
Canadian federal income tax considerations pursuant to the Tax Act generally
applicable to a subscriber who acquires Subscription Receipts or Debentures
pursuant to the offering and who, for purposes of the Tax Act, holds the
Subscription Receipts, the Debentures and the Units issued pursuant to the
Subscription Receipts or on the conversion, redemption or repayment of the
Debentures (collectively, the "SECURITIES") as capital property and deals at
arm's length with the Trust and the Underwriters. Generally speaking, the
Securities will be considered to be capital property to a holder provided the
holder does not hold the Securities in the course of carrying on a business of
trading or dealing in securities and has not acquired them in one or more
transactions considered to be an adventure in the nature of trade. Certain
holders who might not otherwise be considered to hold their Securities as
capital property may, in certain circumstances, be entitled to have such
Securities (other than Subscription Receipts) treated as capital property by
making the election permitted by subsection 39(4) of the Tax Act. This summary
is not applicable to: (i) a holder that is a "financial institution", as defined
in the Tax Act for purposes of the mark-to-market rules; (ii) a holder an
interest in which would be a "tax shelter investment" as defined in the Tax Act;
or (iii) a holder that is a "specified financial institution" as defined in the
Tax Act. Any such holder should consult its own tax advisor with respect to an
investment in the Securities.
45
This summary is based upon the provisions of the Tax Act in force as of the date
hereof and Counsel's understanding of the current published administrative
practices of the Canada Revenue Agency ("CRA"). Except for specifically proposed
amendments (the "PROPOSED AMENDMENTS") to the Tax Act that have been publicly
announced by the federal Minister of Finance prior to the date hereof, this
summary does not take into account or anticipate changes in the income tax law,
whether by legislative, governmental or judicial action, nor any changes in the
administrative practices of the CRA. This summary is not exhaustive of all
Canadian federal income tax considerations nor does it take into account any
provincial, territorial or foreign tax considerations arising from the
acquisition, ownership or disposition of the Securities. Except as otherwise
indicated, this summary is based on the assumption that all transactions
described herein occur at fair market value.
THIS SUMMARY IS OF A GENERAL NATURE ONLY AND IS NOT INTENDED TO BE, NOR SHOULD
IT BE CONSTRUED TO BE, LEGAL OR TAX ADVICE TO ANY PROSPECTIVE PURCHASER OR
HOLDER OF SECURITIES, AND NO REPRESENTATIONS WITH RESPECT TO THE INCOME TAX
CONSEQUENCES TO ANY PROSPECTIVE PURCHASER OR HOLDER ARE MADE. CONSEQUENTLY,
PROSPECTIVE HOLDERS SHOULD CONSULT THEIR OWN TAX ADVISORS WITH RESPECT TO THEIR
PARTICULAR CIRCUMSTANCES.
TAXATION OF HOLDERS OF SUBSCRIPTIONS RECEIPTS RESIDENT IN CANADA
No gain or loss will be realized by a holder on the issuance of a Unit pursuant
to a Subscription Receipt. However, if the Acquisition is completed prior to the
Termination Time, the holder of a Subscription Receipt, in addition to receiving
a Unit in exchange therefor, will be entitled to receive an amount equal to the
distributions that the holder would have received on such Unit had the Unit been
issued to the holder on the date of closing of this offering. Counsel is of the
view that the treatment of this additional amount is unclear and it should
either be included as income or characterized as a purchase price adjustment.
Counsel is advised that the Trust will treat such amount as consideration for
use of money. The cost of any Units acquired must be averaged with the cost of
any other Units held by the Unitholder as capital property to determine the
adjusted cost base of each Unit held.
In the event the Acquisition does not close before the Termination Time or if
the Acquisition is terminated at an earlier time, holders of Subscription
Receipts will be required to include their proportionate share of interest on
the Escrowed Funds in computing their income for purposes of the Tax Act.
A disposition or deemed disposition by a holder of a Subscription Receipt, other
than on the exchange thereof for a Unit, but including on the repayment of the
issue price thereof by the Trust in the event the Acquisition is not completed
before the Termination Time, will generally result in the holder realizing a
capital gain (or capital loss) equal to the amount by which the proceeds of
disposition are greater (or less) than the aggregate of the holder's adjusted
cost base thereof and any reasonable costs of disposition. In the event that a
holder becomes entitled to the repayment of the issue price of a Subscription
Receipt as a consequence of the Acquisition not becoming effective prior to the
Termination Time, any amount that is paid to the holder by the Trust as or on
account of interest will be included in the holder's income and excluded from
the holder's proceeds of disposition.
One-half of any capital gain realized by the holder will be included in the
holder's income under the Tax Act for the year of disposition as a taxable
capital gain. One-half of any capital loss realized on a disposition of a
Subscription Receipt may be deducted against taxable capital gains realized by
the holder in the year of disposition, in the three preceding taxation years or
in any subsequent taxation year, to the extent and under the circumstances
described in the Tax Act.
A capital gain realized by a holder who is an individual may give rise to a
liability for alternative minimum tax. A holder that is throughout the year a
"Canadian-controlled private corporation" (as defined in the Tax Act) may be
liable to pay an additional refundable tax of 6 ?% on certain investment income,
including interest and taxable capital gains.
TAXATION OF HOLDERS OF SUBSCRIPTIONS RECEIPTS NOT RESIDENT IN CANADA
No gain or loss will be realized by a holder on the issuance of a Unit pursuant
to a Subscription Receipt. However, if the Acquisition is completed prior to the
Termination Time, the holder of a Subscription Receipt, in addition to receiving
a Unit in exchange therefor, will be entitled to receive an amount equal to the
distributions that the holder would have received on such Unit had the Unit been
issued to the holder on the date of closing of this offering.
46
Counsel is advised that the Trust will be withholding for Canadian withholding
tax on such additional amounts at the rate of 25%, unless such rate is reduced
under the provisions of a tax treaty between Canada and the Unitholder's
jurisdiction of residence. Counsel is advised that where a unitholder is
resident in the United States and entitled to claim the benefit of the Canada-US
Tax Convention the Trust will be withholding at a rate of 10%.
In the event the Acquisition does not close before the Termination Time or if
the Acquisition is terminated at an earlier time, a holder of Subscription
Receipts who is not resident or deemed to be resident in Canada will be subject
to withholding tax on such holder's proportionate share of interest on the
Escrowed Funds which is paid or credited to such holders at the rate of 25%,
unless such rate is reduced under the provisions of a tax treaty between Canada
and the holder's jurisdiction of residence. A holder resident in the United
States who is entitled to claim the benefit of the Canada-US Tax Convention will
generally be entitled to have the rate of withholding reduced to 10% of the
amount of any interest paid or credited. If and to the extent the Escrowed Funds
are invested in obligations of, or guaranteed by, the Government of Canada,
interest on such obligations that is paid or credited to a non-resident holder
of Subscription Receipts will not be subject to Canadian tax.
A disposition or deemed disposition of Subscription Receipts will not give rise
to any capital gains subject to tax under the Tax Act to a holder who is not
resident or deemed to be resident in Canada provided that the Subscription
Receipts are not "taxable Canadian property" of the holder for the purposes of
the Tax Act. Generally, Subscription Receipts will not constitute "taxable
Canadian property" to a non-resident holder at the time of the disposition or
deemed disposition thereof unless (i) the holder uses or holds or is deemed to
use or hold the Subscription Receipts (or the Trust Units issuable pursuant
thereto) in, or in the course of, carrying on a business in Canada, (ii) the
Subscription Receipts (or the Trust Units issuable pursuant thereto) are
"designated insurance property" of the holder for purposes of the Tax Act, or
(iii) the holder, persons with whom the holder does not deal at arm's length
(within the meaning of the Tax Act) or the holder together with such persons
owned 25% or more of the Units at any time during the 60-month period
immediately preceding the disposition.
TAXATION OF HOLDERS OF DEBENTURES RESIDENT IN CANADA
A holder of Debentures that is a corporation, partnership, unit trust or any
trust of which a corporation or a partnership is a beneficiary will be required
to include in computing its income for a taxation year all interest on the
Debentures that accrues to it to the end of the particular taxation year or that
has become receivable or is received by it before the end of that taxation year,
except to the extent that such interest was included in computing the holder's
income for a preceding taxation year.
Any other holder will be required to include in computing income for a taxation
year all interest on the Debentures that is received or receivable by the holder
in that taxation year (depending upon the method regularly followed by the
holder in computing income), except to the extent that the interest was included
in the holder's income for a preceding taxation year. In addition, such holder
will be required to include in computing income for a taxation year any interest
that accrues to the holder on the Debenture to the end of any "anniversary day"
(as defined in the Tax Act) in that year to the extent such interest was not
otherwise included in the holder's income for that year or a preceding year.
A holder of a Debenture who exchanges the Debenture for Units pursuant to the
conversion privilege will be considered to have disposed of the Debenture for
proceeds of disposition equal to the aggregate of the fair market value of the
Units so acquired at the time of the exchange and the amount of any cash
received in lieu of any fractional Unit.
