EXHIBIT 99.1
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HARVEST ENERGY TRUST
2004 RENEWAL ANNUAL INFORMATION FORM
MARCH 30, 2005
TABLE OF CONTENTS
Page
SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS...........................1
SUPPLEMENTAL DISCLOSURE.....................................................2
GLOSSARY OF TERMS...........................................................3
ABBREVIATIONS..............................................................11
CONVERSIONS................................................................11
DATE OF INFORMATION........................................................11
HARVEST ENERGY TRUST.......................................................12
GENERAL DEVELOPMENT OF THE BUSINESS........................................12
RECENT DEVELOPMENTS........................................................16
STATEMENT OF RESERVES DATA.................................................16
OTHER OIL AND NATURAL GAS INFORMATION......................................26
DESCRIPTION OF THE TRUST...................................................37
INFORMATION RESPECTING THE CORPORATION.....................................43
DIRECTORS AND OFFICERS OF THE CORPORATION..................................47
SHARE CAPITAL OF THE CORPORATION...........................................52
DESCRIPTION OF CAPITAL STRUCTURE...........................................52
TRUST INDENTURE............................................................53
TRUST UNIT INCENTIVE PLAN..................................................59
DRIP PLAN..................................................................60
CONFLICTS OF INTEREST......................................................60
AUDIT COMMITTEE INFORMATION................................................61
PROMOTERS..................................................................62
LEGAL PROCEEDINGS..........................................................62
RECORD OF CASH DISTRIBUTIONS...............................................62
ESCROWED SECURITIES........................................................63
INTERESTS OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS................63
TRANSFER AGENT AND REGISTRAR...............................................63
MATERIAL CONTRACTS.........................................................63
INTERESTS OF EXPERTS.......................................................64
MARKET FOR SECURITIES......................................................64
RISK FACTORS...............................................................65
ADDITIONAL INFORMATION.....................................................72
APPENDIX A - REPORT OF MANAGEMENT AND DIRECTORS ON RESERVES DATA AND OTHER
INFORMATION
APPENDIX B - REPORT ON RESERVES DATA
APPENDIX C - FINANCIAL STATEMENTS
APPENDIX D - HARVEST OPERATIONS CORP. AUDIT COMMITTEE MANDATE AND TERMS OF
REFERENCE
1
SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS
This Annual Information Form contains forward-looking statements. These
statements are subject to certain risks and uncertainties that could cause
actual results to differ materially from those included in the forward-looking
statements. The words "believe," "expect," "intend," "estimate" or "anticipate"
and similar expressions, as well as future or conditional verbs such as "will,"
"should," "would," and "could" often identify forward-looking statements.
Specific forward-looking statements contained in this Annual Information Form
include, among others, statements regarding our:
o expected financial performance in future periods;
o expected increases in revenue attributable to development and
production activities;
o estimated capital expenditures for fiscal 2005 and subsequent
periods;
o competitive advantages and ability to compete successfully;
o intention to continue adding value through drilling and exploitation
activities;
o emphasis on having a low cost structure;
o intention to retain a portion of our cash flows after distributions
to repay indebtedness and invest in further development of our
properties;
o reserve estimates and estimates of the present value of our future
net cash flows;
o methods of raising capital for exploitation and development of
reserves;
o factors upon which we will decide whether or not to undertake a
development or exploitation project;
o plans to make acquisitions and expected synergies from acquisitions
made;
o expectations regarding the development and production potential of
our properties; and
o treatment under government regulatory regimes.
With respect to forward-looking statements contained in this Annual Information
Form, we have made assumptions regarding, among other things:
o future oil and natural gas prices and differentials between light,
medium and heavy oil prices;
o the cost of expanding our property holdings;
o our ability to obtain equipment in a timely manner to carry out
development activities;
o our ability to market oil and natural gas successfully to current
and new customers;
o the impact of increasing competition;
o our ability to obtain financing on acceptable terms; and
o our ability to add production and reserves through our development
and exploitation activities.
Some of the risks that could affect our future results and could cause results
to differ materially from those expressed in our forward-looking statements
include:
o the volatility of oil and natural gas prices, including the
differential between the price of light, medium and heavy oil;
o the uncertainty of estimates of oil and natural gas reserves;
o the impact of competition;
o difficulties encountered during the drilling for and production of
oil and natural gas;
o difficulties encountered in delivering oil and natural gas to
commercial markets;
o foreign currency fluctuations;
o the uncertainty of our ability to attract capital;
o changes in, or the introduction of new, government regulations
relating to the oil and natural gas business;
o costs associated with developing and producing oil and natural gas;
o compliance with environmental regulations;
o liabilities stemming from accidental damage to the environment;
o loss of the services of any of our senior management or directors;
and
o adverse changes in the economy generally.
2
The information contained in this Annual Information Form, including the
information provided under the heading "Operational and Other Business Risks"
identifies additional factors that could affect our operating results and
performance. We urge you to carefully consider these factors.
Our forward-looking statements are expressly qualified in their entirety by this
cautionary statement. Our forward-looking statements are only made as of the
date of this Annual Information Form and we undertake no obligation to publicly
update these forward-looking statements to reflect new information, subsequent
events or otherwise.
SUPPLEMENTAL DISCLOSURE
Distributable cash and cash available for distribution and cash-on-cash yield
are not recognized generally accepted accounting principles. Management believes
that in addition to net income and net income per Trust Unit, distributable cash
and cash available for distribution are useful supplemental measures as they
provide investors with information on cash available for distribution.
Cash-on-cash yield is a useful and widely used supplemental measure that
provides investors with information on cash actually distributed relative to
trading price. Investors are cautioned that distributable cash, cash available
for distribution and cash-on-cash yield should not be construed as an alternate
to net income as determined by Canadian generally accepted accounting
principles. Investors are also cautioned that cash-on-cash yield represents a
blend of return of investors' initial investment and a return on investors'
initial investment and is not comparable to traditional yield on debt
instruments where investors are entitled to full return of the principal amount
of debt on maturity in addition to a return on investment through interest
payments.
3
GLOSSARY OF TERMS
In this Annual Information Form, the following terms shall have the meanings set
forth below, unless otherwise indicated.
"ABCA" means the Business Corporations Act (Alberta), together with any or all
regulations promulgated thereunder, as amended from time to time.
"Administration Agreement" means the agreement dated September 27, 2002 between
the Trustee and the Corporation pursuant to which the Corporation provides
certain administrative and advisory services in connection with the Trust. See
"Description of the Trust" and "Information Respecting the Corporation".
"Affiliate" means, with respect to the relationship between corporations, that
one of them is controlled by the other or that both of them are controlled by
the same Person and for this purpose a corporation shall be deemed to be
controlled by the Person who owns or effectively controls, other than by way of
security only, sufficient voting shares of the corporation (whether directly
through the ownership of shares of the corporation or indirectly through the
ownership of shares of another corporation or otherwise) to elect the majority
of its board of directors.
"ARTC" means the Alberta Royalty Tax Credit, an Alberta provincial government
program under which, in certain circumstances, tax credits may be provided
against royalties on oil and natural gas production payable to the Province of
Alberta.
"Board of Directors" or "Harvest Board" means the board of directors of the
Corporation.
"Bridge Agreements" means, collectively, the Bridge Notes and the Equity Bridge
Notes.
"Bridge Lenders" means, collectively, Caribou and the Chairman of the
Corporation.
"Bridge Notes" means, collectively, the bridge notes dated September 29, 2003
between the Trust and each of the Bridge Lenders providing for advances of up to
$30 million to the Trust to assist with the payout of the then existing credit
facility and the payment of the Deferred Purchase Price Obligation as a result
of the acquisition of the Southeast Saskatchewan Properties.
"Business Day" means a day, other than a Saturday, Sunday or statutory holiday
in the Province of Alberta or any other day on which banks in Calgary, Alberta
are not open for business.
"Capital Fund" means the cumulative amount of funds that the Trust retains from
Cash Available For Distributions to finance future acquisitions and development
of properties. See "Description of the Trust - Capital Fund".
"Caribou" means Caribou Capital Corp.
"Cash Available For Distribution" means, for any particular period, all amounts
available for distribution during any applicable period by the Trust to holders
of Trust Units prior to any obligation pursuant to the DPPO and any retention by
the Trust for the Capital Fund. See "Description of the Trust - Cash Available
For Distribution".
"COGPE" means Canadian oil and natural gas property expense, as defined in the
Tax Act.
"COGE Handbook" means the Canadian Oil and Gas Evaluation Handbook prepared
jointly by the Society of Petroleum Evaluation Engineers (Calgary chapter) and
the Canadian Institute of Mining, Metallurgy & Petroleum;
"Corporation" means, as the context requires, the Trust's wholly-owned
subsidiary, Harvest Operations Corp., a corporation amalgamated under the
Business Corporations Act (Alberta) on June 30, 2004 and on January 1, 2004 and,
prior to January 1, 2004, a corporation incorporated under the Business
Corporations Act (Alberta), or its wholly-owned subsidiaries;
4
"Corporation" means Harvest Operations Corp., a wholly-owned subsidiary of the
Trust, and its wholly-owned subsidiaries.
"Current Bank Facility" means the credit facility provided by the Current
Lenders as more fully described under "Information Respecting the Corporation -
Borrowing by the Corporation".
"Current Lenders" means a syndicate of lenders to the Corporation pursuant to
the Current Bank Facility.
"Debenture Indenture" means the trust indenture dated January 29, 2004 made
among the Trust, the Corporation and the Debenture Trustee, as trustee.
"Debenture Trustee" means the trustee of the Debentures Series 1 and Debentures
Series 2, Valiant Trust Company.
"Debentures Series 1" means the 9% convertible unsecured subordinated debentures
of the Trust due May 31, 2009.
"Debentures Series 2" means the 8% convertible unsecured subordinated debentures
of the Trust due September 30, 2009.
"Deferred Purchase Price Obligation" or "DPPO" means, collectively, the ongoing
obligation of the Trust to pay to the Corporation, HST and HBT2, to the extent
of the Trust's available funds, an amount up to 99% of the cost of, including
any amount borrowed to acquire, any Canadian resource property acquired by the
Corporation, HST or HBT2, and the cost of, including any amount borrowed to
fund, certain designated capital expenditures in relation to the Properties.
"Direct Royalties" means royalty interests in petroleum and natural gas rights
acquired by the Trust from time to time pursuant to a Direct Royalties Sale
Agreement.
"Direct Royalties Sale Agreement" means any purchase and sale agreement between
the Trust and an Operating Subsidiary providing for the purchase by the Trust
from an Operating Subsidiary of Direct Royalties.
"Distributable Cash" means, for any particular period, the Cash Available For
Distribution less any amounts retained by the Trust for the Capital Fund.
"DRIP Plan" means, collectively, the Trust's Distribution Reinvestment Plan and
Optional Trust Unit Purchase Plan.
"East Central Alberta Properties" means Properties located in the East Central
Alberta region.
"Equity Bridge Notes" means, collectively, the equity bridge notes dated July
28, 2003 and amended September 29, 2003, June 29, 2004, July 7, 2004 and July 9,
2004 between the Trust and each of the Bridge Lenders providing for advances of
up to $50 million to the Trust to assist in the payout of the Corporation's then
existing credit facility and the payment of the Deferred Purchase Price
Obligation as a result of the Southeast Saskatchewan Properties Transaction.
"Exchangeable Shares" means the non-voting exchangeable shares in the capital of
the Corporation.
"farmout" means an agreement whereby a third party agrees to pay for all or a
portion of the drilling of a well on one or more of the Properties in order to
earn an interest therein, with an Operating Subsidiary retaining a residual
interest in such Properties.
"GLJ" means Gilbert, Laustsen & Jung Associates Ltd., independent oil and
natural gas reservoir engineers of Calgary, Alberta.
5
"Gross" means:
(a) in relation to the Operating Subsidiaries' interest in production
and reserves, its "Corporation gross reserves", which are the
Operating Subsidiaries' interest (operating and non-operating) share
before deduction of royalties and without including any royalty
interest of the Operating Subsidiaries;
(b) in relation to wells, the total number of wells in which the
Operating Subsidiaries have an interest; and
(c) in relation to properties, the total area of properties in which the
Operating Subsidiaries have an interest.
"HBT1" means Harvest Breeze Trust 1, a trust established under the laws of the
Province of Alberta, wholly owned by HST.
"HBT2" means Harvest Breeze Trust 2, a trust established under the laws of the
Province of Alberta, wholly owned by the Trust.
"HST" means Harvest Sask Energy Trust, a trust established under the laws of the
Province of Alberta, wholly owned by the Trust.
"Independent Reserve Engineering Evaluators" means McDaniel, GLJ and PLA,
independent oil and natural gas reservoir engineers of Calgary, Alberta, who
evaluated the crude oil, natural gas liquids and natural gas reserves of the
Operating Subsidiaries as at December 31, 2004, in accordance with the standards
contained in the COGE Handbook and the reserve definitions contained in NI
51-101.
"Initial Public Offering" means the initial public offering of 3,750,000 Trust
Units at a price of $8.00 per Trust Unit completed on December 5, 2002,
resulting in gross proceeds of $30,000,000, and includes the over-allotment
option granted in favour of and exercised by the underwriters to acquire an
additional 562,500 Trust Units at a price of $8.00 per Trust Unit, resulting in
gross proceeds of $4,500,000.
"McDaniel" means McDaniel & Associates Consultants Ltd., independent oil and
natural gas reservoir engineers of Calgary, Alberta.
"Net" means:
(d) in relation to the Operating Subsidiaries' interest in production
and reserves, the Operating Subsidiaries' interest (operating and
non-operating) share after deduction of royalties obligations, plus
the Operating Subsidiaries' royalty interest in production or
reserves.
(e) in relation to wells, the number of wells obtained by aggregating
the Operating Subsidiaries' working interest in each of its gross
wells; and
(f) in relation to the Operating Subsidiaries' interest in a property,
the total area in which the Operating Subsidiaries have an interest
multiplied by the working interest owned by the Operating
Subsidiaries.
"NI 51-101" means National Instrument 51-101 Standards of Disclosure for Oil and
Gas Activities;
"Notes" means, collectively, the promissory notes issuable by the Corporation in
series pursuant to a note indenture to be redeemed in consideration for a
portion of the NPI, having a fair market value equal to such principal amount,
and being subject to the following terms and conditions:
6
(a) being unsecured and bearing interest at 6% per annum payable monthly
in arrears on the 20th day of the next following month;
(b) being subordinate to all senior indebtedness which includes all
indebtedness for borrowed money or owing in respect of property
purchases on any default in payment of any such senior indebtedness,
and to all trade debt of the Corporation or any subsidiary of the
Corporation or the Trust on any creditor proceedings such as
bankruptcy, liquidation or insolvency;
(c) being subject to earlier prepayment, being due and payable on the
15th anniversary of the date of issuance;
(d) being subject to such other standard terms and conditions as would
be included in a note indenture for promissory notes of this kind,
as may be approved by the Harvest Board.
"NPI" means, collectively, the net profit interest owing by the Operating
Subsidiaries to the Trust pursuant to the NPI Agreements.
"NPI Agreements" means, collectively, the amended and restated net profit
interest agreement dated September 27, 2002 between the Corporation and the
Trust, the royalty agreement dated effective January 17, 2003 between WEI and
BNY Trust Company of Canada and the net profit interest agreement dated October
17, 2003 between HST and the Trust and "NPI Agreement" means any one of these
agreements, as applicable.
"NYMEX" means the New York Mercantile Exchange.
"Operating Subsidiaries" means, collectively, the Corporation, HST, REEI, REP,
BRP, HBT1 and HBT2, each a direct or indirect wholly-owned subsidiary of the
Trust, and "Operating Subsidiary" means any of the Corporation, HST, REEI, REP,
BRP, HBT1, and HBT2, as applicable.
"Ordinary Resolution" means a resolution approved at a meeting of Unitholders by
more than 50% of the votes cast in respect of the resolution by or on behalf of
Unitholders present in person or represented by proxy at the meeting.
"Permitted Investments" means:
(a) loan advances to the Corporation;
(b) interest bearing accounts of certain financial institutions
including Canadian chartered banks and the Trustee;
(c) obligations issued or guaranteed by the Government of Canada or any
province of Canada or any agency or instrumentality thereof;
(d) term deposits, guaranteed investment certificates of deposit or
bankers' acceptances of or guaranteed or accepted by any Canadian
chartered bank or other financial institution (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 or Moody's Investors Service, Inc. or Dominion
Bond Rating Service Limited;
(e) commercial paper rated at least A or the equivalent by Dominion Bond
Rating Service Limited; and
(f) investments in bodies corporate, partnerships or trusts engaged in
the oil and natural gas business;
provided that an investment is not a Permitted Investment if it:
7
(g) would result in the cost amount to the Trust of all "foreign
property" (as defined in the Tax Act) which is held by the Trust to
exceed the amount prescribed by Regulation 5000(1) of the
Regulations to the Tax Act;
(h) is a "small business security" as that term is used in Part L1 of
the Regulations to the Tax Act; or
(i) would result in the Trust not being considered either a "unit trust"
or a "mutual fund trust" for purposes of the Tax Act.
"Person" includes an individual, a body corporate, a trust, a union, a pension
fund, a government and a governmental agency.
"PLA" means Paddock, Lindstrom & Associates Ltd., independent oil and natural
gas reservoir engineers of Calgary, Alberta.
"Pro Rata Share" means, of any particular amount in respect of a Unitholder at
any time, the product obtained by multiplying the number of Trust Units that are
owned by that Unitholder at that time by the quotient obtained when the
particular amount is divided by the total number of all Trust Units that are
issued and outstanding at that time.
"Production" means the produced petroleum, natural gas and natural gas liquids
attributed to the Properties.
"Properties" means the working, royalty or other interests of the Corporation
and HST in any petroleum and natural gas rights, tangibles and miscellaneous
interests, including properties which may be acquired by the Corporation or HST
from time to time.
"Property Interests" means petroleum and natural gas rights and related
tangibles and miscellaneous interests beneficially owned by the Corporation, HST
or HBT2.
"Provost Properties Vendors" means, collectively, the vendors from whom the
Operating Subsidiaries acquired the Provost Properties.
"Record Date" means December 31 of each year hereafter and the last day of each
calendar month or such other date as may be determined from time to time by the
Trustee upon the recommendation of the Board of Directors.
"REEI" means Red Earth Energy Inc., a corporation formed under the laws of the
province of Alberta and wholly owned by the Corporation.
"REP" means Red Earth Partnership, a partnership established under the laws of
Alberta.