The cost to the holder of the Units so acquired will be equal to their fair
market value at the time of the exchange and must be averaged with the adjusted
cost base of all other Units held at that time as capital property by the holder
for the purpose of calculating the adjusted cost base of each such Unit.
If the Trust redeems a Debenture prior to maturity or repays a Debenture upon
maturity and the holder does not exercise the conversion privilege prior to such
redemption or repayment, the holder will be considered to have disposed of the
Debenture for proceeds of disposition equal to the amount received by the holder
(other than the amount received or deemed to be received as interest) on such
redemption or repayment. Generally a premium paid on redemption or repurchase
prior to maturity will be deemed to be interest. If the holder receives Units on
47
redemption or repayment, the holder will be considered to have received proceeds
of disposition equal to the fair market value of the Units so received and the
amount of any cash received in lieu of any fractional Unit. The cost to the
holder of the Units so received will be equal to their fair market value at the
time of the exchange and must be averaged with the adjusted cost base of all
other Units held at that time as capital property by the holder for the purpose
of calculating the adjusted cost base of each such Unit.
On any disposition or deemed disposition of a Debenture as described above or
otherwise, the holder thereof will generally realize a capital gain (or capital
loss) equal to the amount by which the proceeds of disposition (adjusted as
described below) are greater (or less) than the aggregate of the holder's
adjusted cost base of the Debenture and any reasonable costs of the disposition.
Upon such a disposition or deemed disposition of a Debenture, interest accrued
thereon to the date of disposition or otherwise deemed to be received will be
included in computing the holder's income, except to the extent such amount was
otherwise included in the holder's income, and will be excluded in computing the
holder's proceeds of disposition of the Debenture.
One-half of any capital gain realized by the holder will be included in the
holder's income under the Tax Act for the year of disposition as a taxable
capital gain. One-half of any capital loss realized on a disposition of a
Debenture may be deducted against taxable capital gains realized by the holder
in the year of disposition, in the three preceding taxation years or in any
subsequent taxation year, to the extent and under the circumstances described in
the Tax Act.
A capital gain realized by a holder who is an individual may give rise to a
liability for alternative minimum tax. A holder that is throughout the year a
"Canadian-controlled private corporation" (as defined in the Tax Act) may be
liable to pay an additional refundable tax of 6 2 /3 % on certain investment
income, including interest and taxable capital gains.
TAXATION OF HOLDERS OF DEBENTURES NOT RESIDENT IN CANADA
A holder of a Debenture who is not resident or deemed to be resident in Canada
will generally be subject to Canadian withholding tax at the rate of 25% on
interest paid or credited pursuant to the Debenture, unless such rate is reduced
under the provisions of a tax treaty between Canada and the holder's
jurisdiction of residence. A holder of a Debenture resident in the United States
who is entitled to claim the benefit of the Canada-US Tax Convention will
generally be entitled to have the rate of withholding reduced to 10% of the
amount of any interest paid or credited. Any premium paid on a redemption or
repurchase of Debentures prior to maturity will be deemed to be interest paid or
credited and subject to withholding tax.
A disposition or deemed disposition of a Debenture, whether on conversion,
redemption, or otherwise, will not give rise to any capital gains subject to tax
under the Tax Act to a holder who is not resident or deemed to be resident in
Canada provided that (i) the holder does not hold or use and is not deemed to
hold or use the Debenture in the course of carrying on business in Canada; (ii)
the Debenture is not a "designated insurance property" of the holder for
purposes of the Tax Act; and (iii) the Debenture does not otherwise constitute
"taxable Canadian property" to the holder within the meaning of the Tax Act.
Generally, a Debenture will not otherwise constitute taxable Canadian property
to a non-resident holder at the time of the disposition or deemed disposition
thereof unless (i) the holder, persons with whom the holder does not deal at
arm's length (within the meaning of the Tax Act) or the holder together with
such persons owned 25% or more of the Units at any time during the 60-month
period immediately preceding the disposition, or (ii) the Trust is not a mutual
fund trust for the purposes of the Tax Act on the date of disposition.
If a Debenture is sold or transferred by a non-resident holder to a purchaser
that is resident in Canada at a time when interest has accrued and remains
unpaid on the Debenture, the portion of the purchase or transfer price
attributable to such accrued interest will be deemed to be interest, and there
will be liability on the part of the purchaser to remit withholding tax on such
deemed interest (and any other amounts deemed to be interest) under the Tax Act.
THE COMPUTATION OF THE AMOUNT OF INTEREST WHICH IS DEEMED TO HAVE BEEN PAID ON A
TRANSFER OF DEBENTURES, INCLUDING A CONVERSION, IS COMPLEX, AND IN SOME
CIRCUMSTANCES UNCLEAR. NON-RESIDENT SELLERS OR TRANSFERORS OF DEBENTURES SHOULD
CONSULT THEIR OWN ADVISORS AS TO WHETHER ANY WITHHOLDING OBLIGATION APPLIES.
48
STATUS OF THE TRUST
Based upon representations made by the Manager, in the opinion of Counsel, the
Trust presently qualifies as a "mutual fund trust" as defined by the Tax Act,
and this summary assumes that the Trust will continue to so qualify. Counsel is
advised by the Manager that it is intended that the requirements necessary for
the Trust to qualify as a mutual fund trust will continue to be satisfied so
that the Trust will continue to qualify as a mutual fund trust at all times
throughout its existence. In the event that the Trust were not to so qualify,
the income tax considerations would in some respects be materially different
from those described herein.
TAXATION OF THE TRUST
The Trust is required to include in its income for each taxation year all net
realized capital gains, dividends, accrued interest and amounts accrued in
respect of the Royalty. The Trust may deduct in respect of each taxation year an
amount not exceeding 20% of the total issue expenses of the offering and other
offerings of its Units or debt obligations (subject to proration for a short
taxation year) to the extent that those expenses were not otherwise deductible
in a preceding year, and may also deduct reasonable management and
administration fees incurred by it in the year. The Trust may also deduct, in
computing its income from all sources for a taxation year, an amount not
exceeding 10.00% on a declining balance basis of its cumulative Canadian oil and
gas property expense ("COGPE") account at the end of that year, prorated for
short taxation years.
To the extent that the Trust has any income for a taxation year after the
inclusions and deductions outlined above, the Trust will be permitted to deduct
all amounts of income which are paid or become payable by it to Unitholders in
the year. An amount will be considered payable to a Unitholder in a taxation
year only if it is paid in the year by the Trust or the Unitholder is entitled
in the year to enforce payment of the amount. Counsel is advised that the Trust
intends to deduct, in computing its income, the full amount available for
deduction in each year to the extent of its taxable income for the year
otherwise determined. As a result of such deduction from income, it is expected
that the Trust will not be liable for any material amount of tax under the Tax
Act; however no assurances can be given in this regard.
Under the Trust Indenture, income received by the Trust may be used to finance
cash redemptions of Trust Units. Further, it is possible that income received by
the Trust will be used to repay the principal amount of any outstanding
indebtedness (including the Debentures and the Redemption Notes). Accordingly,
such income so utilized will not be payable to holders of the Trust Units by way
of cash distributions. In such circumstances, such income may be payable to
holders of Trust Units in the form of additional Trust Units ("Reinvested
Units").
TAXATION OF UNITHOLDERS RESIDENT IN CANADA
Each Unitholder is required to include in computing his income for a particular
taxation year the portion of the net income of the Trust that is paid or payable
to the Unitholder in that taxation year, whether or not the amount was actually
paid to the Unitholder in that year. Income of a Unitholder from the Units will
be considered to be income from property and not resource income (or "resource
profits") for purposes of the Tax Act. Any loss of the Trust for purposes of the
Tax Act cannot be allocated to, or treated as a loss of a Unitholder.
Reinvested Units issued to a Unitholder in lieu of a cash distribution will have
a cost equal to the fair market value of such units and will be averaged with
the adjusted cost base of all other Units held by the Unitholder at that time as
capital property in order to determine the adjusted cost base of each Unit.
Any amounts paid or payable by the Trust to a Unitholder in excess of the
Unitholder's share of the income of the Trust and the non-taxable portion of
capital gains made payable to Unitholders in the year will generally not be
included in the income of the Unitholder but will reduce the adjusted cost base
of such Unitholder's Trust Units. To the extent that the adjusted cost base to a
holder of a Trust Unit would otherwise be less than nil, the negative amount
will be deemed to be a capital gain of the Unitholder from the disposition of
the Trust Unit in the year in which the negative amount arises. The non-taxable
portion of capital gains of the Trust that is paid or made payable to the
Unitholder in a year will not be included in computing the Unitholder's income
for the year and will not reduce the adjusted cost base to the Unitholder of the
Trust Units.
49
An actual or deemed disposition (other than in a tax deferred transaction) of
Units by a Unitholder, whether on a redemption or otherwise, will give rise to a
capital gain (or capital loss) equal to the amount by which the proceeds of
disposition (excluding any amount payable by the Trust which represents an
amount that must otherwise be included in the Unitholder's income as described
above) are greater than (or less than) the aggregate of the adjusted cost base
of the Units to the Unitholder plus any reasonable costs associated with the
disposition. One-half of any capital gain realized by a Unitholder on a
disposition of a Unit will be included in the Unitholder's income under the Tax
Act for the year of disposition as a taxable capital gain. One-half of any
capital loss realized on a disposition of a Unit may be deducted against taxable
capital gains realized by the Unitholder in the year of disposition, in the
three preceding taxation years or in any subsequent taxation year, to the extent
and under the circumstances described in the Tax Act.
Taxable capital gains realized by a Unitholder who is an individual may give
rise to alternative minimum tax depending on such Unitholder's circumstances. A
Unitholder that throughout the relevant year is a "Canadian-controlled private
corporation" as defined in the Tax Act may be liable to pay an additional
refundable tax of 6 2/3% on certain investment income, including taxable capital
gains.
A redemption of Units in consideration for cash, Notes or Redemption Notes, as
the case may be, will be a disposition of such Units for proceeds of disposition
equal to the amount of such cash or the fair market value of such Notes or
Redemption Notes, as the case may be, less any portion thereof that is
considered to be a distribution out of the income of the Trust. Redeeming
Unitholders will consequently realize a capital gain, or sustain a capital loss,
depending upon whether such proceeds exceed, or are exceeded by, the adjusted
cost base of the Units so redeemed. The receipt of Notes or Redemption Notes in
substitution for Units may result in a change in the income tax characterization
of distributions. Holders of Notes or Redemption Notes generally will be
required to include in income interest that is received or receivable or that
accrues (depending on the status of the Unitholder as an individual, corporation
or trust) on the Notes or Redemption Notes. The cost to a Unitholder of any
property distributed to a Unitholder by the Trust will be deemed to be equal to
the fair market value of such property at the time of distribution. Unitholders
should consult with their own tax advisors as to the consequences of receiving
Notes or Redemption Notes on a redemption.
TAXATION OF UNITHOLDERS NOT RESIDENT IN CANADA
Any distribution of income of the Trust to a Unitholder who is not resident or
deemed to be resident in Canada will generally be subject to Canadian
withholding tax at the rate of 25%, unless such rate is reduced under the
provisions of a tax treaty between Canada and the Unitholder's jurisdiction of
residence. A Unitholder resident in the United States who is entitled to claim
the benefit of the Canada-US Tax Convention will be entitled to have the rate of
withholding reduced to 15% of the amount of any income distributed. Pursuant to
the Proposed Amendments, the Trust will, beginning in 2005, also be obligated to
withhold on all capital distributions to non-residents at the rate of 15%. Where
a non-resident sustains a capital loss on a disposition of Units such loss may
reduce the non-resident's tax liability in respect of capital distributions.
A disposition or deemed disposition of a Unit, whether on redemption or
otherwise, will not give rise to any capital gains subject to tax under the Tax
Act to a holder who is not resident or deemed to be resident in Canada provided
that the Units are not "taxable Canadian property" of the holder for the
purposes of the Tax Act. Units will not be considered taxable Canadian property
to such a holder unless: (a) the holder holds or uses, or is deemed to hold or
use the Units in the course of carrying on business in Canada; (b) the Units are
"designated insurance property" of the holder for purposes of the Tax Act; (c)
at any time during the 60 month period immediately preceding the disposition of
the Units the holder or persons with whom the holder did not deal at arm's
length or any combination thereof, held 25% or more of the issued Units; or (d)
the Trust is not a mutual fund trust for the purposes of the Tax Act on the date
of disposition.
Interest paid or credited on notes to a non-resident Unitholder who receives
Notes or Redemption Notes on a redemption of Units will be subject to Canadian
withholding tax at a rate of 25%, unless such rate is reduced under the
provisions of an applicable tax treaty. A Unitholder resident in the United
States who is entitled to claim the benefit of the Canada-US Tax Convention
generally will be entitled to have the rate of withholding reduced to 10% of the
amount of such interest.
50
ELIGIBILITY FOR INVESTMENT
Provided the Trust qualifies as a mutual fund trust, the Subscription Receipts,
the Debentures and the Units issuable pursuant to the Subscription Receipts and
on conversion, redemption or maturity of the Debentures will be qualified
investments under the Tax Act for trusts governed by registered retirement
savings plans, registered retirement income funds, deferred profit sharing plans
("DPSPS") (except, in the case of the Debentures, a DPSP to which the Trust has
made a contribution) and registered education savings plans (collectively, the
"PLANS") provided that in the case of Subscription Receipts, the Trust deals at
arm's length with each person who is an annuitant, a beneficiary, an employee or
subscriber under the governing plan of the plan trust for such plans. If the
Trust ceases to qualify as a mutual fund trust, Subscription Receipts, the
Debentures and the Units issuable pursuant to the Subscription Receipts and on
conversion, redemption or maturity of the Debentures will cease to be qualified
investments for Plans. Adverse tax consequences may apply to a Plan, or an
annuitant thereunder, if the Plan acquires or holds property that is not a
qualified investment for the Plan.
Where a Plan receives Notes or Redemption Notes as a result of a redemption of
Units, such Notes or Redemption Notes may not be qualified investments for the
Plan under the Tax Act depending upon the circumstances at the time, and this
could give rise to adverse consequences to the Plan or the annuitant thereunder.
Accordingly, Plans that own Units should consult their own advisors before
deciding to exercise the redemption rights thereunder.
Provided the Trust restricts its holdings in foreign property within the limits
provided in the Tax Act and provided the Trust qualifies as a mutual fund trust,
the Subscription Receipts, the Debentures and the Units issuable pursuant to the
Subscription Receipts and on conversion, redemption or maturity of the
Debentures will not be foreign property for Plans (other than registered
education savings plans), registered pension plans or other persons subject to
tax under Part XI of the Tax Act. Registered education savings plans are not
subject to tax under Part XI of the Tax Act.
See also "Risk Factors - Consequences of Loss of Mutual Fund Trust Status".
RISK FACTORS
An investment in the securities of Advantage is subject to certain risks.
INVESTORS SHOULD CAREFULLY CONSIDER THE RISKS DESCRIBED UNDER "RISK FACTORS",
BEGINNING ON PAGE 50 OF THE AIF AS WELL AS THE FOLLOWING RISK FACTORS:
POSSIBLE FAILURE TO REALIZE ANTICIPATED BENEFITS OF ACQUISITIONS
The Trust is proposing to complete the Acquisition to strengthen its position in
the oil and natural gas industry and to create the opportunity to realize
certain benefits including, among other things, potential cost savings.
Achieving the benefits of these and future acquisitions the Trust may complete
depends in part on successfully consolidating functions and integrating
operations, procedures and personnel in a timely and efficient manner, as well
as the Trust's and AOG's ability to realize the anticipated growth opportunities
and synergies from combining the acquired businesses and operations with those
of the Trust. The integration of acquired businesses requires the dedication of
substantial management effort, time and resources which may divert management's
focus and resources from other strategic opportunities and from operational
matters during this process. The integration process may result in the loss of
key employees and the disruption of ongoing business, customer and employee
relationships that may adversely affect the Trust's ability to achieve the
anticipated benefits of these and future acquisitions.
POSSIBLE FAILURE TO COMPLETE THE ACQUISITION
The Acquisition is subject to normal commercial risk that the Acquisition may
not be completed on the terms negotiated or at all. If closing of the
Acquisition does not take place by the Termination Time, the Escrow Agent and
the Trust will repay to holders of Subscription Receipts, commencing on or
before the second Business Day following the Termination Time, an amount equal
to the issue price therefor plus a PRO RATA share of the interest earned on the
Escrowed Funds and the Debentures will mature on the Initial Maturity Date.
51
OPERATIONAL AND RESERVES RISKS RELATING TO THE ASSETS
The risk factors set forth in the Trust's AIF and in this short form prospectus
relating to the oil and natural gas business and the operations and Reserves of
the Trust apply equally in respect of the Assets that the Trust is acquiring
pursuant to the Acquisition. In particular, the Reserves and recovery
information contained in the Sproule Anadarko Report in respect of the Assets is
only an estimate and the actual production from and ultimate Reserves of those
properties may be greater or less than the estimates contained in such report.
MARKET FOR SECURITIES
There is currently no market through which the Subscription Receipts or the
Debentures may be sold and purchasers may not be able to resell Subscription
Receipts or Debentures purchased under this short form prospectus. There can be
no assurance that an active trading market will develop for the Subscription
Receipts or the Debentures after the offering, or if developed, that such a
market will be sustained at the price level of the offering.