"Reserve Fund" means the cumulative amount of production and other revenues
entitled to be retained by the Operating Subsidiaries pursuant to the NPI
Agreements to provide for payment of production costs which the Operating
Subsidiaries estimate will or may become payable in the following six months for
which there may not be sufficient production revenues to satisfy such production
costs in a timely manner. See "Description of the Trust - The NPI and Direct
Royalties - Reserve Fund".
"Reserve Life Index" or "RLI" means the amount obtained by dividing the quantity
of proved plus probable reserves as at the end of the previous year, by the
annualized production of petroleum, natural gas and natural gas liquids from
those reserves, in the following year, as projected in the Reserve Report.
"Reserve Report" means the report prepared by the Independent Reserve
Engineering Evaluators, dated January 1, 2005 evaluating the crude oil, natural
gas liquids and natural gas reserves of the Operating Subsidiaries as at
December 31, 2004, in accordance with the standards contained in the COGE
Handbook and the reserve definitions contained in NI 51-101.
8
"Reserve Value" means, for any petroleum and natural gas property at any time,
the present worth of all of the estimated pre-tax cash flow net of capital
expenditures from the proved plus probable reserves shown in the Reserve Report
for such property, discounted at 10% and using forecast price and cost
assumptions (a common benchmark in the oil and natural gas industry).
"SE Saskatchewan Properties Acquisition Agreement" means the agreement of
purchase and sale between the SE Saskatchewan Properties Vendor and the
Corporation dated effective October 1, 2003 for the purchase of the Southeast
Saskatchewan Properties.
"SE Saskatchewan Properties Transaction" means the acquisition of the Southeast
Saskatchewan Properties by the Corporation pursuant to the SE Saskatchewan
Properties Acquisition Agreement.
"SE Saskatchewan Properties Vendor" means a senior oil and natural gas
partnership.
"Senior Indebtedness" means all indebtedness, liabilities and obligations of the
Trust (whether outstanding as at the date of the Indenture or thereafter
created, incurred or assumed or for which it is liable in respect of any
guarantee, indemnity, suretyship or joint and several liability) (i) in respect
of borrowed money of itself or any subsidiary; (ii) in connection with the
acquisition of any business, properties or asset by itself or any subsidiary;
(iii) in connection with risk mitigation instruments or agreements of itself or
a subsidiary; (iv) to any trade creditors of itself or any subsidiary; or (v)
renewals, extensions, restructurings, refinancings and refunding of any of the
foregoing; unless the instrument creating or evidencing any of the foregoing
provides that such indebtedness, liabilities or obligations are to rank pari
passu, or subordinate, in right of payment to the Debentures.
"Southeast Saskatchewan Properties" means various working, royalty, proprietary
3D seismic and other interests acquired pursuant to the SE Saskatchewan
Properties Transaction as described under "Acquisition of Southeast Saskatchewan
Properties".
"Special Resolution" means a resolution proposed to be passed as a special
resolution at a meeting of Unitholders (including an adjourned meeting) duly
convened for the purpose and held in accordance with the provisions of the Trust
Indenture at which two or more holders of at least 10% of the aggregate number
of Trust Units then outstanding are present in person or by proxy and passed by
the affirmative votes of the holders of not less than 66 2/3% of the Trust Units
represented at the meeting and voted on a poll upon such resolution.
"Special Warrants" means the special trust unit purchase warrants sold to a
syndicate of underwriters on February 4, 2003, which warrants were exchanged for
Trust Units upon their deemed exercise on March 7, 2003.
"Storm" means Storm Energy Ltd.
"Subsequent Investments" means any of the investments that the Trust may make
pursuant to the Trust Indenture, which includes:
(a) making payments to the Corporation pursuant to the Deferred Purchase
Price Obligations under the NPI Agreement;
(b) making loans to the Corporation in connection with the Capital Fund;
and
(c) temporarily holding cash and investments for the purposes of paying
the expenses and liabilities of the Trust, making certain other
investments as contemplated by Section 4.2 of the Trust Indenture,
paying amounts payable by the Trust in connection with the
redemption of any Trust Units, and making distributions to
Unitholders;
provided that such investments will not be a Subsequent Investment if it:
9
(d) would result in the cost amount to the Trust of all "foreign
property" (as defined in the Tax Act) which is held by the Trust to
exceed the amount prescribed by Regulation 5000(1) of the
Regulations to the Tax Act;
(e) is a "small business security" as that term is used in Part L1 of
the Regulations to the Tax Act; or
(f) would result in the Trust not being considered either a "unit trust" or a
"mutual fund trust" for purposes of the Tax Act.
"Tax Act" means the Income Tax Act (Canada) and the regulations thereunder.
"Trust" or "Harvest" means Harvest Energy Trust.
"Trust Fund" at any time, shall mean any of the following monies, properties and
assets that are at such time held by the Trustee on behalf of the Trust for the
purposes of the Trust under the Trust Indenture:
(a) the amount paid to settle the Trust;
(b) all funds realized from the issuance of Trust Units;
(c) any Permitted Investments in which funds may from time to time be
invested;
(d) all rights in respect of and income generated under the NPI
Agreement with the Corporation, including the applicable NPI;
(e) all rights in respect of and income generated under a Direct
Royalties Sale Agreement;
(f) any Subsequent Investment;
(g) any proceeds of disposition of any of the foregoing property
including, without limitation, the Direct Royalties; and
(h) all income, interest, profit, gains and accretions and additional
assets, rights and benefits of any kind or nature whatsoever arising
directly or indirectly from or in connection with or accruing to
such foregoing property or such proceeds of disposition.
"Trust Indenture" means the amended and restated trust indenture dated July 10,
2003 between the Trustee and the Corporation as such indenture may be further
amended by supplemental indentures from time to time.
"Trust Unit" means a trust unit of the Trust created, issued and certified under
the Trust Indenture and outstanding and entitled to the benefits thereof.
"Trustee" means Valiant Trust Company, or its successor as trustee of the Trust.
"TSX" means the Toronto Stock Exchange.
"Unitholders" means the holders from time to time of one or more Trust Units.
"Unit Incentive Plan" means the Trust's unit incentive plan described under
"Trust Unit Incentive Plan".
"U.S. Securities Act" means the United States Securities Act of 1933, as
amended.
"WEI" means the Trust's former wholly-owned subsidiary, Westcastle Energy Inc.,
a corporation incorporated under the Business Corporations Act (Alberta) and
which amalgamated with the Corporation on January 1, 2004, with the amalgamated
corporation continuing under the name "Harvest Operations Corp.".
10
"Working Interest" or "WI" means an undivided interest held by a party in an oil
and/or natural gas or mineral lease granted by a Crown or freehold mineral
owner, which interest gives the holder the right to "work" the property (lease)
to explore for, develop, produce and market the lease substances but does not
include, among other things, a royalty, overriding royalty, gross overriding
royalty, net profits interest or other interest that entitles the holder thereof
to a share of production or proceeds of sale of production without a
corresponding right or obligation to "work" the property.
Certain other terms used herein but not defined herein are defined in NI 51-101
and, unless the context otherwise requires, shall have the same meanings herein
as in NI 51-101.
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ABBREVIATIONS
Oil and Natural Gas Liquids Natural Gas
- --------------------------- -----------
Bbl Barrel Mcf thousand cubic feet
Bbls Barrels Mmcf million cubic feet
Mbbls thousand barrels Bcf billion cubic feet
Bbls/d barrels per day Mcf/d thousand cubic feet per day
Mmbbls million barrels Mmcf/d million cubic feet per day
NGLs natural gas liquids MMBTU million British Thermal Units
Other
AECO EnCana Corporation's natural gas storage facility located at
Suffield, Alberta.
BOE barrel of oil equivalent, using the conversion factor of 6 Mcf
of natural gas being equivalent to one Bbl of oil, unless
otherwise specified. The conversion factor used to convert
natural gas to oil equivalent is not necessarily based upon
either energy or price equivalents at this time.
BOE/d barrels of oil equivalent per day.
MBOE thousand barrels of oil equivalent.
MMBOE million barrels of oil equivalent.
OOIP original oil in place.
WTI West Texas Intermediate, the reference price paid in U.S.
dollars at Cushing, Oklahoma for crude oil of standard grade.
(0)API the measure of the density or gravity of liquid petroleum
products derived from a specific gravity. MW megawatts of
electrical power.
3D three dimensional.
Darcies the measure of permeability (being the ease with which a single
fluid will flow through connected pore space when a pressure
gradient is applied).
porosity the measure of the fraction of pore space of a reservoir.
$000 thousands of dollars
$millions millions of dollars
CONVERSIONS
The following table sets forth certain conversions between Standard Imperial
Units and the International System of Units (or metric units).
To Convert From To Multiply By
--------------- -- -----------
Mcf cubic metres 28.174
cubic metres cubic feet 35.494
Bbls cubic metres 0.159
feet metres 0.305
metres feet 3.281
miles kilometres 1.609
kilometres miles 0.621
acres hectares 0.405
hectares acres 2.471
ALL DOLLAR AMOUNTS SET FORTH IN THIS ANNUAL INFORMATION FORM ARE IN CANADIAN
DOLLARS, EXCEPT WHERE OTHERWISE INDICATED.
DATE OF INFORMATION
Unless otherwise specified, information in this Annual Information Form is as at
the end of the Trust's most recently completed financial year, being December
31, 2004.
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HARVEST ENERGY TRUST
General
The Trust is an open-ended, unincorporated investment trust established under
the laws of the Province of Alberta and created pursuant to the Trust Indenture.
The head and principal office of the Trust is located at Suite 2100, 330 - 5th
Avenue S.W., Calgary, Alberta T2P 0L4. Although the Trust receives income from
the NPI from each of the Operating Subsidiaries, all oil and natural gas
operations are conducted through the Corporation and the Trust is managed solely
by the Corporation pursuant to the Trust Indenture and the Administration
Agreement.
Structure of the Trust
The structure of the Trust and the flow of cash from the Properties to the
Operating Subsidiaries, from the Operating Subsidiaries to the Trust and from
the Trust to Unitholders are set forth below:
------------------------
Uniholders
------------------------
|
| Distributable Cash
------------------------ < ------------------------------------
- ----------------------------- Harvest Energy Trust < ------------------ |
| Capital ------------------------ - NPI Income(4) | |
| Fund | | | |
- ------------------ | | | |
Capital Fund | Note & NPI | Direct | |
- ------------------ | Income(4) | Royalties(3) | |
| | | |
| | --------------------- |
- ------------------ | | Harvest Sask |
Senior Noteholders Senior Notes | | Energy Trust (1)(4) |
- ------------------ <------------------------ | | --------------------- |
| | | | |
- ------------------ <---------------------- --------------------------- | | |
Banking Facilities Debt Service Harvest Operations Corp (1) | | |
- ------------------ --------------------- > --------------------------- | | |
Credit | | | | |
Advances | | | | |
| | | ------------- --------------
| Net Revenue from | | Harvest Harvest
| the sale of 99% of | | Breeze Trust Breeze Trust
| Production | | / No. 1(1)(5) No. 2(1)(4)(5)
| | | / ------------- --------------
----------------------- | | / \ /
| | | | / \ /
---------------- ------------ | | | \ /
Reclamation Fund Reserve Fund | | | \ /
---------------- ------------ | | | \ /
| | | ----------------
| | | Breeze Resources
| | | Partnership
| | | ----------------
| | | |
| | | Net Revenue from |
| | | the Sale of 99% of |
| | | Production |
| | | |
----------------- ----------
Properties(2) Properties
----------------- ----------
Notes:
(1) All operations and management of the Trust and the Operating Subsidiaries
are conducted through Harvest Operations Corp. The Trust holds all of the
voting securities of Harvest Operations Corp. and of Harvest Sask. Energy
Trust.
(2) Harvest Operations Corp. and Harvest Sask. Energy Trust own these
properties.
(3) In addition to the NPI, the Trust holds various direct royalties.
(4) The Trust receives regular monthly payments in accordance with the NPI
Agreements as well as distributions and interest payments from Harvest
Sask. Energy Trust, HBT1 and HBT2.
(5) HBT1 and HBT2 have also issued priority units to Harvest Operations Corp.
GENERAL DEVELOPMENT OF THE BUSINESS
The following is a description of the general development of the business of the
Trust.
13
The Corporation was incorporated on May 14, 2002 to carry on oil and natural gas
acquisition, development and production activities. The Board of Directors then
reviewed its strategic alternatives and based on such review determined that the
formation of an energy royalty trust was the optimal structure. On July 10,
2002, the Trust was formed pursuant to the Trust Indenture. On the same date,
the Corporation and the Trust entered into a net profit agreement which has been
amended and restated effective September 27, 2002 pursuant to which the
Corporation granted to the Trust the right to receive income from the net profit
interest created thereby on Properties held by the Corporation from time to
time. Pursuant to that NPI Agreement, the Trust paid to the Corporation $12.6
million using the proceeds from an interim loan provided by Caribou to the
Trust.
On July 10, 2002 the Corporation acquired certain direct royalties and
properties from a major oil and natural gas producer for an aggregate purchase
price of $26.1 million. The acquisition consisted of an overriding royalty
interest of 7.10688% in the Choice Viking Gas Unit No. 1, and an approximate 99%
working interest in oil and natural gas producing properties that are both
unitized and non-unitized. The purchase price was funded by an advance under the
Corporation's credit facilities and, indirectly, through an interim loan
provided by Caribou to the Trust.
On August 1, 2002 the Corporation entered into an Agreement of Purchase and Sale
with a major oil and natural gas producer to purchase certain direct royalties
and properties effective June 1, 2002 for an aggregate purchase price of $71.8
million. The Corporation completed the acquisition on November 15, 2002 for a
closing price of $53.2 million. The acquisition consisted of a direct royalty
interest and an interest in oil and natural gas producing properties located in
East Central Alberta. The purchase price was funded by an advance under the
Corporation's credit facilities and, indirectly, through an interim loan
provided by Caribou to the Trust.
On December 5, 2002, the Trust completed the Initial Public Offering, which
resulted in the issuance of 3,750,000 Trust Units and aggregate gross proceeds
of $30.0 million. Approximately $22.9 million from the net proceeds of the
Initial Public Offering was used to repay interim loans which had been provided
by Caribou to the Trust (including accrued interest) and approximately $5.4
million from the net proceeds of the Initial Public Offering was used to
partially repay bank indebtedness. The balance was used for general working
capital purposes.
On December 17, 2002, the Trust issued 562,500 Trust Units to FirstEnergy
Capital Corp. and Haywood Securities Inc. as a result of the exercise of an
over-allotment option granted to them in connection with the Initial Public
Offering. The gross proceeds from the sale of such Trust Units were $4.5
million.
On February 4, 2003, the Trust sold 1,500,000 Special Warrants to a syndicate of
underwriters at a price of $10.00 per Special Warrant for net proceeds of $13.7
million. Each Special Warrant entitled the holder to receive on exercise or
deemed exercise one Trust Unit for the payment of no additional consideration.
On March 7, 2003, the Trust received receipts for a (final) prospectus
qualifying the Trust Units issuable on exercise of the Special Warrants and on
March 7, 2003, the Trust issued 1,500,000 Trust Units on the deemed exercise of
the Special Warrants. The net proceeds were used to partially repay bank
indebtedness and for working capital.
During April and May, 2003, the Corporation closed the acquisition of various
interests in two properties in the Killarney area of Alberta. The properties
were acquired from two major oil and natural gas producers for $13.2 million and
the issuance of 200,000 Trust Units respectively. The cash acquisition was
financed through the Corporation's credit facilities. Included with the
acquisition was an interest in two oil batteries.
At the Annual and Special Meeting of Unitholders of the Trust held on June 12,
2003 (the "2003 Unitholders' Meeting"), Unitholders approved resolutions
respecting each of the matters set forth below:
o to amend the Trust Indenture to authorize the creation of an unlimited
number of special voting units ("Special Voting Units"). Each Special
Voting Unit entitles the holder thereof to such number of votes at
meetings of Unitholders as may be prescribed by the Board of Directors of
the Corporation in the resolution authorizing the issuance of any such
Special Voting Units;
o to amend the Trust Indenture to grant the Corporation (through the Board
of Directors) the specific authority and responsibility for any and all
matters relating to the terms of the NPI Agreement and other
14
material contracts of the Trust (other than as otherwise provided in the
Trust Indenture) including any amendments thereto;
o to amend the Trust Indenture to clarify and elaborate upon the
responsibility which had previously been delegated to the Corporation in
respect of matters relating to an issuance or offering of Trust Units or
any other rights, warrants or other securities to purchase, to convert
into or to exchange into Trust Units;
o to authorize an amendment of the articles of the Corporation to create a
new class of non-voting common shares, issuable in series ("Non-Voting
Shares"). Except for the right to notice of and to attend at any meetings
of the shareholders of the Corporation, the holder of the Non-Voting
Shares will have the same rights as the holders of common shares of the
Corporation;
o to increase the number of Trust Units which may be reserved for issuance
under the Unit Incentive Plan by 246,000 Trust Units from 875,000 Trust
Units to a cumulative maximum number of 1,121,000 Trust Units; and
o approving the issuance by the Trust in one or more private placements
during the 12 month period commencing June 12, 2003, of up to 11,210,957
Trust Units, subject to certain restrictions.
On June 27, 2003, the Trust completed the acquisition of all of the common
shares of WEI and an NPI in certain producing oil and natural gas properties
held by WEI in exchange for total consideration of approximately $10.1 million
(consisting of the issuance of 625,000 Trust Units, $3 million in cash and a
$850,000 unsecured promissory note) plus the assumption of $2.8 million in bank
debt and $2.3 million in working capital deficit. The oil and natural gas
producing properties acquired included working interests ranging from 20% to
100% in the fields of Amisk, Czar and Killarney, all of which are operated by
the Corporation.
On July 28, 2003, the Trust entered into the Equity Bridge Notes to provide
funds to pay the Deferred Purchase Price Obligation associated with the
Southeast Saskatchewan Properties Transaction. On July 29, 2003, $11 million was
advanced to the Trust pursuant to the Equity Bridge Notes to fund a deposit
relating to the purchase of the Southeast Saskatchewan Properties. On September
29, 2003, the Trust amended the Equity Bridge Notes to allow advances to be used
to pay out the Corporation's then existing credit facility and entered into the
Bridge Notes. On September 29, 2003, the Trust received additional advances
under the Equity Bridge Notes in the amount of $22.5 million and also received
advances of $25.0 million under the Bridge Notes. These amounts were advanced by
the Trust to the Corporation on September 30, 2003 and used to pay out in part
the approximately $48.1 million owing under the Corporation's then existing
credit facility. On October 1, 2003, the $11 million deposit in connection with
the Southeast Saskatchewan Properties Transaction was refunded and the Trust
used this amount to repay $11 million of principal in respect of the Bridge
Notes.