PRIOR RANKING INDEBTEDNESS; ABSENCE OF COVENANT PROTECTION
The Debentures will be subordinate to all Senior Indebtedness and to any
indebtedness of creditors of the Trust. The Debentures will also be effectively
subordinate to claims of creditors of the Trust's subsidiaries except to the
extent the Trust is a creditor of such subsidiaries ranking at least PARI PASSU
with such other creditors.
Other than as described herein, the Indenture will not limit the ability of the
Trust to incur additional debt or liabilities (including Senior Indebtedness) or
to make distributions. The Indenture does not contain any provision specifically
intended to protect holders of the Debentures in the event of a future leveraged
transaction involving the Trust. However, the Trust Indenture, among other
things, restricts the Trust's level of indebtedness, provides operating
investment guidelines, mandates the making of distributions and specifies the
nature of its business.
CHANGES IN ACCOUNTING STANDARDS APPLICABLE TO CONVERTIBLE DEBENTURES
For 2005 and future years, the amounts outstanding for the Debentures will be
classified as liabilities and the interest cost on the Debentures will be
included as interest expense in the determination of net income.
CONSEQUENCES OF LOSS OF MUTUAL FUND TRUST STATUS
If the Trust no longer qualified as a mutual fund trust or such status was
successfully challenged by a relevant tax authority, certain adverse
consequences may arise for the Trust and Unitholders. Some of the significant
consequences of losing mutual fund trust status are as follows:
o The Trust would be taxed on certain types of income distributed to
Unitholders, including income generated by the royalties held by the Trust.
Payment of this tax may have adverse consequences for some Unitholders,
particularly Unitholders that are not residents of Canada and residents of
Canada that are otherwise exempt from Canadian income tax.
o The Trust would cease to be eligible for the capital gains refund mechanism
available under Canadian tax laws if it ceased to be a mutual fund trust.
o Trust Units held by Unitholders that are not residents of Canada would
become taxable Canadian property. These non-resident holders would be
subject to Canadian income tax on any gains realized on a disposition of
Trust Units held by them.
o The Trust Units would not constitute qualified investments for Plans. If,
at the end of any month, one of these Plans hold 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 Plan. An RRSP or RRIF holding non-qualified Trust Units would be
subject to taxation on income attributable to the Trust Units. If an RESP
holds non-qualified Trust Units, it may have its registration revoked by
the Canada Revenue Agency.
52
o The Trust would no longer be exempt from the application of the alternative
minimum tax provisions of the Tax Act.
In addition, the Trust may take certain measures in the future to the extent the
Trust believes them necessary to maintain its status as a mutual fund trust.
These measures could be adverse to certain holders of Trust Units.
KEY MAN INSURANCE
The Trust does not have key man insurance in effect for its senior management.
The contributions of these individuals to the immediate future operations of the
Trust are important and the loss of such individuals could adversely impact on
the Trust's growth and profitability.
MATERIAL CONTRACTS
The material contracts entered into or to be entered into by the Trust in
connection with the offering are as follows:
(a) the Subscription Receipt Agreement referred to under "Details of the
Offering - Subscription Receipts";
(b) the Indenture referred to under "Details of the Offering - Debentures"; and
(c) the Underwriting Agreement referred to under "Plan of Distribution".
Copies of each of the foregoing agreements (in draft form prior to closing in
the case of the Subscription Receipt Agreement and the Indenture) may be
inspected during regular business hours at the offices of the Trust, at 3100,
150 - 6th Avenue S.W., Calgary, Alberta, T2P 3Y7 until the expiry of the 30-day
period following the date of the final short form prospectus.
LEGAL PROCEEDINGS
There are no outstanding legal proceedings material to the Trust to which the
Trust is a party or in respect of which any of its properties are subject, nor
are there any such proceedings known to be contemplated.
AUDITORS, TRANSFER AGENT AND REGISTRAR
The auditors of the Trust are KPMG LLP, Chartered Accountants, Suite 1200, 205 -
5th Avenue S.W., Calgary, Alberta T2P 4B9.
The transfer agent and registrar for the Units, the Subscription Receipts and
Debentures is Computershare Trust Company of Canada at its principal offices in
Calgary, Alberta and Toronto, Ontario.
STATUTORY AND CONTRACTUAL RIGHTS OF RESCISSION AND
STATUTORY RIGHTS OF WITHDRAWAL
Securities legislation in certain of the provinces of Canada provides purchasers
with the right to withdraw from an agreement to purchase securities. This right
may be exercised within two business days after receipt or deemed receipt of a
prospectus and any amendment. In several of the provinces, securities
legislation further provides a purchaser with remedies for rescission or, in
some jurisdictions, damages if the prospectus and any amendment contains a
misrepresentation or is not delivered to the purchaser, provided that the
remedies for rescission or damages are exercised by the purchaser within the
time limit prescribed by the securities legislation of the purchaser's province.
The purchaser should refer to any applicable provisions of the securities
legislation of the province in which the purchaser resides for the particulars
of these rights or consult with a legal advisor.
In addition, original purchasers of Subscription Receipts will have the benefit
of a contractual right of rescission exercisable following the issuance of Units
to such purchasers. See "Details of the Offering - Subscription Receipts".
53
AUDITORS' CONSENT
The Board of Directors of Advantage Oil & Gas Ltd.
We have read the short form prospectus of Advantage Energy Income Fund (the
"TRUST") dated September 3, 2004 relating to the sale and issue of subscription
receipts and extendible convertible unsecured subordinated debentures of the
Trust. We have complied with Canadian Generally Accepted Standards for an
auditor's involvement with offering documents.
We consent to the use, through incorporation by reference in the above mentioned
short form prospectus, of our report to the Unitholders of the Trust on the
consolidated balance sheets of the Trust as at December 31, 2003 and 2002 and
the consolidated statements of income and accumulated income and cash flows for
each of the years then ended. Our report is dated April 7, 2004.
(signed) KPMG LLP
Chartered Accountants
Calgary, Canada
September 3, 2004
AUDITORS' CONSENT
The Board of Directors of Advantage Oil & Gas Ltd.
We have read the short form prospectus of Advantage Energy Income Fund (the
"TRUST") dated September 3, 2004 relating to the sale and issue of subscription
receipts and extendible convertible unsecured subordinated debentures of the
Trust. We have complied with Canadian Generally Accepted Standards for an
auditor's involvement with offering documents.
We consent to the use in the above-mentioned short form prospectus of our report
to the directors of Advantage Oil & Gas Ltd. on the schedule of revenues and
expenses for the Acquired Assets for the year ended December 31, 2003. Our
report is dated August 24, 2004.
(signed) KPMG LLP
Chartered Accountants
Calgary, Canada
September 3, 2004
AUDITORS' CONSENT
We have read the short form prospectus of Advantage Energy Income Fund (the
"TRUST") dated September 3, 2004 relating to the qualification for distribution
of 3,500,000 subscription receipts each representing the right to receive one
trust unit of the Trust, $75,000,000 principal amount of 7.50% extendible
convertible unsecured subordinated debentures of the Trust and $50,000,000
principal amount of 7.75% extendible convertible unsecured subordinated
debentures of the Trust. We have complied with Canadian generally accepted
standards for an auditor's involvement with offering documents.
We consent to the use through incorporation by reference in the above-mentioned
short form prospectus of our report to the directors of MarkWest Resources
Canada Corp. ("MARKWEST") on the balance sheet of MarkWest as at December 31,
2002 and the statements of earnings and retained earnings (deficit) and cash
flows for the year then ended. Our report is dated November 12, 2003.
(signed) PRICEWATERHOUSECOOPERS LLP
Chartered Accountants
Calgary, Canada
September 3, 2004
A-1
SCHEDULE "A"
UNAUDITED PROFORMA CONSOLIDATED FINANCIAL STATEMENTS
A-2
The Board of Directors of Advantage Oil & Gas Ltd.
We have read the accompanying unaudited pro forma consolidated balance sheet of
Advantage Energy Income Fund (the "Fund") as at June 30, 2004 and unaudited pro
forma consolidated statement of operations for the six months then ended and for
the year ended December 31, 2003, and have performed the following procedures:
1. Compared the figures in the columns captioned "Advantage" to the
unaudited consolidated financial statements of the Fund as at June 30,
2004 and for the six months then ended, and the audited consolidated
financial statements of the Fund for the year ended December 31, 2003,
as restated and described in the unaudited consolidated financial
statements as at June 30, 2004 and for the six months then ended,
respectively, and found them to be in agreement.
2. Compared the figures in the columns captioned "Acquired Assets " to the
unaudited schedule of revenues and expenses of the Acquired Assets for
the six months ended June 30, 2004 and the audited schedule of revenues
and expenses of the Acquired Assets for the year ended December 31,
2003.
3. Compared the figures in the columns captioned "MarkWest" to the
unaudited financial statements of MarkWest Resources Canada Corp. as at
September 30, 2003 and for the nine months then ended and to the
unaudited accounting records of MarkWest Resources Canada Corp. for the
period from October 1, 2003 to December 2, 2003 and found them to be in
agreement.
4. Made enquiries of certain officials of the Company who have
responsibility for financial and accounting matters about:
(a) The basis for determination of the pro forma adjustments; and
(b) Whether the pro forma consolidated financial statements comply as
to form in all material respects with the securities regulations
of various provinces.
The officials:
(a) described to us the basis for determination of the pro forma
adjustments, and
(b) stated that the pro forma consolidated financial statements
comply as to form in all material respects with the securities
regulations of various provinces.
5. Read the notes to the pro forma consolidated financial statements, and
found them to be consistent with the basis described to us for
determination of the pro forma adjustments.
6. Recalculated the application of the pro forma adjustments to the
aggregate of the amounts in the other columns as at June 30, 2004 and
for the six months then ended, and for the year ended December 31, 2003,
and found the amounts in the column captioned "Pro Forma Consolidated"
to be arithmetically correct.
A pro forma financial statement is based on management assumptions and
adjustments, which are inherently subjective. The foregoing procedures are
substantially less than either an audit or a review, the objective of which is
the expression of assurance with respect to management's assumptions, the pro
forma adjustments, and the application of the adjustments to the historical
financial information. Accordingly, we express no such assurance. The foregoing
procedures would not necessarily reveal matters of significance to the pro forma
consolidated financial statements, and we therefore make no representation about
the sufficiency of the procedures for the purposes of a reader of such
statements.
(signed) KPMG LLP
Chartered Accountants
Calgary, Canada
September 3, 2004
A-3
ADVANTAGE ENERGY INCOME FUND
PROFORMA CONSOLIDATED BALANCE SHEET
(unaudited)
(thousands of dollars)
Advantage Pro Forma Pro Forma
June 30, 2004 Adjustments Consolidated
------------- ----------- ------------- ------------
ASSETS
Current assets
Accounts receivable $ 35,988 $ - $ 35,988
Property and equipment 532,101 183,198 (note 2a) 715,299
Goodwill 27,773 - 27,773
------------- ------------ --------------
$ 595,862 $ 183,198 $ 779,060
============= ============ ==============
LIABILITIES
Current liabilities
Accounts payable and accrued liabilities $ 41,248 $ - $ 41,248
Cash distributions payable to Unitholders 9,189 - 9,189
Hedging liability 10,224 - 10,224
Bank indebtedness 161,707 (5,910) (note 2a) 155,797
------------- ------------ --------------
222,368 (5,910) 216,458
Capital lease obligation 1,885 - 1,885
Asset retirement obligations 14,477 6,598 (note 2a) 21,075
Future income taxes 68,457 - 68,457
------------- ------------ --------------
307,187 688 307,875
------------- ------------ --------------
UNITHOLDERS' EQUITY
Unitholders' capital 339,279 62,510 (note 2a) 401,789
Convertible debentures 66,396 125,000 (note 2a) 191,396
Contributed surplus 1,036 - 1,036
Accumulated income 88,044 (5,000) (note 2a) 83,044
Accumulated cash distributions (206,080) - (206,080)
------------- ------------ --------------
288,675 182,510 471,185
------------- ------------ --------------
$ 595,862 $ 183,198 $ 779,060
============= ============ ==============
SEE ACCOMPANYING NOTES TO THE UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL
STATEMENTS
A-4
ADVANTAGE ENERGY INCOME FUND
PROFORMA CONSOLIDATED STATEMENT OF OPERATIONS
(thousands of dollars)
(unaudited)
Acquired
Advantage Assets
Six Months Six Months
Ended Ended Pro Forma Pro Forma
June 30, 2004 June 30, 2004 Adjustments Consolidated
------------- ------------- ----------- ----------- ------------
REVENUE
Petroleum and natural gas sales $ 108,017 $ 48,640 $ - $ 156,657
Royalties, net of Alberta
Royality Credit (21,130) (10,997) (32,127)
----------- ----------- ----------- ----------
86,887 37,643 - 124,530
----------- ----------- ----------- ----------
EXPENSES
Operating 16,538 13,130 - 29,668
General and administrative 1,634 - - 1,634
Stock-based compensation 1,036 - - 1,036
Interest 2,677 - (112) (note 2c) 2,565
Management fees 1,055 - 368 (note 2d) 1,423
Non-cash performance incentive 2,900 - - 2,900
Unrealized hedging loss 10,224 - - 10,224
Depletion, depreciation and accretion 41,001 - 19,417 (note 2e) 60,418
----------- ----------- ----------- ----------
77,065 13,130 19,673 109,868
----------- ----------- ----------- ----------
Income before taxes 9,822 24,513 (19,673) 14,662
TAXES
Future income tax recovery (9,542) - - (9,542)
Income and capital taxes 630 - 201 (note 2f) 831
----------- ----------- ----------- ----------
(8,912) - 201 (8,711)
----------- ----------- ----------- ----------
NET INCOME $ 18,734 $ 24,513 $ (19,874) $ 23,373
=========== =========== =========== ==========
Net income per trust unit (note 2g)
Basic $ 0.36
Diluted $ 0.36
SEE ACCOMPANYING NOTES TO THE UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL
STATEMENTS
A-5
ADVANTAGE ENERGY INCOME FUND
PROFORMA CONSOLIDATED STATEMENT OF OPERATIONS
(thousands of dollars)
(unaudited)
MarkWest MarkWest Acquired
Advantage Nine Months October 1 Assets
Year ended Ended to Year Ended MarkWest Assets
December 31 September 30, December 2, December 31, ProForma ProForma
2003 2003 2003 2003 Adjustments Adjustment Consolidated
(restated)
REVENUE
Petroleum and natural $ 166,075 $ 37,695 $ 8,884 $ 104,809 $ - $ - $ 317,463
gas sales
Royalties, net of (28,491) (11,263) (2,144) (24,751) - - (66,649)
Alberta Royalty Credit
137,584 26,432 6,740 80,058 - - 250,814
EXPENSES
Operating 25,618 7,641 1,884 25,310 - - 60,453
General and 3,216 1,787 784 - - - 5,787
administrative
Interest 6,378 1,822 - - (3,592) (284) (note 2c) 4,324
Management fees 1,679 - - - 355 821 (note 2d) 2,855
Non-cash performance 19,592 - - - - - 19,592
incentive
Depletion, depreciation 54,027 15,295 5,144 (1,448) 40,325 (note 2e) 113,343
and accretion
Other - 151 - - - - 151
110,510 26,696 7,812 25,310 (4,685) 40,862 206,505
Income (loss) before taxes 27,074 (264) (1,072) 54,748 4,685 (40,862) 44,309
TAXES
Future income tax recovery (18,203) (7,143) - - - - (25,346)
Income and capital taxes 1,253 431 - - - 411 (note 2f) 2,095
(16,950) (6,712) - - - 411 (23,251)
NET INCOME $ 44,024 $ 6,448 $ (1,072) $ 54,748 $ 4,685 $ (41,273) $ 67,560
Net income per trust unit
(note 2g)
Basic 1.26
Diluted 1.26
SEE ACCOMPANYING NOTES TO THE UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL
STATEMENTS
A-6
ADVANTAGE ENERGY INCOME FUND
NOTES TO PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS
SIX MONTHS ENDED JUNE 30, 2004 AND YEAR ENDED DECEMBER 31, 2003
(UNAUDITED)
1. BASIS OF PRESENTATION
On August 24, 2004 Advantage Oil & Gas Ltd. entered into an agreement to
acquire properties from Anadarko Canada Corporation ("Acquired Assets").
The acquisition is expected to close on September 30, 2004.
On December 2, 2003, Advantage Oil & Gas Ltd. acquired all of the issued
and outstanding shares of MarkWest Resources Canada Corp. ("MarkWest")
for cash consideration of $97 million.
The accompanying unaudited pro forma consolidated financial statements
have been prepared by management of Advantage Energy Income Fund
("Advantage") in accordance with Canadian generally accepted accounting
principles. In the opinion of management the pro forma consolidated
financial statements include all material adjustments necessary for fair
presentation in accordance with Canadian generally accepted accounting
principles.
These pro forma consolidated financial statements may not be indicative
either of the results that actually would have occurred if the events
reflected herein had been in effect on the dates indicated or of the
results which may be obtained in the future.
The unaudited pro forma consolidated balance sheet of Advantage has been
prepared based on the unaudited consolidated balance sheet of Advantage
as at June 30, 2004. The unaudited pro forma consolidated statement of
operations for the six-month period ended June 30, 2004 has been prepared
from:
o The unaudited consolidated statement of operations of Advantage for
the six-month period ended June 30, 2004; and
o The unaudited schedule of revenues and expenses of the Acquired
Assets for the six-month period ended June 30, 2004.