On July 29, 2003 the Corporation entered into an agreement in respect of the
purchase of partnership interests in a New Brunswick limited partnership which
held the Southeast Saskatchewan Properties. On September 29, 2003 the
Corporation entered into an agreement wherein the interests of the Corporation
in the July 29, 2003 agreement referred to above were assigned to the Southeast
Saskatchewan Properties Vendor and wherein it was agreed that substantially all
of the Southeast Saskatchewan Properties would be conveyed to the Corporation.
On October 1, 2003, the Corporation entered into the Southeast Saskatchewan
Properties Acquisition Agreement with the Southeast Saskatchewan Properties
Vendor to acquire substantially all of the Southeast Saskatchewan Properties
effective October 1, 2003 for total consideration of approximately $80 million,
prior to adjustments and transaction costs. Closing of the Southeast
Saskatchewan Properties Acquisition occurred on October 16, 2003.
Immediately following the completion of the Southeast Saskatchewan Properties
Transaction, the Trust completed an internal reorganization pursuant to which
substantially all of the Southeast Saskatchewan Properties were conveyed to HST,
a trust which is wholly-owned by the Trust.
The Southeast Saskatchewan Properties Acquisition was financed as to $48.65
million through an offering of 4,312,500 Trust Units at a price of $12.00 per
Trust Unit for gross proceeds of $51.8 million and as to $31.35 million through
advances under the Current Bank Facility.
15
The Southeast Saskatchewan Properties are located in South East Saskatchewan
near the town of Carlyle. The majority of the production is situated between
Township 7 Range 32 W1M to Township 13 Range 13 W2M. In 2004, the Southeast
Saskatchewan Properties produced an average of 5,447 BOE/d of light (28(degree)
to 34(degree) API) oil concentrated in the Mississippian-aged Tiltson subcrop
play trend. As evaluated by the Independent Reserve Engineering Evaluators in
the Reserve Report, the Southeast Saskatchewan Properties contained, as at
December 31, 2004, 18.1 MMBOE of proved plus probable reserves, with an RLI of
9.0 years. The recovery mechanism is bottom water drive supported by an active
aquifer affording an efficient recovery of reserves, making operating
characteristics of the Southeast Saskatchewan Properties similar to those of the
other Properties. The Trust has an average Working Interest of 100% in the
Southeast Saskatchewan Properties and operates 100% of the production from the
properties. All of the production is concentrated geographically which promotes
ease of access and operating synergies. Management identified upside value with
the Southeast Saskatchewan Properties, associated with production optimization,
development drilling, the undeveloped land holdings and the proprietary seismic
database.
On October 16, 2003, the Trust issued 4,312,500 Trust Units at a price of $12.00
per Trust Unit for gross proceeds of $51.8 million. The Trust Units were offered
to the public through a syndicate of underwriters, which was led by National
Bank Financial Inc. and included CIBC World Markets Inc., FirstEnergy Capital
Corp. and Haywood Securities Inc.
On January 29, 2004, the Trust issued $60 million principal amount of 9%
convertible unsecured subordinated debentures, maturing on May 31, 2009 and
convertible into Trust Units at a price of $14.00 per Trust Unit. The
convertible debentures were offered to the public through a syndicate of
underwriters which was led by National Bank Financial Inc. and included CIBC
World Markets Inc., FirstEnergy Capital Corp., Haywood Securities Inc., TD
Securities Inc. and Canaccord Capital Corporation.
On June 30, 2004, Harvest acquired Storm Energy for approximately $192.2
million, including assumed debt of approximately $56.8 million and a working
capital deficit of $10.5 million. Harvest paid approximately $75 million in cash
and issued approximately $40 million of trust units and approximately $9 million
of exchangeable shares of the Corporation to former shareholders of Storm. The
acquired properties produced approximately 4,060 boe/d during the six months
ended June 30, 2004 and are primarily concentrated in the Red Earth area of
North Central Alberta. These properties added high quality light oil to
Harvest's product mix, providing diversification benefits, along with low
operating costs. Harvest acquired a 60% interest in the Red Earth Partnership
when it purchased Storm.
On July 30, 2004, the Trust issued 12,166,666 Subscription Receipts at a price
of $14.40 per receipt, each of which entitled the holder to receive one Trust
Unit of the Trust on September 2, 2004, and $100 million principal amount of 8%
convertible unsecured subordinated debentures, maturing on September 30, 2009
and convertible into Trust Units at a price of $16.25 per Trust Unit. The
Subscription Receipts and convertible debentures were offered to the public
through a syndicate of underwriters, which was led by National Bank Financial
Inc., and included CIBC World Markets Inc., TD Securities Inc., BMO Nesbitt
Burns Inc., RBC Dominion Securities Inc., FirstEnergy Capital Corp., Canaccord
Capital Corporation, Haywood Securities Inc. and GMP Securities Ltd.
On September 2, 2004, Harvest acquired Breeze Resources Partnership, which held
certain assets in East Central Alberta and Southern Alberta acquired from a
senior producer, for the purchase price of approximately $526 million before
final working capital adjustments. These assets produced approximately 20,481
boe/d for the six months ended June 30, 2004 and are primarily concentrated in
the Crossfield area of Alberta, southern Alberta and east central Alberta. The
Crossfield and southeast Alberta properties comprise Harvest's new Southern
Alberta core area, and the east central Alberta properties supplemented
Harvest's existing properties in that core area. The acquisition of these assets
added Harvest's first significant natural gas production.
On October 14, 2004 Harvest closed a private placement of US$250 million of
senior notes due October 15, 2011, issued in the United States. Net proceeds
were used to repay Harvest's bank bridge facility associated with the September
2004 asset acquisition and to partially repay outstanding balances under the
Trust's revolving credit facility. The senior notes bear interest at an annual
rate of 7?% and were sold at a price of 99.3392% of their principal amount.
16
Significant Acquisitions and Significant Dispositions
There were no significant acquisitions or significant dispositions by the Trust
or any significant probable acquisitions by the Trust within or since the
completion of the most recently completed financial year of the Trust other than
as described above in "- General Development of the Business" and as described
in "Recent Developments - Acquisitions".
RECENT DEVELOPMENTS
Acquisitions
On June 30, 2004, Harvest Operations Corp. amalgamated with Storm Energy Ltd.
immediately after acquiring its shares under a Plan of Arrangement. The
amalgamated corporation continued under the name "Harvest Operations Corp.".
On September 2, 2004, Harvest acquired the Breeze Resources Partnership which
held certain producing assets acquired from a senior producer. This acquisition
closed for a purchase price of $526 million, before closing adjustments. This
acquisition was financed partially with bank debt, which was mostly repaid with
the proceeds of a US$250 million senior note offering closed in October 2004.
Potential Acquisitions
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, the Trust has not reached agreement on the
price or terms of any potential material acquisitions other than as described
above. The Trust cannot predict whether any current or future opportunities will
result in one or more acquisitions for the Trust.
STATEMENT OF RESERVES DATA
The statement of reserves data and other oil and natural gas information set
forth below (the "Statement") is dated December 31, 2004. The effective date of
the Statement is December 31, 2004 and the preparation date of the Statement is
February 17, 2005.
Disclosure of Reserves Data
Harvest retained the qualified, Independent Reserves Engineering Evaluators to
evaluate and prepare reports on 100% of Harvest's crude oil and natural gas
reserves as of December 31, 2004. Harvest's reserves were evaluated by McDaniel
(who evaluated 77% of Harvest's total reserves), GLJ (who evaluated 17% of
Harvest's total reserves) and PLA (who evaluated 6% of Harvest's total
reserves).
The Reserves Data summarizes the crude oil, natural gas liquids and natural gas
reserves of the Operating Subsidiaries and the net present values of future net
revenue for these reserves using constant prices and costs and forecast prices
and costs. The Reserve Report has been prepared by the Independent Reserve
Engineering Evaluators in accordance with the standards contained in the COGE
Handbook and the reserve definitions contained in NI 51-101. Additional
information not required by NI 51-101 has been presented to provide continuity
and additional information which we believe is important to the readers of this
information. The Operating Subsidiaries engaged the Independent Reserve
Engineering Evaluators to provide an evaluation of proved and proved plus
probable reserves and no attempt was made to evaluate possible reserves.
All of the Operating Subsidiaries' reserves are in Canada and, specifically, in
the provinces of Alberta, British Columbia and Saskatchewan.
17
Disclosure provided herein in respect of BOEs may be misleading, particularly if
used in isolation. A BOE conversion ratio of 6 Mcf:1 bbl is based on an energy
equivalency conversion method primarily applicable at the burner tip and does
not represent a value equivalency at the wellhead.
It should not be assumed that the estimates of future net revenues presented in
the tables below represent the fair market value of the reserves. There is no
assurance that the constant prices and costs assumptions and forecast prices and
costs assumptions will be attained and variances could be material. The recovery
and reserve estimates of the Operating Subsidiaries' crude oil, natural gas
liquids and natural gas reserves provided herein are estimates only and there is
no guarantee that the estimated reserves will be recovered. Actual crude oil,
natural gas and natural gas liquid reserves may be greater than or less than the
estimates provided herein.
Reserves Data (Constant Prices and Costs)
SUMMARY OF OIL AND NATURAL GAS RESERVES
AND NET PRESENT VALUES OF FUTURE NET REVENUE
as of December 31, 2004
CONSTANT PRICES AND COSTS
RESERVES
-------------------------------------------------------------------------------
LIGHT AND MEDIUM OIL HEAVY OIL NATURAL GAS
---------------------- ----------------------- ----------------------
Gross Net Gross Net Gross Net
RESERVES CATEGORY (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mmcf) (Mmcf)
- ----------------------------- -------- -------- -------- -------- -------- --------
PROVED
Developed Producing 26,722.0 23,942.0 29,163.3 26,766.4 56,899.6 50,471.5
Developed Non-Producing 355.6 329.1 - - 5,648.7 5,425.4
Undeveloped 2,691.6 2,396.4 3,374.5 3,093.8 1,949.6 1,325.7
-------- -------- -------- -------- -------- --------
TOTAL PROVED 29,769.2 26,667.5 32,537.8 29,860.2 64,497.9 57,222.6
-------- -------- -------- -------- -------- --------
PROBABLE 8,205.9 7,488.8 14,950.3 13,819.7 18,512.3 16,360.0
-------- -------- -------- -------- -------- --------
TOTAL PROVED PLUS PROBABLE 37,975.1 34,156.3 47,488.1 43,679.9 83,010.2 73,582.6
======== ======== ======== ======== ======== ========
RESERVES
---------------------------------------------------
NATURAL GAS LIQUIDS TOTAL OIL EQUIVALENT (BOE)
--------------------- --------------------------
Gross Net Gross Net
RESERVES CATEGORY (Mbbl) (Mbbl) (Mboe) (Mboe)
- --------------------------- ------- ------- --------- --------
PROVED
Developed Producing 1,981.1 1,755.8 67,349.7 60,876.1
Developed Non-Producing 82.2 72.0 1,379.3 1,305.3
Undeveloped 62.5 60.0 6,453.5 5,771.2
------- ------- --------- --------
TOTAL PROVED 2,125.8 1,887.8 75,182.5 67,952.6
------- ------- --------- --------
PROBABLE 509.2 460.1 26,750.8 24,495.3
------- ------- --------- --------
TOTAL PROVED PLUS PROBABLE 2,635.0 2,347.9 101,933.2 92,447.9
======= ======= ========= ========
18
NET PRESENT VALUES OF FUTURE NET REVENUE
---------------------------------------------------------------------------
DISCOUNTED BEFORE INCOME TAXES (1)
---------------------------------------------------------------------------
0% 5% 10% 15% 20%
RESERVES CATEGORY ($000) ($000) ($000) ($000) ($000)
- -------------------------------- ----------- ----------- --------- --------- ---------
PROVED
Developed Producing 998,514.7 806,481.2 684,174.1 599,096.0 536,200.3
Developed Non-Producing 41,029.0 29,407.2 22,871.7 18,695.7 15,790.2
Undeveloped 93,379.0 66,294.0 49,224.5 37,705.4 29,512.0
----------- ----------- --------- --------- ---------
TOTAL PROVED 1,132,922.7 902,182.4 756,270.3 655,497.1 581,502.5
----------- ----------- --------- --------- ---------
PROBABLE 372,454.7 254,713.9 188,850.9 147,266.4 118,838.8
----------- ----------- --------- --------- ---------
TOTAL PROVED PLUS PROBABLE 1,505,377.4 1,156,896.3 945,121.2 802,763.5 700,341.3
=========== =========== ========= ========= =========
TOTAL FUTURE NET REVENUE
(UNDISCOUNTED)
as of December 31, 2004
CONSTANT PRICES AND COSTS
FUTURE NET
OPERATING DEVELOPMENT WELL ABANDONMENT REVENUE BEFORE
RESERVES REVENUE ROYALTIES COSTS COSTS COSTS INCOME TAXES(1)
CATEGORY ($000) ($000) ($000) ($000) ($000) ($000)
- ----------------- ------------ ----------- ----------- ------------- ------------------ ----------------
Proved Reserves 2,392,609 273,263 842,770 76,407 67,246 1,132,923
Proved Plus
Probable Reserves 3,152,293 347,123 1,094,278 135,818 69,697 1,505,377
FUTURE NET REVENUE
BY PRODUCTION GROUP
as of December 31, 2004
CONSTANT PRICES AND COSTS
FUTURE NET REVENUE BEFORE
INCOME TAXES (discounted at
10%/year)
RESERVES CATEGORY PRODUCTION GROUP ($000)
- ------------------------------------- --------------------------------------------- -------------------------------
Proved Reserves Light and Medium Crude Oil 410,994
Heavy Crude Oil 178,211
Natural Gas (including by-products) 167,065
Proved Plus Probable Reserves Light and Medium Crude Oil 489,163
Heavy Crude Oil 242,344
Natural Gas (including by-products) 213,614
19
Reserves Data (Forecast Prices and Costs) - December 31, 2004
SUMMARY OF OIL AND NATURAL GAS RESERVES
AND NET PRESENT VALUES OF FUTURE NET REVENUE
as of December 31, 2004
FORECAST PRICES AND COSTS
RESERVES
LIGHT AND MEDIUM OIL HEAVY OIL NATURAL GAS
---------------------- --------------------- ----------------------
Gross Net Gross Net Gross Net
RESERVES CATEGORY (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mmcf) (Mmcf)
- ------------------------------------ -------- -------- -------- -------- -------- --------
PROVED
Developed Producing 26,385.8 23,679.3 29,355.3 26,635.9 56,887.4 50,464.8
Developed Non-Producing 356.6 331.9 0 0 5,649.7 5,426.4
Undeveloped 2,698.6 2,416.3 3,374.5 2,923.7 1,953.6 1,328.7
-------- -------- -------- -------- -------- --------
TOTAL PROVED 29,441.0 26,427.5 32,729.8 29,559.6 64,490.7 57,219.9
-------- -------- -------- -------- -------- --------
PROBABLE 8,397.7 7,679.9 15,446.9 13,849.4 18,660.2 16,474.6
-------- -------- -------- -------- -------- --------
TOTAL PROVED PLUS PROBABLE 37,838.7 34,107.4 48,176.7 43,409.0 83,150.9 73,694.5
======== ======== ======== ======== ======== ========
RESERVES
--------------------------------------------------
NATURAL GAS LIQUIDS TOTAL OIL EQUIVALENT
--------------------- -----------------------
Gross Net Gross Net
RESERVES CATEGORY (Mbbl) (Mbbl) (Mboe) (Mboe)
- ----------------------------------- ------- ------- --------- --------
PROVED
Developed Producing 1,979.5 1,755.4 67,201.8 60,481.4
Developed Non-Producing 82.2 72.0 1,380.4 1,308.3
Undeveloped 63.5 60.0 6,462.2 5,621.5
------- ------- --------- --------
TOTAL PROVED 2,125.2 1,887.4 75,044.5 67,411.1
------- ------- --------- --------
PROBABLE 512.8 463.0 27,467.4 24,738.1
------- ------- --------- --------
TOTAL PROVED PLUS PROBABLE 2,638.0 2,350.4 102,511.9 92,149.2
======= ======= ========= ========
NET PRESENT VALUES OF FUTURE NET REVENUE
BEFORE INCOME TAXES DISCOUNTED AT (%/year) (1)
----------------------------------------------------------------------------
0% 5% 10% 15% 20%
RESERVES CATEGORY ($000) ($000) ($000) ($000) ($000)
- ------------------------------------ ----------- ----------- ----------- --------- ---------
PROVED
Developed Producing 1,145,401.6 948,487.3 820,000.6 728,640.9 659,768.4
Developed Non-Producing 35,851.3 25,399.5 19,697.4 16,136.0 13,691.1
Undeveloped 103,879.8 77,550.3 60,364.4 48,400.8 39,649.2
----------- ----------- ----------- --------- ---------
TOTAL PROVED 1,285,132.7 1,051,437.1 900,062.4 793,177.7 713,108.7
----------- ----------- ----------- --------- ---------
PROBABLE 447,590.0 310,111.9 232,424.1 183,027.1 149,083.9
----------- ----------- ----------- --------- ---------
TOTAL PROVED PLUS PROBABLE 1,732,722.7 1,361,549.0 1,132,486.5 976,204.8 862,192.6
=========== =========== =========== ========= =========
20
TOTAL FUTURE NET REVENUE
(UNDISCOUNTED)
as of December 31, 2004
FORECAST PRICES AND COSTS
FUTURE NET
OPERATING DEVELOPMENT WELL ABANDONMENT REVENUE BEFORE
RESERVES REVENUE ROYALTIES COSTS COSTS COSTS INCOME TAXES(1)
CATEGORY ($000) ($000) ($000) ($000) ($000) ($000)
- ---------------- ---------- ------------ ------------ ------------- ----------------- ------------------
Proved Reserves 2,732,967 310,515 965,391 83,341 88,587 1,285,133
Proved Plus
Probable
Reserves 3,672,879 408,354 1,291,284 146,272 94,246 1,732,723
FUTURE NET REVENUE
BY PRODUCTION GROUP
as of December 31, 2004
FORECAST PRICES AND COSTS
FUTURE NET REVENUE BEFORE
INCOME TAXES (discounted at
10%/year)
RESERVES CATEGORY PRODUCTION GROUP ($000)
- ---------------------------------- --------------------------------------------- --------------------------------
Proved Reserves Light and Medium Crude Oil 405,447
Heavy Crude Oil 331,702
Natural Gas (including by-products) 162,913
Proved Plus Probable Reserves Light and Medium Crude Oil 481,776
Heavy Crude Oil 458,081
Natural Gas (including by-products) 192,630
Notes to Reserves Data Tables:
1. The Trust is entitled to deduct from its income all amounts which are paid
or payable by it to Unitholders in a given financial year. As a result of
amounts paid to Unitholders in the course of the most recent financial
year, the Trust is not liable for any material amount of income tax on
income. The net present values of future net revenue after income taxes
are, therefore, the same as the net present values of future net revenue
before income taxes.