The unaudited pro forma consolidated statement of operations for the year
ended December 31, 2003 has been prepared from:
o The audited consolidated statement of operations of Advantage for
the year ended December 31, 2003;
o The audited schedule of revenues and expenses of the Acquired Assets
for the year ended December 31, 2003; and
o The unaudited statement of earnings of MarkWest for the nine-month
period ended September 30, 2003;
o The unaudited accounting information of MarkWest for the period from
October 1, 2003 to December 1, 2003.
Advantage's financial statements for the year ended December 31, 2003
have been restated to reflect a change in accounting policy with respect
to asset retirement obligations. This change in accounting policy is more
fully described in the unaudited consolidated financial statements of
Advantage as at and for the six-month period ended June 30, 2004. The
restated amounts are reflected in the pro forma consolidated financial
statements.
A-7
2. PRO FORMA TRANSACTIONS AND ASSUMPTIONS
The pro forma consolidated balance sheet gives effect to the following
transactions and assumptions as if they had occurred on June 30, 2004,
while the pro forma consolidated statements of operations for the six
month period ended June 30, 2004 and the year ended December 31, 2003
gives effect to the following transactions and assumptions as if they had
occurred on January 1, 2004 and January 1, 2003 respectively:
(a) The acquisition of the Acquired Assets by Advantage for cash
consideration of $186,000,000 before purchase price adjustments. The
acquisition is being accounted for under the purchase method.
The acquisition is to be financed through the issuance of
$50,000,000 of 7.75% and $75,000,000 of 7.50% extendible convertible
unsecured subordinated debentures and the issuance of 3.5 million
subscription receipts at a price of $18.80 per unit. Associated
underwriters' fees related to convertible debentures of $5,000,000
are included in accumulated income. Excess proceeds over the
purchase price of the Acquired Assets will be used to reduce bank
debt.
(b) The operations from the MarkWest acquisition described in note 1
have been included in the statement of operations of Advantage
beginning December 2, 2003. As a result, the pro forma statement of
operations for the year ended December 31, 2003 has been adjusted to
reflect the operations of MarkWest for the period from January 1 to
December 1, 2003.
(c) Interest expense has been calculated by applying applicable bank
interest rates for the period to the reduction in bank debt due to
the proceeds from the financing exceeding the expected purchase
price.
(d) Management fees have been adjusted to reflect the additional expense
associated with the increase in operating income.
(e) Depletion and depreciation has been determined using the full cost
method of accounting based on combined proved reserves, future
development costs, production volumes and the costs of acquiring the
Acquired Assets and MarkWest. Accretion expense has been adjusted to
reflect the additional asset retirement obligation associated with
the Acquired Assets and MarkWest.
(f) Current taxes have been adjusted to reflect changes in large
corporation tax. It is assumed that any additional future income tax
effect resulting from the pro forma adjustments will be offset by
additional deductions to the Trust.
(g) Pro forma basic per unit amounts are based on the weighted average
number of Advantage units outstanding for the period plus the
additional units issued pursuant to the prospectus. Pro forma
diluted per unit amounts are based on the weighted average number of
diluted Advantage units outstanding for the period plus the
additional units that would be issued on the conversion of the
convertible debentures referenced under 2 (a).
B-1
SCHEDULE "B"
SCHEDULE OF REVENUES AND EXPENSES
B-2
Schedule of Revenues and Expenses of the
ACQUIRED ASSETS
For the year ended December 31, 2003
B-3
AUDITORS' REPORT
To the Board of Directors of Advantage Oil and Gas Ltd.
At the request of Advantage Energy Income Fund we have audited the schedule of
revenues and expenses of the Acquired Assets for the year ended December 31,
2003. This financial information is the responsibility of management. Our
responsibility is to express an opinion on this financial information based on
our audit.
We conducted our audit in accordance with Canadian generally accepted auditing
standards. Those standards require that we plan and perform an audit to obtain
reasonable assurance whether the financial information is free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial information. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall presentation of the financial
information.
In our opinion, this financial information presents fairly, in all material
respects, the revenues and expenses of the Acquired Assets for the year ended
December 31, 2003.
(signed) KPMG LLP
Chartered Accountants
Calgary, Canada
August 24, 2004
B-4
ADVANTAGE ENERGY INCOME FUND
Schedule of Revenues and Expenses of the Acquired Assets
- -------------------------------------------------------------------------------------------------------------------
Six-month period
ended June 30, Year ended
---------------------------------- December 31,
2004 2003 2003
- -------------------------------------------------------------------------------------------------------------------
(unaudited)
Revenue $ 48,639,651 $ 57,561,573 $ 104,809,129
Royalties (10,996,552) (13,768,361) (24,751,107)
- -------------------------------------------------------------------------------------------------------------------
37,643,099 43,793,212 80,058,022
Operating Costs (13,129,975) (12,139,884) (25,309,551)
- -------------------------------------------------------------------------------------------------------------------
Operating Income $ 24,513,124 $ 31,653,328 $ 54,748,471
- -------------------------------------------------------------------------------------------------------------------
See accompanying notes to schedule of revenues and expenses.
B-5
ADVANTAGE ENERGY INCOME FUND
Notes to Schedule of Revenues and Expenses of the Acquired Assets
Year ended December 31, 2003
(Information for the six months ended June 30, 2004 is unaudited)
- --------------------------------------------------------------------------------
1. BASIS OF PRESENTATION:
Pursuant to an agreement dated August 24, 2004, Advantage Energy Income
Fund ("Advantage"), through its wholly-owned subsidiary, Advantage Oil &
Gas Ltd., acquired interests in certain petroleum and natural gas
properties ("Acquired Assets") from Anadarko Canada Corporation
("Anadarko").
The schedule of revenue and expenses for selected properties includes the
operations of the acquired properties of Anadarko.
The schedule of revenue and expenses for the acquired properties includes
only revenues, royalties and operating costs applicable to the working
interest of Anadarko for the acquired properties.
The schedule of revenue and expenses for selected properties does not
include any provision for the depletion and depreciation, site restoration,
future capital costs, impairment of unevaluated properties, general and
administrative costs and income taxes for the selected properties as these
amounts are based on the consolidated operations of Anadarko of which the
selected properties form only a part of.
2. SIGNIFICANT ACCOUNTING POLICIES:
(a) Revenue:
Revenue from the sale of oil, natural gas liquids and natural gas is
recognized at the time the product is produced and sold. Pricing used in
the schedule of revenues and expenses is the current market price net of
transportation costs.
(b) Royalties:
Royalties are recorded at the time the product is produced and sold.
Royalties are calculated in accordance with the applicable regulations or
the terms of individual royalty agreements.
(c) Operating costs:
Operating costs include amounts incurred to bring the oil and natural gas
to the surface, gather, process, treat and store the product in the field.
C-1
SCHEDULE "C"
UNAUDITED FINANCIAL STATEMENTS OF MARKWEST RESOURCES CANADA CORP.
FOR THE NINE-MONTH PERIOD ENDED SEPTEMBER 30, 2003
C-2
Financial Statements of
MARKWEST RESOURCES
CANADA CORP.
Nine months ended September 30, 2003
C-3
MARKWEST RESOURCES CANADA CORP.
Balance Sheet
- -------------------------------------------------------------------------------------------------------------------
September 30, December 31,
2003 2002
- -------------------------------------------------------------------------------------------------------------------
(unaudited)
Assets
Current assets:
Cash $ - $ 3,345,099
Accounts receivable 7,581,616 5,238,507
Prepaids and other current assets 456,463 574,714
- -------------------------------------------------------------------------------------------------------------------
8,038,079 9,158,320
Deferred financing costs 168,195 319,571
Property, plant and equipment (note 3) 156,396,341 142,334,142
- -------------------------------------------------------------------------------------------------------------------
$ 164,602,615 $ 151,812,033
- -------------------------------------------------------------------------------------------------------------------
Liabilities and Shareholders' Equity
Current liabilities:
Cash, less outstanding cheques $ 2,969,853 $ -
Accounts payable and accrued liabilities 14,651,559 9,948,858
Current portion of capital lease obligations (note 5) 312,499 -
Advances from parent (note 6) 51,210,654 16,265,710
Current portion of long-term debt (note 4) 21,000,000 -
- -------------------------------------------------------------------------------------------------------------------
90,144,565 26,214,568
Long-term debt (note 4) - 53,000,000
Capital lease obligations (note 5) 2,129,543 -
Provision for future site restoration (note 7) 1,585,203 1,159,212
Future income tax 38,217,486 45,360,728
- -------------------------------------------------------------------------------------------------------------------
41,932,232 125,734,508
Shareholders' equity:
Share capital (note 8) 28,542,263 28,542,263
Retained Earnings (deficit) 3,983,555 (2,464,738)
- -------------------------------------------------------------------------------------------------------------------
32,525,818 26,077,525
Commitments (note 9)
Subsequent events (note 11)
- -------------------------------------------------------------------------------------------------------------------
$ 164,602,615 $ 151,812,033
- -------------------------------------------------------------------------------------------------------------------
See accompanying notes to financial statements.
C-4
MARKWEST RESOURCES CANADA CORP.
Statement of Earnings and Retained Earnings (deficit)
- -------------------------------------------------------------------------------------------------------------------
Nine months
ended Year ended
September 30, December 31,
2003 2002
- -------------------------------------------------------------------------------------------------------------------
(unaudited)
Revenue:
Petroleum and natural gas revenue $ 37,649,367 $ 41,747,575
Royalties, net of Alberta Royalty Tax Credit (11,262,603) (10,026,021)
- -------------------------------------------------------------------------------------------------------------------
26,386,764 31,721,554
Other income 46,237 33,967
- -------------------------------------------------------------------------------------------------------------------
26,433,001 31,755,521
Expenses:
Production 7,641,336 7,244,966
General and administrative 1,787,330 2,629,180
Depletion, depreciation, amortization and site restoration 15,295,368 21,248,048
Interest expense 1,821,428 1,596,929
Other 151,375 1,079,330
- -------------------------------------------------------------------------------------------------------------------
26,696,837 33,798,453
- -------------------------------------------------------------------------------------------------------------------
Loss before income taxes (263,836) (2,042,932)
Income taxes:
Current tax expense (recovery) 431,113 (160,291)
Future tax recovery (7,143,242) (2,445,256)
- -------------------------------------------------------------------------------------------------------------------
(6,712,129) (2,605,547)
- -------------------------------------------------------------------------------------------------------------------
Net earnings for the period 6,448,293 562,615
Deficit, beginning of period (2,464,738) (3,027,353)
- -------------------------------------------------------------------------------------------------------------------
Retained earnings (deficit), end of period $ 3,983,555 $ (2,464,738)
- -------------------------------------------------------------------------------------------------------------------
See accompanying notes to financial statements.
C-5
MARKWEST RESOURCES CANADA CORP.
Statement of Cash Flows
- -------------------------------------------------------------------------------------------------------------------
Nine months
ended Year ended
September 30, December 31,
2003 2002
- -------------------------------------------------------------------------------------------------------------------
(unaudited)
Cash provided by (used in):
Net earnings for the period $ 6,448,293 $ 562,615
Items not affecting cash:
Depreciation, depletion and amortization and site
restoration 15,295,368 21,248,048
Future income taxes (7,143,242) (2,445,256)
Amortization of deferred financing costs 151,376 1,079,330
- -------------------------------------------------------------------------------------------------------------------
14,751,795 20,444,737
Net change in non-cash working capital items 2,267,667 2,265,829
- -------------------------------------------------------------------------------------------------------------------
17,019,462 22,710,566
Investing activities:
Property, plant and equipment additions (28,776,848) (25,490,063)
Proceeds on disposition of property, plant and equipment 2,579,439 -
Abandonment expenditures (103,183) (5,151)
Change in capital accrual 210,176 (1,637,235)
- -------------------------------------------------------------------------------------------------------------------
(26,090,416) (27,132,449)
Financing activities:
Repayment of long-term debt (32,000,000) -
Advances from parent 34,944,944 5,646,530
Decrease in capital lease obligations (188,942) -
- -------------------------------------------------------------------------------------------------------------------
2,756,002 5,646,530
- -------------------------------------------------------------------------------------------------------------------
(Decrease) increase in cash (6,314,952) 1,224,647
Cash, beginning of period 3,345,099 2,120,452
- -------------------------------------------------------------------------------------------------------------------
Cash, end of period $ (2,969,853) $ 3,345,099
- -------------------------------------------------------------------------------------------------------------------
Supplementary information:
- -------------------------------------------------------------------------------------------------------------------
Interest paid on long-term debt $ 1,726,896 $ 2,692,095
Income taxes paid (received) (199,369) (500,783)
Non-cash items:
Assets acquired under capital lease 2,630,984 -
- -------------------------------------------------------------------------------------------------------------------
See accompanying notes to financial statements.
C-6
MARKWEST RESOURCES CANADA CORP.
Notes to Financial Statements
Nine months ended September 30, 2003
- --------------------------------------------------------------------------------
NATURE OF OPERATIONS:
MarkWest Resources Canada Corp. (the "Company") explores for and produces
oil and natural gas and is a wholly owned subsidiary of MarkWest
Hydrocarbons, Inc.
1. SIGNIFICANT ACCOUNTING POLICIES:
(a) Cash:
Cash consists of the balance with the bank, cash on hand and
short-term investments with a maturity of three months or less when
purchased.
(b) Property, plant and equipment:
The Company follows the full cost method of accounting for oil and
gas operations, whereby all costs of exploring for and developing oil
and gas properties and related reserves are capitalized. Such costs
include land acquisition costs, cost of drilling both productive and
non-productive wells, and geological and geophysical expenses and
related overhead. Proceeds of disposition are applied against the
cost pools with no gain or loss recognized expect where the
disposition results in a significant change in the rate of depletion.
The carrying value is limited to the recoverable amount as determined
by estimating the future net revenues from proven properties (based
on period end prices and costs) and the value of unproven properties
(at the lower of cost and net realizable value) less estimated future
site restoration costs, general and administrative expenses and
financing costs.
Capitalize costs, excluding costs relating to unproven properties,
are depleted using the unit-of-production method based on estimated
proven reserves of oil and gas before royalties as determined by
independent petroleum engineers. For purposes of the depletion
calculation, oil and natural gas reserves and production are
converted to a common unit-of-measure. Other assets are depreciated
on a straight-line basis over the estimated service lives of the
assets.
Assets under capital lease are recorded at the present value of the
lease payments at the inception of the lease.
(c) Provision for future site restoration:
The Company estimates its future site restoration and abandonment
costs for its oil and gas properties. The costs represent
management's best estimate of the future restoration and abandonment
costs based upon current legislation and industry practices. The
total estimated costs are being provided for on a unit-of-production
basis. The annual provision is included in amortization expense and
actual site restoration costs are charged to the liability account as
incurred.
C-7
MARKWEST RESOURCES CANADA CORP.
Notes to Financial Statements
Nine months ended September 30, 2003
- --------------------------------------------------------------------------------
1. SIGNIFICANT ACCOUNTING POLICIES (CONTINUED):
(d) Joint ventures:
Certain of the Company's activities are conducted jointly with other
parties. These financial statements reflect the Company's
proportionate interest in such activities.
(e) Financial instruments:
The Company's financial instruments are comprised of accounts
receivable, accounts payable and accrued liabilities, advances from
parent, long term debt and commodity instruments (note 10). The fair
value of the financial instruments approximates their carrying
amount. A significant portion of the Company's accounts receivable is
from oil and gas companies. Although collection of these receivables
could be influenced by economic factors affecting this industry, the
risk of significant loss is considered remote.
(f) Income taxes:
The Company follows the liability method of accounting for income
taxes. Under this method, the Company records future income taxes for
the affect of any differences between the accounting and the income
tax basis of an asset or liability using income tax rates
substantially enacted on the balance sheet date. The effect of a
change in income tax rates on the future income tax assets and
liabilities is recognized in income in the period of the change.
(g) Measurement uncertainty:
The amount recorded for depletion and depreciation of capital assets
and the provision for future site restoration costs are based on
estimates. The ceiling test calculation is based on estimates of
proven reserves, production rates, oil and gas prices, future costs
and other relevant assumptions. By their nature, these estimates are
subject to measurement uncertainty and the effect on the financial
statements from change in such estimates in future periods could be
significant.
3. PROPERTY, PLANT AND EQUIPMENT:
--------------------------------------------------------------------------------------------------------------
Accumulated Net book
September 30, 2003 Cost depreciation value
--------------------------------------------------------------------------------------------------------------
Petroleum and natural gas properties
and equipment $ 197,741,457 $ 44,074,741 $ 153,666,716
Furniture and equipment 370,806 206,392 164,414
Assets under capital lease 2,630,984 65,773 2,565,211
--------------------------------------------------------------------------------------------------------------
$ 200,743,247 $ 44,346,906 $ 156,396,341
--------------------------------------------------------------------------------------------------------------
C-8
MARKWEST RESOURCES CANADA CORP.
Notes to Financial Statements
Nine months ended September 30, 2003
- --------------------------------------------------------------------------------
3. PROPERTY, PLANT AND EQUIPMENT:
- -------------------------------------------------------------------------------------------------------------------
Accumulated Net book
Cost depreciation value
- -------------------------------------------------------------------------------------------------------------------
Petroleum and natural gas properties
and equipment $ 171,592,526 $ 29,430,588 $ 142,161,938
Furniture and equipment 322,328 150,124 172,204
- -------------------------------------------------------------------------------------------------------------------
$ 171,914,854 $ 29,580,712 $ 142,334,142
- -------------------------------------------------------------------------------------------------------------------
Costs for unproven properties of $41,427,431 at September 30, 2003 and
$48,420,924 at December 31, 2002 have been excluded from the depletion
calculation. During the nine month period ended September 30, 2003 and the
year ended December 31, 2002, the Company capitalized no overhead costs
related to exploration and development activities and capitalized
$1,409,182 and $2,251,374 of interest expense respectively.