2. Columns may not add due to rounding.
3. The crude oil, natural gas liquids and natural gas reserve estimates
presented in the Reserve Report are based on the definitions and
guidelines contained in the COGE Handbook. A summary of those definitions
are set forth below.
Reserve Categories
Reserves are estimated remaining quantities of oil and natural gas and related
substances anticipated to be recoverable from known accumulations, from a given
date forward, based on
o analysis of drilling, geological, geophysical and engineering data;
o the use of established technology; and
21
o specified economic conditions (see the discussion of "Economic
Assumptions" below).
Reserves are classified according to the degree of certainty associated with the
estimates.
(a) Proved reserves are those reserves that can be estimated with a high
degree of certainty to be recoverable. It is likely that the actual
remaining quantities recovered will exceed the estimated proved
reserves.
(b) Probable reserves are those additional reserves that are less
certain to be recovered than proved reserves. It is equally likely
that the actual remaining quantities recovered will be greater or
less than the sum of the estimated proved plus probable reserves.
Other criteria that must also be met for the categorization of reserves are
provided in the COGE Handbook.
Each of the reserve categories (proved and probable) may be divided into
developed and undeveloped categories:
(c) Developed reserves are those reserves that are expected to be
recovered from existing wells and installed facilities or, if
facilities have not been installed, that would involve a low
expenditure (for example, when compared to the cost of drilling a
well) to put the reserves on production. The developed category may
be subdivided into producing and non-producing.
(i) Developed producing reserves are those reserves that are
expected to be recovered from completion intervals open at the
time of the estimate. These reserves may be currently
producing or, if shut-in, they must have previously been on
production, and the date of resumption of production must be
known with reasonable certainly.
(ii) Developed non-producing reserves are those reserves that
either have not been on production, or have previously been on
production, but are shut-in, and the date of resumption of
production is unknown.
(d) Undeveloped reserves are those reserves expected to be recovered
from known accumulations where a significant expenditure (for
example, when compared to the cost of drilling a well) is required
to render them capable of production. They must fully meet the
requirements of the reserves classification (proved, probable) to
which they are assigned.
In multi-well pools it may be appropriate to allocate total pool reserves
between the developed and undeveloped categories or to subdivide the developed
reserves for the pool between developed producing and developed non-producing.
This allocation should be based on the estimator's assessment as to the reserves
that will be recovered from specific wells, facilities and completion intervals
in the pool and their respective development and production status.
Levels of Certainty for Reported Reserves
The qualitative certainty levels referred to in the definitions above are
applicable to individual reserve entities (which refers to the lowest level at
which reserves calculations are performed) and to reported reserves (which
refers to the highest level sum of individual entity estimates for which
reserves are presented). Reported reserves should target the following levels of
certainty under a specific set of economic conditions:
(a) at least a 90 percent probability that the quantities actually recovered
will equal or exceed the estimated proved reserves; and
(b) at least a 50 percent probability that the quantities actually recovered
will equal or exceed the sum of the estimated proved plus probable
reserves.
22
A qualitative measure of the certainty levels pertaining to estimates prepared
for the various reserves categories is desirable to provide a clearer
understanding of the associated risks and uncertainties. However, the majority
of reserves estimates will be prepared using deterministic methods that do not
provide a mathematically derived quantitative measure of probability. In
principle, there should be no difference between estimates prepared using
probabilistic or deterministic methods.
Additional clarification of certainty levels associated with reserves estimates
and the effect of aggregation is provided in the COGE Handbook.
Forecast Prices and Costs - January 1, 2005
Forecast prices and costs are those:
(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 Operating
Subsidiaries 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).
The forecast cost and price assumptions assume increases in wellhead selling
prices and take into account inflation with respect to future operating and
capital costs. Crude oil and natural gas benchmark reference pricing, inflation
and exchange rates utilized in the Reserve Report, based on McDaniel's then
current forecasts at the date of the Report, were as follows:
SUMMARY OF PRICING AND INFLATION RATE ASSUMPTIONS
as of January 1, 2005
FORECAST PRICES AND COSTS
OIL
--------------------------------------------------------
Sask NATURAL GAS
Alberta Cromer NATURAL LIQUIDS
Alberta Bow River Medium GAS Edmonton
WTI Edmonton Heavy Medium Crude Alberta Cond. and U.S./ CAN
Crude Oil Light Crude Oil Crude Oil Oil AECO Spot Natural INFLATION EXCHANGE
($US/ Crude Oil ($Cdn/ ($Cdn/ ($Cdn/ Price Gasolines RATES (1) RATE(2)
Year bbl) ($Cdn/ bbl) bbl) bbl) bbl) ($Cdn/ GJ) ($Cdn/ bbl) (%/Year) ($US/$Cdn)
Forecast ---------- ----------- --------- ---------- ------ ---------- ----------- ---------- ----------
2005 42.00 49.60 29.40 37.00 43.50 6.45 50.40 2.0 0.830
2006 39.50 46.60 29.90 37.10 40.90 6.20 47.40 2.0 0.830
2007 37.00 43.50 27.90 34.60 38.20 6.05 44.30 2.0 0.830
2008 35.00 41.10 26.30 32.70 36.00 5.80 41.90 2.0 0.830
2009 34.50 40.50 25.90 32.20 35.50 5.70 41.30 2.0 0.830
2010 34.30 40.20 25.80 32.00 35.30 5.60 41.00 2.0 0.830
2011 35.00 41.00 26.30 32.60 36.00 5.80 41.80 2.0 0.830
2012 35.70 41.90 26.80 33.30 36.70 5.90 42.80 2.0 0.830
2013 36.40 42.70 27.30 33.90 37.40 5.95 43.60 2.0 0.830
2014 37.10 43.50 27.90 34.60 38.10 6.05 44.40 2.0 0.830
2015 37.80 44.30 28.40 35.20 38.90 6.20 45.20 2.0 0.830
2016 38.60 45.30 29.00 36.00 39.70 6.35 46.20 2.0 0.830
2017 39.40 46.20 29.60 36.70 40.50 6.45 47.20 2.0 0.830
2018 40.20 47.10 30.20 37.50 41.30 6.65 48.10 2.0 0.830
2019 41.00 48.10 30.80 38.20 42.20 6.75 49.10 2.0 0.830
2020 41.80 49.00 31.40 38.90 43.00 6.85 50.00 2.0 0.830
2021 42.60 50.00 32.00 39.70 43.80 6.95 51.00 2.0 0.830
2022 43.50 51.00 32.70 40.50 44.70 7.15 52.10 2.0 0.830
2023 44.40 52.10 33.30 41.40 45.60 7.30 53.20 2.0 0.830
2024 45.30 53.10 34.00 42.20 46.60 7.50 54.20 2.0 0.830
There-after 45.30 53.10 34.00 42.20 46.60 7.50 54.20 0.0 0.830
23
Notes:
(1) Inflation rates for forecasting prices and costs.
(2) Exchange rates used to generate the benchmark reference prices in this
table.
Weighted average historical prices realized by the Operating Subsidiaries for
the year ended December 31, 2004, were $6.30/mcf for natural gas, $41.10/bbl for
natural gas liquids and $31.11/bbl for heavy oil.
Constant Prices and Costs
Constant prices and costs are:
(c) the Operating Subsidiaries' prices and costs as at the effective
date of the estimation, held constant throughout the estimated lives
of the properties to which the estimate applies; and
(d) if, and only to the extent that, there are fixed or presently
determinable future prices or costs to which the Operating
Subsidiaries is legally bound by a contractual or other obligation
to supply a physical product, including those for an extension
period of a contract that is likely to be extended, those prices or
costs rather than the prices and costs referred to in paragraph (a).
For the purposes of paragraph (a), the Operating Subsidiaries' prices are the
posted prices for oil and the spot price for natural gas, after historical
adjustments for transportation, gravity and other factors.
The constant crude oil and natural gas benchmark references pricing and the
exchange rate utilized in the Reserve Report were as follows:
SUMMARY OF PRICING ASSUMPTIONS
as of December 31, 2004
CONSTANT PRICES AND COSTS
OIL NATURAL GAS
---------------------------------------------- NATURAL GAS LIQUIDS
Bow Alberta Spot Edmonton
West Texas Edmonton River Cromer Natural Gas Reference
Intermediate Light Medium Hardisty Medium Price at Price NGL EXCHANGE
(WTI)(1) Crude(2) Crude(2) Heavy(3) Crude(2) Field Gate(4) Mix(3) RATE(1)
Year ($US/bbl) ($Cdn/bbl) ($Cdn/bbl) ($Cdn/bbl) ($Cdn/bbl) ($Cdn/MMBtu) ($Cdn/bbl) ($US/$Cdn)
- ----------- ------------ ---------- ---------- ---------- ---------- -------------- ------------ ----------
2004 43.45 48.79 24.58 17.61 39.70 6.62 37.30 0.8308
Notes:
(1) December 31, 2004 NYMEX close
(2) Average of Shell, Imperial, PetroCanada pricing at December 31, 2004
(3) Based on historical price differentials and adjustments
(4) Estimated from AECO December 31, 2004 price of $6.44/GJ
Future Development Costs
The following table sets forth development costs deducted in the estimation of
the Operating Subsidiaries' future net revenue attributable to the reserve
categories noted below.
24
Forecast Prices and Costs Constant Prices and Costs
($000) ($000)
------------------------------------ ------------------------------------
Year Proved Plus Proved Plus
Proved Reserves Probable Reserves Proved Reserves Probable Reserves
--------------- ----------------- --------------- -----------------
2005 23,796 42,304 23,426 41,641
2006 29,346 67,280 28,242 64,715
2007 4,294 4,690 4,070 4,443
Thereafter 25,905 31,998 20,669 25,019
Total Undiscounted 83,341 146,272 76,407 135,818
====== ======= ====== =======
Total Discounted at 10% 60,304 111,654 57,425 107,061
Estimated future abandonment and reclamation costs related to a property have
been taken into account by the Independent Reserve Engineering Evaluators in
determining reserves that should be attributed to a property and in determining
the aggregate future net revenue therefrom, there was deducted the reasonable
estimated future well abandonment costs. No allowance was made, however, for
reclamation of wellsites or the abandonment and reclamation of any facilities.
Both the constant and forecast price and cost assumptions assume the continuance
of current laws and regulations.
The extent and character of all factual data supplied to the Independent Reserve
Engineering Evaluators were accepted by the Independent Reserve Engineering
Evaluators as represented. No field inspection was conducted.
Reconciliations of Changes in Reserves and Future Net Revenue
RECONCILIATION OF
OPERATING SUBSIDIARIES NET RESERVES (After royalties)
BY PRINCIPAL PRODUCT TYPE
FORECAST PRICES AND COSTS
ASSOCIATED AND NON-ASSOCIATED
LIGHT AND MEDIUM OIL HEAVY OIL NATURAL GAS
-------------------------------- ------------------------------- -------------------------------
Net Net Net
Proved Proved Proved
Net Net Plus Net Net Plus Net Net Plus
Proved Probable Probable Proved Probable Probable Proved Probable Probable
FACTORS (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mmcf) (Mmcf) (Mmcf)
- --------------------- ---------- ---------- ---------- --------- ---------- ---------- --------- ---------- ----------
December 31, 2003 17,512.1 4,279.7 21,791.8 6,307.2 895.6 7,202.8 1,700.4 564.1 2,264.5
Extensions/Improved
Recovery 860.3 528.0 1,388.3 23.0 26.6 49.6 52.0 12.0 64.0
Technical Revisions 963.7 113.5 1,077.2 450.4 169.3 619.7 234.7 133.7 368.4
Discoveries 325.6 109.4 435.0 0.0 0.0 0.0 0.0 0.0 0.0
Acquisitions 8,580.1 2,420.4 11,000.5 24,478.4 12,418.9 36,897.3 57,974.1 15,479.2 73,453.3
Dispositions 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Economic Factors 1,929.3 228.9 2,158.2 899.9 338.0 1,238.9 594.8 285.6 880.4
Production (3,743.6) 0.0 (3,743.6) (2,599.3) 0.0 (2,599.3) (3,336.1) 0.0 (3,336.1)
- ------------------------------------------------------------------------------------------------------------------------
December 31, 2004 26,427.5 7,679.9 34,107.4 29,559.6 13,849.4 43,409.0 57,219.9 16,474.6 73,694.5
========================================================================================================================
25
-------------------------------------- --------------------------------------
NATURAL GAS LIQUIDS TOTAL (BOE)
-------------------------------------- --------------------------------------
Net Proved Net Proved
Net Plus Net Plus
Net Proved Probable Probable Net Proved Probable Probable
FACTORS (Mbbl) (Mbbl) (Mbbl) (MBOE) (MBOE) (MBOE)
- ----------------------- ------------- ------------ ----------- ------------ ------------ ------------
December 31, 2003 101.8 27.2 129.0 24,204.5 5,296.5 29,501.0
Extensions/ Improved
Recovery 0.0 0.0 0.0 891.9 556.6 1,448.5
Technical Revisions 72.9 17.4 90.3 1,526.1 322.5 1,848.6
Discoveries 0.0 0.0 0.0 325.6 109.4 435.0
Acquisitions 1,710.2 383.6 2,093.8 44,431.1 17,802.8 62,233.8
Dispositions 0.0 0.0 0.0 0.0 0.0 0.0
Economic Factors 146.5 34.8 181.3 3,074.80 650.3 3,725.20
Production (144.0) 0.0 (144.0) (7,042.9) 0.0 (7,042.9)
- ------------------------------------------------------------------------------------------------------
December 31, 2004 1,887.4 463.0 2,350.4 67,411.1 24,738.1 92,149.2
======================================================================================================
RECONCILIATION OF CHANGES IN
NET PRESENT VALUES OF FUTURE NET REVENUE
DISCOUNTED AT 10% PER YEAR
PROVED RESERVES
CONSTANT PRICES AND COSTS
2004
PERIOD AND FACTOR ($000)
- ------------------------------------------------------------------------------- -------------
Estimated Future Net Revenue at Beginning of Year $ 244,263
Oil and Gas Sales During the Period Net of Royalties and Production Costs (203,653)
Changes due to Prices 21,431
Actual Development Costs During the Period 42,662
Changes in Future Development Costs (85,871)
Changes Resulting from Extensions, Infill Drilling and Improved Recovery 30,616
Changes Resulting from Discoveries 7,960
Changes Resulting from Acquisitions of Reserves 502,785
Changes Resulting from Dispositions of Reserves --
Accretion of Discount 24,426
Other Significant Factors --
Net Changes in Income Taxes --
Changes Resulting from Technical Reserves Revisions Plus Effects of Timing 171,651
-------------
Estimated Future Net Revenue at End of Year $ 756,270
-------------
Note: Table includes values from all Independent Reserve Engineering Evaluators
Additional Information Relating to Reserves Data
Undeveloped Reserves
The Operating Subsidiaries carry a relatively minor amount of undeveloped
reserves. These reserves are infill wells primarily located in undrilled spacing
units. A portion of these infill wells are projected to be upgraded to producing
status in 2005 and the remainder in 2006 and 2007.
26
The Operating Subsidiaries do not see a major uncertainty related to the
upgrading of undeveloped reserves. Nevertheless, a catastrophic drop in oil
prices might delay infill drilling activity.
Important economic factors that should be taken into consideration that may
affect particular components of the reserve data include: oil pricing, power
costs and operating expenses.
Significant Factors or Uncertainties
Information in this Annual Information Form contains forward-looking information
and estimates with respect to Harvest. This information addresses future events
and conditions, and as such involves risks and uncertainties that could cause
actual results to differ materially from those contemplated by the information
provided. These risks and uncertainties include but are not limited to factors
intrinsic in domestic and international politics and economics, general industry
conditions including the impact of environmental laws and regulations,
imprecision of reserves estimates, fluctuations in commodity prices, interest
rates or foreign exchange rates and stock market volatility. The information and
opinions concerning the Trust's future outlook are based on information
available at March 16, 2005.
OTHER OIL AND NATURAL GAS INFORMATION
Oil and Natural Gas Properties
The Operating Subsidiaries' portfolio of Properties is discussed below. Although
the Trust receives income from the NPI from each of the Operating Subsidiaries,
all oil and natural gas operations and the management of the Trust are conducted
by the Corporation.
In general, the Properties include major oil accumulations which benefit from
active pressure support due to an underlying regional aquifer. Generally, the
properties have predictable decline rates with costs of production and oil price
key to determining the economic limits of production. The Corporation is
actively engaged in cost reduction, production and reserve replacement
optimization efforts directed at reserve addition through extending the economic
life of these producing properties beyond the limits used in the Reserve Report
and developing new proven reserves previously not evaluated by the Independent
Reserve Engineering Evaluators. In respect of the Properties, the Corporation
has entered into a number of electrical power swaps to manage a portion of the
risk associated with electrical power cost volatility, which is a significant
portion of the production costs associated with the Properties.
Harvest's portfolio of significant properties is discussed below. In general,
the properties include major oil accumulations which benefit from active
pressure support due to an underlying regional aquifer. Generally, the
properties have predictable decline rates with costs of production and oil price
key to determining the economic limits of production. Harvest is actively
engaged in cost reduction, production and reserve replacement optimization
efforts directed at reserve addition through extending the economic life of
these properties and developing new proven reserves previously not evaluated by
Harvest's Independent Reserve Engineering Evaluators.