Month-end prices of $33.51 (December 31, 2002 - $33.49/bbl) for oil and
$5.69/mcf (December 31, 2002 - $5.66/mcf) for gas resulted in no ceiling
test deficiency at September 30, 2003 or December 31, 2002.
4. LONG-TERM DEBT:
On May, 24, 2002, the Company amended its credit agreement ("Canadian
Credit Facility") with various financial institutions for an amount of
US$35,000,000. This facility is a component of the overall debt facility of
the parent company, MarkWest Hydrocarbons, Inc. ("Parent") of Denver,
Colorado. The overall amount of the Parent's facility ("Credit Facility")
is US$60,000,000.
Available borrowings under the Credit Facility are determined by a
borrowing base that is determined by the value of the proved reserves of
oil and as owned by the Parent (directly or indirectly through
subsidiaries, including MarkWest Resources Canada Corp.), and also on the
working capital of the Parent, the level of which is determined by NGL
product accounts receivable and inventory levels. The borrowing base on
proved reserves is calculated semi-annually, while borrowing base on
working capital is calculated monthly. Actual borrowing limits for the
Credit Facility may be less than US$60,000,000, depending on proved
reserves, working capital levels, and financial covenants. The Company had
outstanding borrowings of C$21,000,000, or approximately US$15,551,000, at
September 30, 2003 and C$53,000,000, or approximately US$33,758,000, at
December 31, 2002 of the US$35,000,000 available.
MARKWEST RESOURCES CANADA CORP.
Notes to Financial Statements
Nine months ended September 30, 2003
- --------------------------------------------------------------------------------
4. LONG-TERM DEBT (CONTINUED):
The Canadian Credit Facility permits MarkWest Resources Canada Corp. to
borrow money at a rate equal to the London Interbank Offered Rate ("LIBOR")
plus an applicable margin of between 1.75% and 2.75% based on a certain
leverage ratio, which is determined as the ratio of total funded debt to
EBITDA. Funds can also be borrowed at the Canadian Prime Rate plus an
applicable margin of between 0.375% and 1.375%, based on the leverage
ratio. There is a fee on the unused portion of the Canadian Credit Facility
of between 0.25% and 0.50% based on the leverage ratio. The weighted
average interest rate was 5.64% for the period ended September 30, 2003 and
5.02% for the year ended December 31, 2002.
The Credit Facility is a revolving facility, with a maturity and expiry
date of August 9, 2004. The entire outstanding principal balance is due in
full on this date. The Credit Facility is collateralized by a first lien on
substantially all the Company's assets.
5. CAPITAL LEASE OBLIGATIONS:
Future minimum annual lease payments at September 30, 2003 (December 31,
2002 - $nil) consists of the following:
---------------------------------------------------------------------------
September 30,
2003
---------------------------------------------------------------------------
2004 $ 443,220
2005 443,220
2006 443,220
2007 and thereafter 1,474,395
---------------------------------------------------------------------------
2,804,055
Less amounts representing interest at 5.5% 362,013
---------------------------------------------------------------------------
2,442,042
Current portion 312,499
---------------------------------------------------------------------------
$ 2,129,543
---------------------------------------------------------------------------
Interest of $69,603 relating to capital lease obligations is included in
interest expense for the period ended September 30, 2003.
6. ADVANCES FROM PARENT:
The advances from parent bear interest at 7% per annum, are due on demand
and are unsecured.
C-10
MARKWEST RESOURCES CANADA CORP.
Notes to Financial Statements
Nine months ended September 30, 2003
- --------------------------------------------------------------------------------
7. PROVISION FOR FUTURE SITE RESTORATION:
--------------------------------------------------------------------------
September 30, December 31,
2003 2002
--------------------------------------------------------------------------
Balance, beginning of period $ 1,159,212 $ 222,958
Current period provisions 529,174 941,405
Current period expenditures (103,183) (5,151)
--------------------------------------------------------------------------
$ 1,585,203 $ 1,159,212
--------------------------------------------------------------------------
The provision for future site restoration costs is recorded in the
statement of income as component of depletion, depreciation and
amortization expense and on the balance sheet as a long-term liability. The
total estimated liability is $5,000,000 at September 30, 2003 (December 31,
2002 - $3,960,000).
8. SHARE CAPITAL:
(a) Authorized:
Unlimited number of common shares without nominal or par value
(b) Issued:
--------------------------------------------------------------------------------------------------------
Number of
As at September 30, 2003 and December 31, 2002 shares Amount
--------------------------------------------------------------------------------------------------------
Class A common shares 26,933,363 $ 28,542,263
---------------------------------------------------------------------------------------------------------
9. COMMITMENTS:
The Company has committed to certain payments for office space over the
next four years as follows:
-------------------------------------------------------------------------
September 30,
2003
-------------------------------------------------------------------------
2004 $ 188,352
2005 188,352
2006 188,352
2007 125,568
-------------------------------------------------------------------------
C-11
MARKWEST RESOURCES CANADA CORP.
Notes to Financial Statements
Nine months ended September 30, 2003
- --------------------------------------------------------------------------------
10. COMMODITY INSTRUMENTS:
Derivative commodity instruments may be used from time to time by the
Company to manage its exposure to price risks relating to natural gas
prices. The Company's policy is to not utilize derivative commodity
instruments for trading or speculative purposes.
Realized gains and losses on derivative instruments used as hedges are
recognized in income in the period that the hedge is settled.
The Company had the following natural gas hedge agreements outstanding at
September 30, 2003 and December 31, 2002:
-----------------------------------------------------------------------------------------------------------
Volume Price
Type (gj/day) ($/gj) Term
-----------------------------------------------------------------------------------------------------------
Fixed price 2,462 4.62 January 1 2003 to December 31, 2003
Fixed price 2,462 4.82 January 1, 2003 to December 31, 2003
Fixed price 1,758 4.65 January 1, 2004 to December 31, 2004
Fixed price 1,758 4.87 January 1, 2004 to December 31, 2004
Costless collar 2,462 4.09 - 5.24 January 1, 2003 to December 31, 2003
Costless collar 1,758 4.10 - 5.25 January 1, 2004 to December 31, 2004
Basis swap 6,330 Nymex/AECO April 1, 2003 to October 31, 2003
Basis swap 5,275 Nymex/AECO April 1, 2003 to October 31, 2003
-----------------------------------------------------------------------------------------------------------
The unrealized loss on these contracts was $3,271,534 as at September 30,
2003 and $4,117,199 as at December 31, 2002.
Subsequent to September 30, 2003, the Company entered into one natural gas
hedge for the period November 1, 2003 to March 31, 2004 totalling 2,109
gj/day with a price based on Nymex/AECO.
11. SUBSEQUENT EVENTS:
Effective October 1, 2003, all of the shares of the Company were purchased
by Advantage Energy Income Fund for total consideration of $102.5 million.
D-1
CERTIFICATE OF THE TRUST
Dated: September 3, 2004
This short form prospectus, together with the documents incorporated herein by
reference, constitutes full, true and plain disclosure of all material facts
relating to the securities offered by this short form prospectus as required by
the securities legislation of each of the Provinces of Canada. For the purpose
of the Province of Quebec, this simplified prospectus, as supplemented by the
permanent information record, contains no misrepresentation that is likely to
affect the value or the market price of the securities to be distributed.
ADVANTAGE ENERGY INCOME FUND
BY: ADVANTAGE OIL & GAS LTD.
(signed) Kelly I. Drader (signed) Peter A. Hanrahan
President and Chief Executive Officer Vice President, Finance and Chief Financial Officer
ON BEHALF OF THE BOARD OF DIRECTORS
(signed) Ronald A. McIntosh (signed) Rodger A. Tourigny
Director Director
D-2
CERTIFICATE OF THE UNDERWRITERS
Dated: September 3, 2004
To the best of our knowledge, information and belief, this short form
prospectus, together with the documents incorporated herein by reference,
constitutes full, true and plain disclosure of all material facts relating to
the securities offered by this short form prospectus as required by the
securities legislation of each of the Provinces of Canada. For the purpose of
the Province of Quebec, to our knowledge, this simplified prospectus, as
supplemented by the permanent information record, contains no misrepresentation
that is likely to affect the value or the market price of the securities to be
distributed.
SCOTIA CAPITAL INC.
By: (signed) Steven Kroeker
BMO NESBITT BURNS INC. NATIONAL BANK FINANCIAL INC.
By: (signed) Jason J. Zabinsky By: (signed) David M. Vetters
RBC DOMINION SECURITIES INC.
By: (signed) Craig E. Kelly
CIBC WORLD MARKETS INC.
By: (signed) Arthur N. Korpach
FIRSTENERGY CAPITAL CORP. RAYMOND JAMES LTD.
By: (signed) Nicholas J. Johnson By: (signed) Edward J. Bereznicki