27
2004 Historical Production by Material Property
Light, Medium and Average Daily
Heavy Crude Oil Natural gas Production
Core Area and Material Property (bbl/d) (mcf/d) NGL (bbl/d) (BOE/d)
- -----------------------------------------------------------------------------------------------------------------
Southern Alberta
Suffield(1) 2,334 538 -- 2,424
Crossfield(1) -- 4,703 186 970
Cavalier(1) 304 2,708 15 770
Badger(1) 248 196 6 287
Other(1) 6 46 -- 14
- -----------------------------------------------------------------------------------------------------------------
Total Southern Alberta 2,892 8,191 207 4,465
- -----------------------------------------------------------------------------------------------------------------
East Central Alberta
Hayter 4,587 347 13 4,658
Wainwright/Viking Kinsella(1) 999 43 -- 1,006
Killarney 1,083 95 3 1,102
Thompson Lake 1,019 286 25 1,092
Amisk/Czar 978 74 6 996
Halkirk/Leahurst(1) 201 414 6 276
Other(1) 1,802 1,116 23 2,012
- -----------------------------------------------------------------------------------------------------------------
Total East Central Alberta 10,669 2,375 76 11,142
- -----------------------------------------------------------------------------------------------------------------
North Central Alberta
Evi 1(2) 683 -- 92 775
Evi 3 / Kitty(2) 125 -- -- 125
Loon Lake(2) 324 -- -- 324
Red Earth(2) 208 -- -- 208
Other(2) 93 34 5 103
- -----------------------------------------------------------------------------------------------------------------
Total North Central Alberta 1,433 34 97 1,535
- -----------------------------------------------------------------------------------------------------------------
Saskatchewan
Hazelwood 2,454 -- 91 2,544
Moose Valley 1,063 -- -- 1,063
Big Marsh / White Bear 873 287 -- 921
Flinton/Corning 827 -- -- 827
Other 520 16 -- 523
- -----------------------------------------------------------------------------------------------------------------
Total Saskatchewan 5,736 303 91 5,877
- -----------------------------------------------------------------------------------------------------------------
2004 Production Total 20,730 10,903 471 23,019
=================================================================================================================
(1) Properties acquired as part of the Property Acquisition completed on
September 2, 2004. Production only reflects annual historical contribution
from September 2, 2004.
(2) Properties acquired as part of the Storm acquisition completed June 30,
2004. Production only reflects annual historical contribution from June
30, 2004.
28
East Central Alberta
The properties within the East Central Alberta core area are located between
T35-R1-W4 to T49-R2-W5M and produce primarily crude oil. The following
summarizes the key characteristics of this core operating area:
Proved Reserves:
Oil (mbbl) 27,338.2
NGL (mbbl) 183.5
Natural gas (mmcf) 4,697.0
- ----------------------------------------------------------------------
Total (mboe) 28,304.5
PV10 ($000) 281,072.2
Current Production (boe/d) 13,956
Producing wells 1,360
Ownership 85-90%
Operatorship 90%
Average area operating expenses ($/boe) $9.09
Viking-Kinsella/Wainwright
Harvest acquired the Viking-Kinsella/Wainwright property from EnCana in
September 2004. Current production from these pools averages approximately 3,180
boe/d of 20(Degree) API oil, producing from the Cretaceous Upper Mannville
Sparky Formation. Harvest has an average 96% working interest in these operated
properties. Original oil in place (OOIP) at Viking-Kinsella/Wainwright is
estimated at 133 mmbbls on Harvest's working interest acreage.
Future development opportunities at this property may include 16 infill and
step-out drilling locations, as well as field optimization in fluid handling and
debottlenecking the water injection system, which Harvest believes will
contribute to reduced operating expenses. Numerous fracture stimulation
opportunities also have been identified.
Hayter
Harvest acquired the Hayter property in November 2002. Current production at
Hayter averages approximately 4,500 boe/d of 14.8(Degree) API oil, producing
from the Lower Cretaceous Cummings/Dina formation. Harvest has an average 94%
working interest in this operated property. OOIP at Hayter is estimated at 138
mmbbls of oil on Harvest's working interest acreage.
Future development at Hayter may include infill and step-out drilling at up to
13 identified locations. Operating expense reduction projects such as low
pressure water disposal wells, horizontal disposal wells, and battery
optimization are ongoing. In addition to cost reduction initiatives, Harvest
believes it can capitalize on condensate blending opportunities to increase oil
price realizations.
Killarney
The Killarney property was acquired by Harvest in two transactions in April and
June 2003. Current production from the property is 1,105 boe/d of 20(Degree) API
oil, producing from the Lower Cretaceous Cummings/Dina formation. Harvest has an
average 91% working interest in this operated property. OOIP at Killarney is
estimated at 51 mmbbls on Harvest's working interest acreage.
Future development at Killarney will primarily be focused on low pressure water
disposal to increase operating cost efficiencies through power reduction as well
as increased fluid handling leading to increased oil production.
Thompson Lake
Thompson Lake was one of the first properties acquired by Harvest in July 2002.
Current production from this property is 887 boe/d of 27(Degree) API oil,
producing from the Glauconite A pool. Harvest has an average 99% working
interest in this operated property. OOIP at Thompson Lake is estimated at 50
mmbbls on Harvest's working interest acreage.
Future development at Thompson Lake will be focused on ongoing operating expense
reduction as well as increased fluid handling leading to increased oil
production.
29
Amisk
The Amisk property was acquired by Harvest in June 2003. Current production from
the property averages approximately 550 boe/d of 20(Degree) API oil. Harvest has
an average 75% working interest in this operated property.
Future development at Amisk will primarily be focused on reducing operating
expenses through power reduction resulting from low pressure water disposal.
Czar
Harvest's Czar property was acquired in June 2003. Current production from Czar
averages approximately 367 boe/d of 16(Degree) API oil, producing from the Dina
formation. Harvest has an average 100% working interest in this operated
property.
Future development at Czar may include some sweet gas production in the latter
half of 2005.
Halkirk / Leahurst
The Halkirk/Leahurst properties are located near Stettler, Alberta and were
acquired by Harvest in September 2004. Current production from these properties
averages approximately 805 boe/d of 36(Degree) API oil, producing from the
Glauconite formation. A small amount of slightly sour gas is produced from this
area as well. Harvest has 70% working interest in Leahurst and 96% in Halkirk.
Future development at Halkirk/Leahurst will primarily be focused on waterfloods
and reactivation of shut-in wells. Some infill drilling is planned for later in
2005.
Southern Alberta
The properties within the Southern Alberta core area are located from T13-R6-W4M
to T29-R29-W4M and produce both crude oil and natural gas. Harvest acquired all
Southern Alberta properties from EnCana in September 2004, and formed a new core
area. The following table summarizes the key characteristics of this core
operating area:
Proved Reserves:
Oil (mbbl) 12,864.2
NGL (mbbl) 1,376.7
Natural gas (mmcf) 52,688.8
- -------------------------------------------------------------------------
Total (mboe) 23,022.4
PV10 ($000) 323,223.3
Current Production (boe/d) 12,723
Producing wells 295
Ownership 85%
Operatorship 100%
Average area operating expenses ($/boe) $5.21
Suffield
Current production from this region is 6,900 boe/d of heavy oil, averaging
11-18(Degree) API from the Upper Mannville Glauconitic formation. Harvest has an
average 99% working interest in this operated property. OOIP at Suffield is
estimated at 170 mmbbls of oil on Harvest's working interest acreage.
Future development at Suffield may include step-out, extension and infill
drilling at up to 65 identified locations, as well as increased fluid handling
capacities. Pool optimization projects may target increased production and
generate economic oil production with increased water cuts to outperform
engineering reserve estimates.
Crossfield
Current production from this region is primarily natural gas with some liquids,
and averages approximately 2,730 boe/d from the Lower Cretaceous Basal Quartz
formation. Harvest has an average 75% working interest in this operated
property. Original Gas In Place (OGIP) at Crossfield is estimated at 400 bcf of
natural gas on Harvest's working interest acreage, with another 150-180 bcf not
exposed. Future development at Crossfield will include infill
30
and step-out drilling at up to 12 identified locations and field compression to
increase the recovery factor and accelerate production.
Cavalier
Current production from this region is 2,190 boe/d of primarily light crude oil
averaging 30-36(Degree) API. Production is from the Upper Mannville Glauconitic
formation. Harvest has an average 96% working interest in this operated
property.
Future development at Cavalier may include waterflood/reservoir management and
optimization, and infill drilling to increase the recovery factor and accelerate
production.
Badger
Current production from this region is 800 boe/d of medium crude oil averaging
21(Degree) API and natural gas produced from the Upper Mannville Glauconitic
Formation. Harvest has an average 100% working interest in this operated
property. OOIP at Badger is estimated at 14 mmbbls and OGIP is estimated at 6
bcf on Harvest's working interest acreage.
Future development at Badger may include infill drilling, waterflood
optimization, and reservoir management to increase the recovery factor.
Southeast Saskatchewan
The properties within the southeast Saskatchewan core area are located from
T5-R31-W1M to T13-R9-W2M and produce primarily light gravity crude oil. Harvest
acquired the properties in October 2003. The following table summarizes the key
characteristics of this core operating area:
Proved Reserves:
Oil (mbbl) 14,675.7
NGL (mbbl) 229.2
Natural gas (mmcf) 1,307.7
- --------------------------------------------------------------------------
Total (mboe) 15,122.9
PV10 ($000) 161,904.3
Current Production (boe/d) 5,619
Producing wells 448
Ownership 98%
Operatorship 99%
Average area operating expenses ($/boe) $10.08
Hazelwood
Current production from Hazelwood is 2,840 boe/d of average 33(Degree) API crude
oil produced from the Tilston Formation. Harvest has an average 99% working
interest in this operated property. OOIP at Hazelwood is estimated at 160 mmbbls
on Harvest's working interest acreage.
Future development at Hazelwood may include step-out and horizontal infill
drilling at up to 45 locations to increase the recovery factor and accelerate
production. Harvest believes further drilling opportunities are possible through
the continued pooling of landowner interests to drill under-exploited areas.
Harvest's extensive proprietary 3D seismic coverage offers control of the
opportunity. An extensive workover program is available to increase oil
production.
Whitebear/Big Marsh
Current production from Whitebear/Big Marsh is 710 boe/d of average 34(Degree)
API crude oil produced from the Tilston Formation. Harvest has an average 100%
working interest in this operated property. OOIP at Whitebear/Big Marsh is
estimated at 85 mmbbls on Harvest's working interest acreage.
31
Future development at Whitebear/Big Marsh may include infill drilling at three
identified locations, water handling upgrades and water control measures to
increase the recovery factor. Harvest's extensive proprietary 3D seismic
coverage offers control of the opportunity to increase oil production through
horizontal infill drilling.
Flinton/ Corning
Current production from the Flinton / Corning area is 780 boe/d of average
28.4(Degree) API crude oil produced from the Tilston Formation. Harvest's
average working interest in this operated property is 100%. OOIP at Flinton is
estimated at 80 mmbbl on Harvest's working interest acreage.
Future development in this area may include infill drilling at 2 identified
locations.
Moose Valley
Current production from Moose Valley is 815 boe/d of average 27.8(Degree) API
crude oil produced from the Tilston Formation. Harvest's average working
interest in this operated property is 95%. OOIP at Moose Valley is estimated at
over 47 mmbbl on Harvest's working interest acreage.
Future development in this area may include downspaced infill drilling.
North Central Alberta
The properties within the North Central Alberta core area are located from
T83-R7-W5M to T89-R15-W5M and produce primarily light gravity crude oil and
natural gas. Harvest acquired all North Central Alberta properties when it
acquired Storm in June 2004, and formed a new core area. The following table
summarizes the key characteristics of this core operating area:
Proved Reserves:
Oil (mbbl) 7,288.3
NGL (mbbl) 336.7
Natural gas (mmcf) 5,818.0
- --------------------------------------------------------------------------
Total (mboe) 8,594.7
PV10 ($000) 133,862.1
Current Production (boe/d) 3,443
Producing wells 156
Ownership 50%
Operatorship 75%
Average area operating expenses ($/boe) $5.08
Evi 1
Evi 1 was acquired by Harvest in June of 2004 and current production averages
1,420 BOE/d of 39(Degree) API from the Slave Point / Granite Wash Formations.
Harvest has an average 58% working interest in this operated property. Potential
development may include new completions and step-out drilling.
Evi 3 / Kitty
Evi 3 and Kitty were acquired in June, 2004 and current production averages 510
BOE/d of 39(Degree) API also from the Slave Point / Granite Wash Formations.
Harvest has an average 67% working interest in this operated property.
Future development in these areas may include production optimization
opportunities, efficiency improvements, step-out drilling and waterflood
implementation.
Loon Lake
Current production from Loon Lake is approximately 670 boe/d of oil averaging
39(Degree) API from the Devonian Slave Point and Granite Wash Formations.
Harvest has an average 45% working interest in this operated property. OOIP at
Loon Lake Slave Point and Granite Wash is estimated at over 55 mmbbls on
Harvest's working interest acreage.
32
Future development at Loon Lake may include downspace drilling in the Slave
Point at up to 32 locations, as well as potential waterflood to increase the
recovery factor and flatten production profiles. Future development in the
Granite Wash may include utilization of Harvest's extensive 3D seismic inventory
to identify future drilling locations, step-out and infill drilling up to 15
locations, as well as production optimization opportunities.
Red Earth
Current production in Red Earth proper as well as miscellaneous other Red Earth
properties averages approximately 440 boe/d of 39(Degree) API gravity crude oil
from the Slave Point / Granite Wash Formations. Harvest has an average 68%
working interest in this operated property.
Incremental Exploitation and Development Potential
Management of the Corporation has identified numerous development opportunities,
many of which provide the potential for capital investment and incremental
production beyond that identified in 3rd party Reserve Reporting. Opportunities
being considered include:
o Implementation or optimization of waterfloods in selected pools resulting
in increased production and recovery;
o Increasing water handling and water disposal capacity at key fields to add
incremental oil volumes. This includes additional use of free water
knock-outs and additional disposal wells;
o Debottlenecking existing fluid handling facilities and surface
infrastructure;
o Optimizing field oil cut management through the shut-in of select wells
and increased total fluid from offset higher oil cut wells. Shut-in wells
would be available for restart as oil cuts vary;
o Uphole completions of bypassed or untested reserves in existing wellbores,
including recompletion of existing shut-in wells to access undrained
reserves;
o Selected infill and step-out development drilling opportunities for
various proven targets generally defined by 3D seismic; and
o Numerous exploratory opportunities defined by seismic from which value
might be extracted by sale, farmout or joint venture.
Oil And Natural Gas Wells
The following table sets forth the number and status of wells in which the
Operating Subsidiaries have a working interest as at December 31, 2004.
Oil Wells Natural Gas Wells
----------------------------- -----------------------------
Producing Non-Producing Producing Non-Producing
-------------- ------------- ------------- -------------
Gross Net Gross Net Gross Net Gross Net
----- ----- ----- ----- ----- ----- ----- -----
Alberta 1,733 1,417 265 240 78 22 4 3
Saskatchewan 440 416 208 196 8 8 4 4
----- ----- ----- ----- ----- ----- ----- -----
Total 2,173 1,833 473 436 86 30 8 7
===== ===== ===== ===== ===== ===== ===== =====
33
Properties with no Attributable Reserves
The following table sets out the Operating Subsidiaries' undeveloped land
holdings as at January 1, 2005.
Undeveloped Acres
---------------------------------------------------------
Gross Net
----- ---
Alberta 307,722 235,002
British Columbia 35,882 8,660
Saskatchewan 118,368 115,457
-------- ----------
Total 461,972 359,119
-------- ----------
- -------------------------------------------------------------------------------
Undeveloped Acres for which rights expire within one year
---------------------------------------------------------
Gross Net
----- ---
Alberta 54,789 49,185
British Columbia 3,199 799
Saskatchewan 19,167 11,894
-------- ----------
Total 77,155 61,878
-------- ----------
Forward Contracts
For details of material commitments to sell natural gas and crude oil which were
outstanding at December 31, 2004 - see note 16 to the Consolidated Financial
Statements contained on pages 59 to 62 in the Trust's annual report, which pages
are incorporated herein by reference.
Additional Information Concerning Abandonment and Reclamation Costs
The following table sets forth information respecting future abandonment and
reclamation costs for surface leases, wells, facilities and pipelines which are
expected to be incurred by the Operating Subsidiaries and for the periods
indicated:
Abandonment & Reclamation costs net Abandonment & Reclamation costs net
of salvage value (undiscounted and of salvage value (discounted at 10%
using a 2% inflation rate) using a 2% inflation rate)
Period ($000) ($000)
- --------------------------------------- ----------------------------------- ------------------------------------
Total as at Dec. 31, 2004 88,591 25,139
Anticipated to be paid in 2005 307 292
Anticipated to be paid in 2006 436 378
Anticipated to be paid in 2007 628 495
The number of net wells for which the Independent Reserve Engineering Evaluators
estimated that the Operating Subsidiaries would incur abandonment and
reclamation costs is 1,741.6 wells (Proved plus Probable).
Abandonment costs (excluding salvage values) associated only with wells were
deducted by the Independent Reserve Engineering Evaluators in estimating future
net revenue in the Reserve Report. Abandonment costs associated with facilities,
pipelines and no reserve addition ("NRA") wells are excluded from the table
above. The estimated future undiscounted expense related to facilities,
pipelines and NRA wells is $168.1 million ($45.5 million
34
discounted at 10%). The nature of these expenses are not expected to change the
anticipated costs for the next three years as they will not be incurred until
the end of a field's reserve life profile.
Capital Expenditures
The following tables summarize capital expenditures (net of incentives and net
of certain proceeds and including capitalized general and administrative
expenses) related to the Operating Subsidiaries' activities for the year ended
December 31, 2004 ($000):
Property acquisition costs
Proved properties 689.8
Undeveloped properties 16.2
-----------------------------------------------------------
Total acquisition costs 706.0
Exploration costs --
Development costs 42.7
------
Total Capital Expenditures 748.7
======
Exploration and Development Activities
The following table sets forth the gross and net exploratory and development
wells in which the Operating Subsidiaries participated during the year ended
December 31, 2004:
Exploratory Wells Development Wells
--------------------- ------------------------
Gross Net Gross Net
------- ------- ------- -------
Light Oil -- -- 17 17
Heavy Oil -- -- 10 9.54
Natural Gas -- -- -- --
Service -- -- 4 3.96
Dry -- -- -- --
---- ---- ---- -----
Total: -- -- 31 30.5
==== ==== ==== =====
During 2005, the Operating Subsidiaries plan to drill 70 net wells (83 gross).
The Operating Subsidiaries will continue the development drilling program in
Southeast Saskatchewan started in 2004, and are targeting to drill 15 net wells
for Tilston oil production. The Operating Subsidiaries have commenced a
development drilling program in Southern Alberta, with approximately 25 net
wells targeted, and plan to undertake projects such as battery optimization and
consolidation to reduce operating costs. The Operating Subsidiaries will
continue development drilling with approximately 5 locations targeted in Hayter,
although the area has become less of a focal point for the Operating
Subsidiaries. The Operating Subsidiaries are also continuing with a program to
add low pressure water disposal to reduce operating costs by reducing
consumption of electricity.
Production Estimates
The following table sets out the volume of the Operating Subsidiaries' net
production estimated for the year ended December 31, 2005 which is reflected in
the estimate of future net revenue disclosed in the tables contained under "-
Disclosure of Reserves Data" and forecast by the Independent Reserve Engineering
Evaluators.
35
Light and Natural Gas
Medium Oil Heavy Oil Natural Gas Liquids BOE
(bbls/d) (bbls/d) (mcf/d) (bbls/d) (BOE/d)
---------- ---------- ------------ ----------- ---------
Proved Producing 12,731 14,007 27,989 852 32,254
Proved Developed Non-Producing 78 0 1,361 10 315
Proved Undeveloped 521 158 651 23 810
Total Proved 13,330 14,164 30,001 884 33,379
Total Probable 933 879 2,455 53 2,274
Total Proved Plus Probable 14,263 15,043 32,456 937 35,653
Suffield is the Operating Subsidiaries' largest producing property representing
18% of forecast 2005 production. It is forecast by the Reserve Evaluators to
produce 6,527 Bbl/d of the estimated total 35,653 Bbl/d.
Production History
The following tables summarize certain information in respect of production,
product prices received, royalties paid, operating expenses and resulting
netback for the periods indicated below:
2004
---------------------------------------------------------------------------
Average Daily Production Volumes Q1 Q2 Q3 Q4 Total
(before the deduction of royalties) --------- --------- --------- --------- ---------
Light Oil (bopd) 5,053 5,216 9,087 12,228 7,911
Medium Oil (bopd) 4,150 4,082 5,416 3,644 4,324
Heavy Oil (bopd) 5,423 5,477 7,894 15,120 8,495
- --------------------------------------------------------------------------------------------------------------------------
Total Oil (bopd) 14,626 14,775 22,397 30,992 20,730
NGL (blpd) 50 141 377 1,309 471
Natural Gas(mcfd) 915 2,249 11,909 28,338 10,903
- --------------------------------------------------------------------------------------------------------------------------
Total Daily Production (BOE/d) 14,829 15,291 24,759 37,024 23,019
==========================================================================================================================
Total Sales Production:
Light Oil (bbl) 459,823 474,656 836,004 1,124,976 2,895,426
Medium Oil (bbl) 377,650 371,462 498,272 335,248 1,582,584
Heavy Oil (bbl) 493,493 498,407 726,248 1,391,040 3,109,170
- --------------------------------------------------------------------------------------------------------------------------
Total Oil (bbl) 1,330,966 1,344,525 2,060,524 2,851,264 7,587,180
NGL (bbl) 4,550 12,831 34,684 120,428 172,386
Natural Gas (mcf) 83,265 204,659 1,095,628 2,607,096 3,990,498
- --------------------------------------------------------------------------------------------------------------------------
Total Production (BOE) 1,349,439 1,391,481 2,277,828 3,406,208 8,424,954
==========================================================================================================================
36
Average Sales Prices Received: 2004
----------------------------------------------------------------------
Q1 Q2 Q3 Q4 Total
------ ------ ------ ------ ------
Natural Gas (mcf) $ 5.46 $ 5.91 $ 6.22 $ 5.68 $ 6.30
Heavy Oil ($/bbl) 28.79 33.53 37.64 28.73 31.11
Medium Oil ($/bbl) 36.44 36.95 43.54 35.55 38.78
Light Oil ($/bbl) 41.09 44.28 53.46 53.64 48.70
- -------------------------------------------------------------------------------------------------------------------
Total Oil ($/bbl) 34.89 38.42 45.84 38.52 39.42
- -------------------------------------------------------------------------------------------------------------------
NGL ($bbl) 35.00 30.39 45.69 33.19 41.10
- -------------------------------------------------------------------------------------------------------------------
BOE - 6:1 $ 35.20 $ 38.13 $ 44.83 $ 37.77 $ 39.33
===================================================================================================================
Royalties Paid
2004
---------------------------------------------------------------------
Q1 Q2 Q3 Q4 Total
------ ------ ------- ------- -------
Heavy Oil ($000) 2,463 2,375 4,674 6,449 15,962
Medium & Light Oil ($000) 5,391 5,780 10,357 12,908 34,436
Natural gas & NGL's ($000) 172 150 1,669 1,848 3,838
- --------------------------------------------------------------------------------------------------------------
Total BOE ($000) 8,026 8,305 16,700 21,205 54,236
- --------------------------------------------------------------------------------------------------------------
Heavy Oil ($/bbl) 4.99 4.77 6.44 4.64 5.13
Medium & Light Oil ($/bbl) 6.44 6.83 7.76 8.84 7.69
Natural gas & NGL's ($/boe) 9.34 3.19 7.68 3.33 4.58
- --------------------------------------------------------------------------------------------------------------
Total BOE ($/boe) $ 5.95 $ 5.97 $ 7.33 $ 6.23 $ 6.44
- --------------------------------------------------------------------------------------------------------------
Operating Expenses(1)
2004
---------------------------------------------------------------------
Q1 Q2 Q3 Q4 Total
------- ------- ------- ------- ------
Heavy Oil ($000) 4,814 4,213 4,906 8,268 22,989
Medium & Light Oil ($000) 8,828 9,143 13,148 15,548 45,921
Natural gas & NGL's ($000) 32 244 939 3,359 4,532
- --------------------------------------------------------------------------------------------------------------
Total BOE ($000) 13,674 13,600 18,993 27,175 73,442
- --------------------------------------------------------------------------------------------------------------
Heavy Oil ($/bbl) 9.76 8.45 6.76 5.70 7.03
Medium & Light Oil ($/bbl) 10.54 10.81 9.85 9.39 10.01
Natural gas & NGL's ($/BOE) 1.71 5.19 4.32 6.07 5.47
- --------------------------------------------------------------------------------------------------------------
Total BOE ($/BOE) $ 10.13 $ 9.77 $ 8.34 $ 7.37 $ 8.48
- --------------------------------------------------------------------------------------------------------------
(1) Includes impact of power hedge gains and losses
Netback Received(2)
2004
--------------------------------------------------------------------------
Q1 Q2 Q3 Q4 Total
------- ------- ------- ------- --------
Heavy Oil ($/bbl) 14.04 20.31 24.45 18.39 18.94
Medium & Light Oil ($/bbl) 22.01 23.42 32.14 31.26 27.49
Natural gas & NGL's ($/BOE) 22.26 25.69 26.66 24.49 28.43
- -------------------------------------------------------------------------------------------------------------------
Total BOE ($/BOE) $ 19.12 $ 22.39 $ 29.16 $ 24.17 $ 24.41
- -------------------------------------------------------------------------------------------------------------------
(2) Before gains or losses on commodity derivatives
37
DESCRIPTION OF THE TRUST
General
The Trust is an open-ended, unincorporated investment trust established under
the laws of the Province of Alberta. The Trust is not managed by a third party
manager. Instead, the Trust is managed by the Corporation, its wholly-owned
subsidiary, pursuant to the Trust Indenture and the Administration Agreement.
The Trust was established for the purposes of:
(a) acquiring the NPI and similar interests from the Corporation and
similar interests and acquiring Direct Royalties;
(b) making payments to the Corporation, to the extent of the Trust's
available funds, for 99% of the Corporation's cost of (including any
amount borrowed to acquire) any Canadian resource property acquired
by the Corporation, and the cost of (including any amount borrowed
to fund) certain designated capital expenditures in relation to the
Properties;
(c) acquiring or investing in securities of the Corporation and in the
securities of any other entity including, without limitation, bodies
corporate, partnerships or trusts that are Permitted Investments,
and borrowing funds or otherwise obtaining credit for that purpose;
(d) disposing of any part of the Trust Fund, including, without
limitation, any securities of the Corporation;
(e) temporarily holding cash and investments for the purposes of paying
the expenses and the liabilities of the Trust, making other
investments as contemplated by the Trust Indenture, paying amounts
payable by the Trust in connection with the redemption of any Trust
Units, and making distributions to Unitholders; and
(f) paying costs, fees and expenses associated with the foregoing
purposes or incidental thereto.
See "Description of the Trust - Cash Available For Distribution" and
"Description of the Trust - Distributable Cash".
The NPI and Direct Royalties
Overview
The NPI consists of the right to receive a monthly payment from the Operating
Subsidiaries pursuant to the terms of the NPI Agreements, equal to the amount by
which ninety-nine (99%) percent of the gross proceeds from the sale of
production attributable to Property Interests for such month (the "NPI
Revenues") exceed ninety-nine (99%) percent of certain deductible production
costs for such period. The residual 1% share of gross proceeds from the sale of
production that does not form part of the NPI is retained by the Operating
Subsidiaries, together with any income derived from Properties that are not
Working Interests in Canadian resource properties (including the Corporation's
1% share of income from the royalty interests from which the Direct Royalties
are derived). This residual revenue is used to defray certain expenses and
capital expenditures of the Operating Subsidiaries.
In calculating the NPI, the Operating Subsidiaries deduct various costs and
expenses. The Trust also reimburses the Operating Subsidiaries for Crown
royalties and other Crown charges that are not deductible for income tax
purposes and are payable by the Operating Subsidiaries in respect of production
from or ownership of the Corporation's Properties. The Operating Subsidiaries
are entitled to set off the right to be so reimbursed against the obligation to
pay the NPI.
38
Pursuant to the NPI Agreements, the Trust must pay to the Operating Subsidiaries
the Deferred Purchase Price Obligation. To satisfy the Deferred Purchase Price
Obligation, the net proceeds of any issue of the Trust Units or the proceeds
from the disposition of the NPI on any Properties are paid to the Corporation.
The Trust is not required to pay an amount as a Deferred Purchase Price
Obligation except to the extent the Trust has such proceeds available. See
"Deferred Purchase Price Obligation" below for a more detailed description of
the Deferred Purchase Price Obligation.
Pursuant to the NPI Agreements, substantially all of the economic benefit
derived from the assets of the Operating Subsidiaries accrues to the benefit of
the Trust and ultimately to the Unitholders. The term of each of the NPI
Agreements is for so long as there are petroleum and natural gas rights to which
the NPI Agreement applies.
In addition to the NPI, the Trust owns a beneficial interest in the Direct
Royalties and the Trust may acquire further Direct Royalties. Such Direct
Royalties may consist of direct petroleum and natural gas royalty interests and
may be acquired from time to time.
Deferred Purchase Price Obligation
Pursuant to the NPI Agreements, the Deferred Purchase Price Obligation consists
of an ongoing obligation of the Trust to pay to the Operating Subsidiaries, to
the extent of the Trust's available funds, an amount equal to the sum of the
following, less amounts financed by the Operating Subsidiaries from debt:
(a) the portion of acquisition costs incurred by the Operating
Subsidiary from time to time which are attributable to Canadian
resource property; plus
(b) certain designated drilling, completion, equipping and other costs,
in respect of the Properties; plus
(c) the portion of indebtedness incurred in respect of such acquisition
costs and capital expenditures, payable at the time of satisfaction
by the Corporation of such indebtedness.
To satisfy the Deferred Purchase Price Obligation, the Trust is required to pay
over to the Corporation the net proceeds of any issue of the Trust Units or the
proceeds from the disposition of the NPI of any Properties held by the
Corporation. The Trust is not obligated to pay an amount as a Deferred Purchase
Price Obligation except to the extent the Trust has such proceeds available.
To the extent that the Corporation designates an expenditure as a Deferred
Purchase Price Obligation:
(a) if the designated expenditure is funded by issuing additional Trust
Units, by the proceeds of dispositions of the Canadian resource
property component of Properties, by the disposition of Direct
Royalties or by the issuance of debt, it will not be a charge
against the income from the NPI, and therefore will not reduce
payments of income from the NPI to the Trust or distributions to
Unitholders;
(b) the Trust will be obliged to pay to the Corporation 99% of the
amount of the designated expenditure to the extent not funded by
borrowing by the Corporation;
(c) the cost to the Trust of the designated expenditure will be added to
the Canadian oil and natural gas property expenditures account of
the Trust, thus creating additional tax deductions (see "Canadian
Federal Income Tax Considerations"); and
(d) the additional revenue generated from the Properties acquired by the
designated expenditure will be added to the revenues used to
calculate income from the NPI, thereby potentially increasing the
amount payable to the Trust under the NPI Agreements.
39
Reserve Fund
Under the NPI Agreements, the Operating Subsidiaries are entitled to pay such
amounts of the revenues received from Production and other income received by
the Corporation in respect of the Properties into the Reserve Fund if, as and
when the Corporation determines, in its reasonable discretion, that it is
prudent to do so in accordance with prudent business practices, to provide for
payment of production costs that the Corporation estimates will or may become
payable in the next six months for which there may not be sufficient revenues to
satisfy such costs in a timely manner. Funds retained by the Corporation in the
Reserve Fund are required to be used by the Corporation to fund the payment of
production costs. To the extent that funds are drawn from the Reserve Fund and
used to pay production costs, such amounts will be deducted from the NPI.
Reclamation Fund
Each of the Operating Subsidiaries are liable for their share of ongoing
environmental obligations and for the ultimate reclamation of the Properties
upon abandonment. Pursuant to the NPI Agreements, the Operating Subsidiaries
have established a funding strategy for the purpose of funding currently
estimated future environmental and reclamation obligations. To the extent that
funds from the reclamation funds are used for site restoration and well and
facility abandonment expenditures such amounts are deducted in calculating
income from the NPI.
Ongoing environmental obligations are expected to be funded out of debt and cash
flow. Those obligations will reduce the amount of income from the NPI payable to
the Trust. At this time, the Operating Subsidiaries have not established either
a separate bank or investment account to segregate funds to finance these
obligations.
In addition to the identified producing wells and wells capable of production,
the Properties include interests in approximately 519 gross (495 net) active
injection, disposal or service wells and 738 gross (640 net) suspended or
shut-in wells, all of which have been included in the total estimate of the
Corporation's future environmental and reclamation obligations.
Cash Available For Distribution
Cash Available For Distribution consists of any amounts received by the Trust
pursuant to the NPI and the Direct Royalties, any interest or other income from
Permitted Investments, ARTC received by the Trust net of non-deductible Crown
royalties that are reimbursed by the Trust to the Operating Subsidiaries,
dividends on the shares of the Operating Subsidiaries or any other dividends on
securities of the Operating Subsidiaries less all expenses and liabilities of
the Trust, including debt service costs, which are due or accrued and which are
chargeable to income.
Pursuant to the Trust Indenture and the Administration Agreement, the
Corporation calculates income from the NPI for each calendar month and arranges
for payment of certain direct expenses of the Trust from the NPI.
The actual amount of Cash Available For Distribution depends on, among other
things, the quantity and quality of crude oil, natural gas and natural gas
liquids produced, prices received for such production, direct expenses of the
Trust, taxes, operating costs, transportation and processing costs, capital
expenditures, debt service costs, Crown and other royalties, other Crown
charges, net contributions to the reclamation funds, net contributions by the
Operating Subsidiaries to the Reserve Fund, and general and administrative costs
of the Trust and the Operating Subsidiaries. See "Risk Factors".
The Operating Subsidiaries also have the discretion to incur debt or retain cash
in order to modify seasonal and other variations in Cash Available For
Distribution. Unitholders may also receive distributions of the net proceeds
received from sales of Properties to the extent the Corporation determines not
to use those proceeds to acquire additional Properties.
40
Delay in Cash Available For Distribution
In addition to the usual delays in payment by purchasers of oil and natural gas
to the operator of the Properties, and by the operator to the Operating
Subsidiaries or the Trust, payments between any of such parties may also be
delayed by restrictions imposed by lenders, delays in the sale or delivery of
products, delays in the connection of wells to a gathering system, blowouts or
other accidents, recovery by the operator of expenses incurred in the operation
of Properties, or the establishment by the operator of reserves for such
expenses.
Capital Fund
The Trust retains up to 50% of the Cash Available For Distribution to finance
future acquisitions and development of Properties with the intent that it will
be able to continue to provide or maintain the Cash Available For Distribution
over a longer period of time than would otherwise be the case. The Trust does
not maintain a separate bank or investment account in which it maintains such
amounts. To the extent Cash Available for Distribution is not distributed to
unitholders, it is invested in acquisitions and development of Properties or
used to repay debt of the Trust or the Operating Subsidiaries.
Distributable Cash
Distributable Cash consists of the balance of the Cash Available For
Distribution after the retention of funds by the Trust for the Capital Fund,
which is distributed to Unitholders.
Unitholders of record on a Record Date are entitled to receive monthly cash
distributions of the Distributable Cash which will become payable on the 15th
day following the Record Date, and if such date of payment is not a Business Day
on the next Business Day after the 15th day following the Record Date.
Income Tax Treatment
Any amounts paid by the Trust in respect of acquisition costs and the Deferred
Purchase Price Obligation is COGPE of the Trust in the year incurred. The
Trust's share of any proceeds of disposition of Canadian resource properties
which are receivable as a result of the release of the NPI will reduce the
Trust's cumulative COGPE. In determining the portion of Distributable Cash that
is taxable to a Unitholder, the Trust is entitled to an annual deduction in
respect of its cumulative COGPE account, resource allowance, general and
administrative and capitalized issue expenses in accordance with the provisions
of the Tax Act. Any portion of Distributable Cash to Unitholders that is not
taxable in the Trust is treated as a return of capital and reduces the adjusted
cost base of Trust Units held as capital property by a Unitholder. In this
respect, the taxation of capital distributions is deferred until an actual or
deemed disposition of Trust Units occurs or a holder's Trust Units have an
adjusted cost base which is less than zero. See "Canadian Federal Income Tax
Considerations".
Board of Directors
The Corporation currently has a board of directors consisting of 5 individuals,
and has presented a slate of 6 directors to the unitholders at the 2005 Annual
General Meeting. Pursuant to the Trust Indenture, Unitholders are entitled to
elect the Board of Directors annually. Prior to all annual meetings, the
Corporation will deliver an information circular and form of proxy to
Unitholders with respect to the election of the directors of the Corporation at
any such meeting. See "Information Respecting the Corporation - Directors and
Officers of the Corporation".
Delegation of Authority, Administration and Trust Governance
The Corporation (and, accordingly, the Board of Directors of the Corporation)
has generally been delegated the significant management decisions of the Trust.
In particular, the Trustee has delegated to the Corporation responsibility for
any and all matters relating to the following: (i) an offering of securities;
(ii) ensuring compliance with all applicable laws, including in relation to an
offering; (iii) all matters relating to the content of any offering documents,
the accuracy of the disclosure contained therein, and the certification thereof;
(iv) all matters concerning the terms of, and amendment from time to time of the
material contracts of the Trust; (v) all matters concerning any
41
underwriting or agency agreement providing for the sale of Trust Units or rights
to Trust Units; (vi) all matters relating to the redemption of Trust Units;
(vii) all matters relating to the voting rights on any investments in the Trust
Fund or any Subsequent Investments; (viii) all matters relating to the specific
powers and authorities as set forth in the Trust Indenture.
Under the NPI Agreements, the Operating Subsidiaries have the exclusive control
and authority over development of, and recovery of petroleum, natural gas and
natural gas liquids from, the Properties and lands pooled or unitized therewith,
including, without limitation, making all decisions respecting whether, when and
how to drill, complete, equip, produce, suspend, abandon and shut-in wells and
whether to elect to convert royalties to working interests. The Harvest Board
has determined that all significant operational decisions and all decisions
relating to: (i) the acquisition and disposition of properties for a purchase
price or proceeds in excess of $5 million; (ii) the approval of capital
expenditure budgets; (iii) the approval of risk management policies and
activities proposed to be undertaken, and (iv) the establishment of credit
facilities, shall be made by the Board of Directors.
In exercising its powers and discharging its duties, the Corporation must act
honestly and in good faith and exercise the degree of care, diligence and skill
that a reasonably prudent oil and natural gas industry advisor and administrator
would exercise in comparable circumstances. The Corporation's objective in
exercising its powers and discharging its duties is to maximize the income
distributable to the Unitholders to the extent consistent with long-term growth
in the value of the Trust. In pursuing such an objective, the Corporation
employs and will continue to employ prudent oil and natural gas business
practices. All of the Corporation's business is and will continue to be
conducted in accordance with applicable laws with a view to the best interests
of the Unitholders and the Trust.
The Harvest Board reviews on an ongoing basis both the nature and extent of the
services required of the Corporation by the Trust and the costs of providing
such services.
General and administrative costs are deducted from production revenues in
computing income from the NPI to the extent not paid from the residual income of
the Corporation or deducted by the Trust in computing Cash Available For
Distribution. General and administrative costs are generally charged to the
Trust by the Corporation based on direct costs incurred in fulfilling the
obligations of the Corporation to the Trust pursuant to the Trust Indenture and
the Administration Agreement. The Corporation is entitled to reimbursement for
all of its direct and indirect expenses, costs and expenditures in connection
with the creation, start-up, set-up and organization of the Trust.
Borrowing by the Trust
Equity Bridge Notes
On July 28, 2003, the Trust entered into the Equity Bridge Notes with the Bridge
Lenders which provide for advances of up to $40 million to the Trust to assist
with the payment of the Deferred Purchase Price Obligation in connection with
the acquisition of certain oil and natural gas properties. On July 29, 2003,
Harvest received $11 million in advances pursuant to the Equity Bridge Notes to
fund the deposit relating to the purchase of such properties. On September 29,
2003, the Equity Bridge Notes were amended to permit advances to be used to pay
out the Prior Bank Facility and the Trust entered into the Bridge Notes. The
Bridge Notes provided for advances of up to $30 million to the Trust to assist
with the payment of the Deferred Purchase Price Obligations as a result of the
acquisition of the Southeast Saskatchewan Properties and to repay outstanding
bank debt. No commitment or arrangement fee was earned by the Bridge Lenders
through the provision of the Bridge Agreements.
The terms of the Bridge Agreements call for quarterly interest payments to be
made to the Bridge Lenders in arrears due on the first business day following a
calendar quarter. The payments are calculated daily at a fixed rate of 10% per
annum using a 365 or 366 (as the case may be) year. Under the Equity Bridge
Notes, the Trust has the option to settle the quarterly interest payments with
cash or, subject to receipt or applicable regulatory approval, the issue of
Trust Units. If the Trust elects to issue Trust Units the Trust is required to
give the Bridge Lenders at least 5 business days notice. The number of Trust
Units to be issued to the Bridge Lenders to settle a quarterly payment shall be
equivalent to the quarterly payment amount divided by 90% of the ten-day
weighted average trading price of the Trust Units on TSX over the last 10
trading days of the calendar quarter.
42
The Trust also has the option to repay the principal amounts outstanding at any
time. The Trust is required to give the Bridge Lenders ten business days written
notice prior to the Trust's repayment of principal. If the Trust chooses to
partially repay the outstanding principal amount, such payment is to be made in
cash. Under the Equity Bridge Notes, if the Trust elects to repay the full
principal amount plus the accrued quarterly payment at maturity, the Trust then
has the option to settle its obligation with cash or, subject to receipt of
applicable regulatory approvals, the issue of Trust Units. If the Trust elects
to issue Trust Units, the Trust is required to give the Bridge Lenders at least
five business days notice. The number of Trust Units to be issued to the Bridge
Lenders to settle the principal amount and accrued quarterly payment amount
shall be equivalent to the sum of the principal and accrued quarterly payment
amounts divided by 90% of the ten-day weighted average trading price of the
Trust Units on TSX over the last ten trading days immediately prior to the date
that the obligation will be settled.
The equity bridge lenders have agreed to subordinate their interests to any
claims of the Bank Lenders. Security has been provided in the form of
second-priority fixed and floating debentures on all of Harvest Energy Trust's
assets. The equity bridge lenders may demand payment of the full amount if
specified events of default under the equity bridge note agreements occur,
including cross default to any other indebtedness of Harvest, an unacceptable
change in Harvest management or trustee, a change in control of Harvest,
suspension or cease trading of the trust units of Harvest on any stock exchange
or if the lender believes there has been a material adverse change or that
repayment or the collateral security has been impaired or is in jeopardy.
Covenants include a negative covenant not to make distributions during an event
of default or if it would materially limit its ability to meet obligations under
the equity bridge notes. The Trust does not have the option to issue Trust Units
to satisfy its repayment obligations if an event of default occurs.
On October 16, 2003, the Corporation repaid $8.5 million of the Equity Bridge
Notes (resulting in $25 million being outstanding thereunder) and $25 million of
the Bridge Notes resulting in no amount being outstanding thereunder through
drawings under the Current Bank Facility.
On January 2, 2004 Harvest paid $0.665 million in accrued interest in respect of
equity bridge principal outstanding during the fourth quarter of 2003. On
January 26 and 29, 2004, Harvest repaid the remaining $25 million of equity
bridge principal amounts outstanding and paid $0.185 million of interest accrued
since December 31, 2003. The Equity Bridge Notes were amended on June 29, 2004,
July 7, 2004, and July 9, 2004 to assist with the acquisition by Harvest
Operations of Storm and the acquisition of the EnCana assets. These notes were
drawn by $30 million and repaid as to $20 million on August 11, 2004 and $10
million on December 30, 2004.
Convertible Debentures
On January 29, 2004, the Trust issued $60 million of 9% convertible unsecured
subordinated debentures due May 31, 2009. Interest on the debentures is payable
semi-annually in arrears in equal installments on May 31 and November 30 in each
year, commencing May 31, 2004. The debentures are convertible into fully paid
and non-assessable trust units at the option of the holder at any time prior to
the close of business on the earlier of May 31, 2009 and the business day
immediately preceding the date specified by the Trust for redemption of the
Debentures, at a conversion price of $14.00 per trust unit plus a cash payment
for accrued interest and in lieu of any fractional trust units resulting on the
conversion. The debentures may be redeemed by the Trust at its option in whole
or in part subsequent to May 31, 2007, at a price equal to $1,050 per debenture
between June 1, 2007 and May 31, 2008 and at $1,025 per debenture between June
1, 2008 and May 31, 2009. Any redemption will include accrued and unpaid
interest at such time when completed. Under both redemption options, the Trust
may elect to pay both the principal and accrued interest in the form of trust
units at a price equal to 95% of the weighted average trading price for the
preceding 20 consecutive trading days, 5 days prior to settlement date.
On August 10, 2004, the Trust issued $100 million of 8% convertible unsecured
subordinated debentures due September 30, 2009. Interest on the debentures is
payable semi-annually in arrears in equal installments on March 31 and September
30 in each year, commencing March 31, 2005. The debentures are convertible into
fully paid and non-assessable trust units at the option of the holder at any
time prior to the close of business on the earlier of September 30, 2009 and the
business day immediately preceding the date specified by the Trust for
redemption of the Debentures, at a conversion price of $16.25 per trust unit
plus a cash payment for accrued interest and in lieu of any fractional trust
units resulting on the conversion. The debentures may be redeemed by the Trust
at its option in whole or in part subsequent to September 30, 2007, at a price
equal to $1,050 per debenture between October 1,
43
2007 and September 30, 2008 and at $1,025 per debenture between October 1, 2008
and September 30, 2009. Any redemption will include accrued and unpaid interest
at such time when completed. Under both redemption options, the Trust may elect
to pay both the principal and accrued interest in the form of trust units at a
price equal to 95% of the weighted average trading price for the preceding 20
consecutive trading days, 5 days prior to settlement date. This series of
convertible debentures ranks pari-passu with the outstanding debentures issued
on January 29, 2004.
Debt of the Corporation
The Corporation has issued senior notes (see "Borrowing by the Corporation -
Senior Notes") which are guaranteed by the Trust, along with the Trust's other
wholly-owned subsidiaries.
INFORMATION RESPECTING THE CORPORATION
The Corporation was incorporated under the Business Corporations Act (Alberta)
on May 14, 2002 as 989131 Alberta Ltd. On May 17, 2002, the Corporation amended
its Articles of Incorporation to change its name to Coyote Energy Inc. and on
September 17, 2002, the Corporation changed its name to "Harvest Operations
Corp.". On January 1, 2004, the Corporation amalgamated with WEI and the
amalgamated corporation continued under the name "Harvest Operations Corp.". The
head and principal office of the Corporation is located at Suite 2100, 330 - 5th
Avenue S.W., Calgary, Alberta, T2P 0L4 and its registered office is located at
Suite 1400, 350 - 7th Avenue S.W., Calgary, Alberta T2P 3N9. All of the issued
and outstanding shares of the Corporation are held in the name of the Trustee
for the benefit of, and on behalf of, the Trust.
Business
The Corporation manages and administers the Trust and the other Operating
Subsidiaries on behalf of the Trust and is responsible for the oil and natural
gas technical, investment, engineering, geological, land management, financial
and administrative services and commodity marketing services relating to the
Properties and the Trust. Each of the directors and senior management of the
Corporation have been involved in the oil and natural gas industry for, on
average, in excess of 20 years. At March 16, 2005, the Corporation has a staff
made up of 84 head office employees and 95 field employees dedicated to the
Properties, with key personnel having extensive experience in all technical,
operating and financial aspects of the oil and natural gas industry including:
o organizing, operating, managing, developing and optimizing petroleum
and natural gas properties;
o evaluating, acquiring and disposing of petroleum and natural gas
properties; and
o marketing petroleum, natural gas and natural gas liquids.
Management Policies and Strategies
As a result of management's past experience, the members of the management team
have established proven track records in acquiring, developing and operating oil
and natural gas resources. Management of the Corporation believes that the
success derived from these experiences can be attributed to several management
principles, including:
(a) a focused and rigorous evaluation and acquisition strategy having an
objective of acquiring operated oil and natural gas reserves at low
costs;
(b) employing operating and management strategies and controls to
increase production rates and enhance production netbacks, primarily
through production cost reduction;
(c) identifying and exploiting upside opportunities in acquired
Properties to increase production and reserve recovery;
44
(d) acquiring other assets within existing operating areas to achieve
operating and development efficiencies; and
(e) managing risk effectively through prudent insurance and commodity
hedging programs and hands-on property management.
Activities undertaken by the management of the Corporation on behalf of the
Trust are intended to be directed towards:
o optimizing consistent levels of Cash Available For Distribution and
ultimately, the Distributable Cash paid to Unitholders;
o capturing the maximum cash flow, production and reserve recovery from the
Properties; and
o striving for long-term growth in the value of the Properties and
consequently the value of the NPI and the Direct Royalties held by the
Trust by improving recovery levels from the Properties and acquiring
additional Properties.
Borrowing by the Corporation
The Operating Subsidiaries and the Trust are permitted to incur indebtedness to
purchase Property Interests, effect capital expenditures or other obligations or
expenditures in respect of the Properties or for working capital purposes.
Indebtedness of the Operating Subsidiaries to fund the purchase of Canadian
resource properties may be repaid with funds received from the Trust pursuant to
the Deferred Purchase Price Obligation. The Harvest Board has established the
following guidelines with respect to the indebtedness of the Operating
Subsidiaries: (i) amounts borrowed to finance the purchase of Properties should
not exceed 50% of the Reserve Value of all Properties including those to be
acquired at the time of borrowing as shown on the latest available independent
engineering report, unless specifically approved by the Board of Directors; and
(ii) the estimated annual debt service costs for the 12 months following the
borrowing on amounts borrowed to finance capital expenditures or other financial
obligations or expenditures required to maintain or improve production from the
Properties should not exceed 50% of the estimated income from the NPI and income
from Direct Royalties for such 12 month period, unless specifically approved by
the Board of Directors. The Operating Subsidiaries are entitled to grant
security in priority to the NPI and the Trust is permitted to grant security on
the NPI and Direct Royalties to secure the loan of funds directly to the Trust
or secure guarantees granted by the Trust of indebtedness of the Operating
Subsidiaries. The borrowings of the Trust require approval by the Board of
Directors.
Debt service costs of the Operating Subsidiaries are deducted in computing NPI
income and debt service costs of the Trust are deducted in computing Cash
Available For Distribution. Debt repayment by the Operating Subsidiaries is
scheduled to minimize, to the extent possible, any income tax payable by the
Operating Subsidiaries.
Senior Credit Facility
On September 1, 2004, in connection with the closing of the acquisition of the
Southern Alberta and East Central Alberta Properties, Harvest Operations entered
into an amended credit agreement with a syndicate of lenders. This credit
facility consists of a $310 million production loan, a $15 million operating
loan, and a U.S. $21.3 million mark to market credit to be used for financial
instrument hedging. The term of the facility is to June 29, 2005. Availability
under the facility is subject to a borrowing base calculation performed by the
lenders at least on a semi-annual basis. The facility permits drawings in
Canadian or U.S. dollars, and includes banker's acceptances, LIBOR loans and
letters of credit. Outstanding balances bear interest at rates ranging from 0%
to 2.25% above the applicable Canadian or U.S. prime rate depending upon the
type of borrowing and the debt to annualized cash flow ratio. The debt is
secured by a $750 million debenture with a fixed and floating charge over all of
the assets of the Corporation, and a guarantee by the Trust and its
subsidiaries.
Under the terms of this credit agreement, a bridge facility of $70 million was
provided to assist in the closing of the EnCana asset acquisition. This facility
was due to mature on June 1, 2005, and outstanding balances under this
45
facility accrued interest at progressive rates of 3% to 8% above the applicable
Canadian prime rate. The bridge facility was repaid in full with the net
proceeds of the senior note issuance. As at December 31, 2004 the Trust was in
compliance with all covenants.
The Corporation is subject to a standby fee equal to 0.125% per annum on the
undrawn amount of the Current Bank Facility.
Events of default under the Current Bank Facility include: failure to pay
interest or principal when due; failure to meet security or covenants; material
misrepresentation; material adverse change in the financial condition of
operations of the Corporation; uncontested proceedings initiated to enforce
encumbrances on the Corporation's assets that have an aggregate value of
$500,000; liquidation, winding-up or dissolution of the Corporation; ceasing to
carry on business; and appointment of receiver or trustee appointed by judicial
body or pursuant to another agreement.
As of March 16, 2005, approximately $90 million is outstanding under the Current
Bank Facility.
Senior Notes
On October 14, 2004, Harvest Operations closed an agreement to sell, on a
private placement basis in the United States, US$250 million of senior notes due
October 15, 2011. The senior notes are unsecured and bear interest at an annual
rate of 7 7/8% and were sold at a price of 99.3392% of their principal amount.
Interest is payable semi-annually on April 15 and October 15. The senior notes
are unconditionally guaranteed by the Trust and all of its wholly-owned
subsidiaries. The Trust used the net proceeds of the offering to repay in full
Harvest's bank bridge facility and partially repay outstanding balances under
Harvest's senior credit facility. The fair value of the senior notes at December
31, 2004 was US$250.6 million (Cdn$301.2 million).
The terms of the notes limit the amount of secured and unsecured debt the
Corporation may issue, and also place certain restrictions on the amount of
distributions which may be paid in certain circumstances.
Commodity Risk Management
The following is a summary of the oil sales price derivative contracts as at
December 31, 2004, that have fixed future sales prices:
---------------------------------------------------------------------------------------------------------
Oil price swap contracts based on West Texas Intermediate
---------------------------------------------------------------------------------------------------------
Mark to Market
Daily Quantity Term Price per Barrel Gain (Loss)
---------------------------------------------------------------------------------------------------------
500 Bbls/d January through December 2005 U.S. $24.00 $ (4,107)
1,100 Bbls/d January through March 2005 U.S. $22.38 (2,535)
1,030 Bbls/d April through June 2005 U.S. $22.18 (2,358)
50% Participating swap contracts based on West Texas Intermediate
---------------------------------------------------------------------------------------------------------
8,750 Bbls/d Jan - Dec 2006 U.S. $38.16(b) $ 3,710
46
Oil price collar contracts based on West Texas Intermediate
----------------------------------------------------------------------------------------------------------------
2,500 Bbls/d January through June 2005 U.S. $28.40 - 32.25 ($21.80) $ (6,032) (a)
1,500 Bbls/d July through December 2005 U.S. $28.17 - 32.10 ($22.33) (3,296) (a)
2,000 Bbls/d January through December 2005 U.S. $28.00 - 42.00 (529)
Note: (a) Harvest has sold put options at the average price denoted in
parenthesis, for the same volumes as the associated commodity
contracts. The counterparty may exercise these options if the
respective index falls below the specified price on a monthly
settlement basis.
(b) This price is a floor. The Trust realizes this price plus 50% of the
difference between spot price and this price.
-------------------------------------------------------------------------------------------------------------
Indexed put options based on West Texas Intermediate
-------------------------------------------------------------------------------------------------------------
Price per Bbl Mark to Market Gain
Daily Quantity Term Type (U.S.$) (Loss)
-------------------------------------------------------------------------------------------------------------
4,000 bbls/d Jan - Dec 2005 Long Put $30.00 $ 937
1,972 bbls/d Jan - Dec 2005 Short Call $30.00 (11,261)
1,972 bbl/d Jan - Dec 2005 Long Call $40.00 4,642
7,000 bbl/d Jan - Dec 2005 Long Put $35.00 4,050
2,380 bbl/d Jan - Dec 2005 Short Call $35.00 (9,239)
2,380 bbl/d Jan - Dec 2005 Long Call $45.00 3,090
7,500 bbl/d Jan - Dec 2005 Long Put $40.00 9,142
3,675 bbl/d Jan - Dec 2005 Short Call $40.00 (8,651)
3,675 bbl/d Jan - Dec 2005 Long Call $50.00 2,678
7,500 bbl/d Jan - June 2006 Long Put $34.00 2,989
3,750 bbl/d Jan - June 2006 Short Call $34.00 (7,252)
3,750 bbl/d Jan - June 2006 Long Call $44.00 3,170
-------------------------------------------------------------------------------------------------------------
The following is a summary of electricity price physical and financial swap
contracts entered into by Harvest Operations to fix the cost of future
electricity usage as at December 31, 2004:
------------------------------------------------------------------------------------------------------------
Swap contracts based on electricity prices
------------------------------------------------------------------------------------------------------------
Weighted Average Average Price Mark to Market
Quantity Term per Megawatt Gain (Loss)
------------------------------------------------------------------------------------------------------------
24.8 MWH January through December 2005 Cdn $47.43 $ 1,272
29.9 MWH January through December 2006 Cdn $47.51 (196)
Swap contracts based on electricity heat rate
------------------------------------------------------------------------------------------------------------
Quantity Term Heat Rate Mark to Market (Loss)
------------------------------------------------------------------------------------------------------------
5 MW January through December 2005 8.40 GJ/MWh $ (80)
------------------------------------------------------------------------------------------------------------
Foreign currency contracts
------------------------------------------------------------------------------------------------------------
Monthly Contract Amount Term Contract Rate Mark to Market
Gain
------------------------------------------------------------------------------------------------------------
U.S. $8.33 million January through December 2005 1.20 Cdn / U.S. $ 4,500(1)
(1) Represents the premium paid on this contract.
47
DIRECTORS AND OFFICERS OF THE CORPORATION
The names, municipalities of residence, present positions with the Corporation
and principal occupations during the past five years of the directors, nominated
directors and officers of the Corporation are set out in the table below and in
the text which follows thereafter.
Name and Municipality of Position with No. of Trust
Residence the Corporation Units Held (1) Principal Occupation
- ------------------------- --------------- --------------- ---------------------------------------------------------
Kevin A. Bennett Nominated 500,000 Professional engineer; independent businessman involved
Calgary, Alberta Director in founding and the directorship of several oil and gas,
and energy services companies. Co-founded Harvest
Energy Trust in 2002 with Mr. Chernoff. From Sept.
1998 to Sept. 2001, was President, C.O.O. and a director
of Ventus Energy Ltd.
John A. Brussa(2)(3)(5) Director 298,305 Barrister and Solicitor; Partner of Burnet, Duckworth &
Calgary, Alberta Palmer LLP (a law firm).
M. Bruce Chernoff(4)(5) Director, 7,645,130(7) Professional Engineer; Chairman of the Corporation;
Calgary, Alberta Chairman President and Director of Caribou (a private investment
management company) since June 1999; from April 2000
to October 2001, Executive Vice President and Chief
Financial Officer of Petrobank Energy and Resources
Ltd. ("Petrobank") (a public oil and natural gas
company); from February to June 1999, Executive Vice
President and Chief Financial Officer of Pacalta
Resources Ltd. ("Pacalta") (a public oil and natural gas
company); prior thereto, Executive Vice President of
Pacalta.
Hank B. Swartout(4) Director 905,690(8) Chairman, President and Chief Executive Officer of
Calgary, Alberta Precision Drilling Corporation since July, 1987.
Verne G. Johnson(2)(3)(4) Director 35,000 President of KristErin Resources Inc., a private family
Calgary, Alberta company since January 2000; Senior Vice President,
Funds Management of Enerplus Resources Group from
2000 to 2002; prior thereto, President and Chief
Executive Officer of AltaQuest Energy Corporation from
1999 to 2000; prior thereto, President of Ziff Energy
Group (an energy consulting company) from 1997 to
1999; prior thereto, President and Chief Executive
Officer
of ELAN Energy Inc. (a public oil and natural gas
company) from 1989 to 1997.
Hector J. McFadyen(2)(3)(5) Director 30,000 Independent businessman and Director of Hunting PLC (a
Calgary, Alberta UK based public international oil services company);
director of Computershare Trust Company of Canada (a
private Canadian company t hat manages various trust
related activities for public and private companies
throughout North America); director of Aluma Systems (a
private Canadian company providing industrial and
concrete construction services); formerly, President,
Midstream Division, Alberta Energy Company Ltd. (a
public oil and natural gas company) from 1995 to 2002.
48
Name and Municipality of Position with No. of Trust
Residence the Corporation Units Held (1) Principal Occupation
- ------------------------- --------------- --------------- ---------------------------------------------------------
Jacob Roorda President 219,625(9) Professional Engineer, President of the Corporation; from
Calgary, Alberta June 1999 to July 2002, Managing Director, Research
Capital (a mid-sized investment banking dealer); from
January 1996 to March 1999, Vice President, Corporate,
Director and co-founder of PrimeWest Energy Trust
("PrimeWest") (a public energy trust); from May 1991 to
January 1996, Manager, Business Development, Fletcher
Challenge (a private oil and natural gas company).
David J. Rain Vice President, 108,000(10) Chartered Accountant; Vice President, CFO and
Calgary, Alberta Corporate Corporate Secretary of the Corporation; Vice President,
Secretary and Finance and Chief Financial Officer of Petrobank from
Chief Financial October 2001 to March 2004; Vice President and Director
Officer of Caribou since June 1999; from April 2000 to
September 2001, Director, Corporate Finance of
Petrobank; from May 1997 to June 1999, Corporate
Controller and Treasurer of Pacalta.
J.A. Ralston Vice President, 76,083(11) Vice President, Operations of the Corporation; from 1996
Calgary, Alberta Operations to 2002, Manager, Production of Penn West Petroleum
("PennWest") (a public oil and natural gas company).
James A. Campbell Vice President, 31,950(12) Vice President, Geosciences of the Corporation from
Calgary, Alberta Geosciences 2004; prior thereto, Manager, Geosciences since August
2002. From August 1997 to July, 2002, Vice President
Exploration with Navigo Energy (and predecessor public
oil and natural gas companies).
Notes:
(1) Represents all Trust Units held directly or indirectly or over which such
person exercises control or direction as at March 16, 2005. Based upon
information provided by the director or officer to the Trust.
(2) Member of the Audit Committee.
(3) Member of the Corporate Governance Committee.
(4) Member of the Reserves, Safety and Environment Committee.
(5) Member of the Compensation Committee.
(6) The terms of office of all of the directors will expire at the next annual
unitholders' meeting of the Trust.
(7) Includes Trust Units held by companies controlled by Mr. Chernoff, and
Trust Units held in RESP accounts for the benefit of Mr. Chernoff's
children.
(8) Includes 162,857 Trust Units held by Mr. Swartout's spouse.
(9) Includes 64,243 Trust Units held in Mr. Roorda's spouse's account which is
controlled by Mr. Roorda.
(10) Includes 30,700 Trust Units held by Mr. Rain's spouse.
(11) Includes 37,066 Trust Units held by Mr. Ralston's spouse.
(12) Includes 9,000 Trust Units held by Mr. Campbell's spouse.
As at March 16, 2005, the directors, nominated directors and officers of the
Corporation and their associates and affiliates, as a group, hold, directly or
indirectly, or exercise control or direction over, approximately 9,849,783 Trust
Units or 23.0% of the outstanding Trust Units and exchangeable shares.
The following is a brief description of the background of each of the senior
officers, nominated directors and directors of the Corporation. The past
performance of each of the individuals indicated below is not necessarily
indicative of future performance.
49
Jacob Roorda, President
Mr. Roorda is a Professional Engineer and holds a Bachelor of Applied Science
(Eng.) degree from Queen's University and an MBA from the University of Calgary.
Following university, Mr. Roorda held a number of senior engineering positions
with Dome Petroleum Ltd. From 1987 to 1991, Mr. Roorda was a Vice President in
the equity research group and was a ranked oil and natural gas analyst at BZW
Canada Ltd., in Toronto.
From 1991 to 1996, Mr. Roorda was Manager, Business Development at Fletcher
Challenge. In January 1996, Mr. Roorda co-founded PrimeWest (a public energy
trust) and served as Vice President, Corporate and Director of PrimeWest. Mr.
Roorda was responsible for overseeing the acquisition strategies of PrimeWest.
While at Fletcher and PrimeWest, Mr. Roorda was responsible for closing in
excess of $650 million of oil and natural gas property acquisitions.
From June 1999 to July 2002, Mr. Roorda was a Managing Director of Research
Capital, an investment-banking firm. At Research Capital, Mr. Roorda was
responsible for the overall direction and operations of the Calgary investment
banking office of the firm.
David J. Rain, Vice President, Chief Financial Officer and Corporate Secretary
Mr. Rain is a Chartered Accountant and holds a Bachelor of Commerce degree from
the University of Saskatchewan.
Mr. Rain articled at KPMG LLP Chartered Accountants and was a Manager in their
audit group when he departed in 1992. Mr. Rain served in senior financial
positions at Nowsco Well Service Ltd., an oilfield service company with
worldwide operations, from 1992 through August 1996. Mr. Rain was the Chief
Financial Officer of Trican Well Service Ltd, an oilfield service company with
operations in Alberta and Saskatchewan, from October 1996 through April 1997.
Mr. Rain joined Pacalta in May 1997 as Corporate Controller. Pacalta was an oil
and natural gas exploration and production company with operations primarily in
Ecuador. When AEC acquired Pacalta in 1999, Mr. Rain joined Mr. Chernoff at
Caribou, and became Director, Corporate Finance at Petrobank in March 2000. Mr.
Rain assumed the position of Vice President, Finance and Chief Financial Officer
of Petrobank in October 2001 and resigned in March 2004. Mr. Rain also serves as
a Director and Chief Financial Officer of Caribou.
J.A. Ralston, Vice President, Operations
Mr. Ralston completed the Management Development Program at the University of
Calgary in 1994.
Mr. Ralston was employed with Petro-Canada from 1980 through June 1994 in a
broad range of field operating positions of increasing responsibility. During
his tenure at Petro-Canada, Mr. Ralston was responsible for construction of
field facilities and pipelines, natural gas plant and field operations,
procurement, reservoir management, drilling and workovers.
Mr. Ralston commenced employment with Penn West in July 1994 where he worked
until June 2002. Since 1997, Mr. Ralston served as Production Manager,
responsible for overseeing all of Penn West's 100,000 BOE/d production
operations, 270 field staff and an annual budget of $200 million. Mr. Ralston
was responsible for all areas of operations including engineering, exploitation,
production optimization, capital management, planning, construction and
budgeting.
James A. Campbell, Vice President, Geosciences
Mr. Campbell has primary responsibility for all Geological and Geophysical
activities, and provides leadership from a technical/operational and
organizational perspective. With over 25 years in the oil and gas sector at
senior management levels, Mr. Campbell will also play an expanded role in
planning Harvest's strategic direction.
50
Mr. Campbell has been with Harvest since inception of the Corporation. Prior to
joining Harvest, Mr. Campbell held the Vice President, Exploration role at
Conoco Canada Ltd. and later Navigo Energy Inc. Mr. Campbell holds a B.Sc.
degree from McMaster University.
Kevin A. Bennett, Nominated Director
Mr. Bennett is a professional engineer with a Bachelor of Engineering Science
degree in Chemical Engineering from the University of Western Ontario (1981).
Since September, 2001 Mr. Bennett has been an independent businessman involved
in founding and the directorship of several oil and gas, and energy services
companies. Mr. Bennett was a co-founder of Harvest Energy Trust with Mr.
Chernoff in 2002.
Prior to Sept. 2001, Mr. Bennett was the President, C.O.O. and a director of
Ventus Energy Ltd. from Sept. 1998.
John A. Brussa, Director
Mr. Brussa is a barrister and solicitor and has been a partner at Burnet,
Duckworth & Palmer LLP in Calgary since 1987. Mr. Brussa is recognized as a
leading tax practitioner in Canada and sits on the board of directors of several
Canadian public companies.
M. Bruce Chernoff, Director and Chairman
Mr. Chernoff is a Professional Engineer with a Bachelor of Applied Science
degree in Chemical Engineering from Queen's University. Mr. Chernoff commenced
employment with Pacalta in 1988. Pacalta was a public junior oil and natural gas
company with operations in Canada until 1996 when it acquired an oil property in
Ecuador. Mr. Chernoff held various senior positions with Pacalta including
Executive Vice-President and Chief Financial Officer. Mr. Chernoff was a
director of Pacalta from 1992 until Pacalta was purchased by Alberta Energy
Company in May 1999.
Mr. Chernoff initiated the formation of Caribou, of which he is the President
and a Director, in June 1999, to carry out investments in oil and natural gas
among other sectors. Mr. Chernoff became a Director, and the Executive Vice
President and Chief Financial Officer of Petrobank in March 2000. Mr. Chernoff
resigned that position in October 2001 to focus on his other business interests.
Mr. Chernoff initiated the formation of the Corporation in June 2002 to pursue
oil and natural gas development and acquisition opportunities.
Hank B. Swartout, Director
Since 1987, Mr. Swartout has been the Chairman of the Board, President and Chief
Executive Officer of Precision Drilling Corporation, the largest Canadian
integrated oilfield and industrial services contractor and a global provider of
products and services to the energy industry.
Verne G. Johnson, Director
Mr. Johnson received a Bachelor of Science degree in Mechanical Engineering from
the University of Manitoba in 1966. He immediately commenced employment with
Imperial Oil Limited, which continued until 1981 (including two years with Exxon
Corporation in New York from 1977 to 1979). In 1981, Mr. Johnson joined Liberty
Petroleum Ltd. as President and Chief Executive Officer. In 1982, he joined Roxy
Petroleum Ltd. as Vice President, Production, remaining until 1987 when he
joined Paragon Petroleum Ltd. as President. In 1989, Mr. Johnson joined ELAN
Energy Inc. (then Lasmo Canada Inc.) as President and a Director. Following the
sale of ELAN in 1997, he became President of Ziff Energy Group until 1999, then
President of AltaQuest Energy Corporation and he then joined the Enerplus
Resources Group in 2000, becoming Senior Vice President of Funds Management. In
February 2002, he departed from the Enerplus Resources Group and remains as
President of his private family company, KristErin Resources Inc.
51
Hector J. McFadyen, Director
Mr. McFadyen holds a Master of Arts (Econ.) degree from the University of
Calgary and a Bachelor of Arts (Econ.) degree from Sir George Williams
University.
Mr. McFadyen was employed at the Alberta Energy and Utilities Board (formerly
the Oil and Natural Gas Conservation Board) between 1969 and 1976, primarily
within its Economics Department.
Mr. McFadyen began work for Alberta Energy Company Ltd. ("AEC"), now EnCana
Corporation ("EnCana"), in 1976. EnCana is one of the largest independent oil
and natural gas producers in North America. Mr. McFadyen developed a number of
significant business units within AEC, developing experience in a broad range of
businesses and disciplines. Such experience included project development and
investments across North America, Latin America, Asia and Europe. At AEC, Mr.
McFadyen served as a member of the senior executive team involved in
recommending and implementing the strategic plan for the company. As President
of the Forest Products Division, he assumed responsibility for development and
implementation of the business strategy for an Alberta based forest products
business. Mr. McFadyen also served as the President of the Midstream Division of
AEC since 1995, having responsibility for the company's pipelines and natural
gas storage businesses. Mr. McFadyen retired from EnCana in 2002.
Mr. McFadyen is a member of the board of directors of Hunting PLC ("Hunting"), a
UK-based public corporation engaged in oil services, and oil and natural gas
marketing and distribution activities internationally. Hunting carries on its
oil and natural gas marketing and distribution activities in North America
through its wholly-owned subsidiary, Gibson Energy Ltd. Mr. McFadyen is also a
member of the Board of Directors of Computershare Trust Company of Canada, a
private Canadian company that manages various trust related activities for
public and private companies throughout North America. Mr. McFadyen is also a
director of Aluma Systems, a private Canadian company providing industrial and
concrete construction services.
Corporate Cease Trade Orders or Bankruptcies
Mr. John Brussa was a director of Imperial Metals Limited, a corporation engaged
in both oil and gas and mining operations, in the year prior to that corporation
implementing a plan of arrangement under the Company Act (British Columbia) and
under the Companies' Creditors Arrangement Act (Canada) which resulted in the
separation of its two businesses and the creation of two public corporations:
Imperial Metals Corporation and IEI Energy Inc. (now Rider Resources Ltd.).
Other than the item referenced above, no director, officer or promoter of the
Corporation has, within the last 10 years, been a director, officer or promoter
of any reporting issuer that, while such person was acting in that capacity, was
the subject of a cease trade or similar order or an order that denied the
company access to any statutory exemption for a period of more than 30
consecutive days or was declared a bankrupt or made a voluntary assignment in
bankruptcy, made a proposal under any legislation relating to bankruptcy or been
subject to or instituted any proceedings, arrangement or compromise with
creditors or had a receiver, receiver-manager or trustee appointed to hold the
assets of that person.
Penalties or Sanctions
No director, officer or promoter of the Corporation, within the last 10 years,
has been subject to any penalties or sanctions imposed by a court or securities
regulatory authority relating to trading in securities, promotion or management
of a publicly traded issuer or theft or fraud.
Personal Bankruptcies
No director, officer or promoter of the Corporation, or a shareholder holding
sufficient securities of the Corporation to affect materially the control of the
Corporation, or a personal holding company of any such persons, has, within the
last 10 years, become bankrupt, made a proposal under any legislation relating
to bankruptcy or insolvency, or
52
being subject to or instituted any proceedings, arrangement or compromise with
creditors or had a receiver, receiver manager or trustee appointed to hold the
assets of the individual.
Conflicts of Interest
Directors and officers of the Corporation may, from to time, be involved with
the business and operations of other oil and gas issuers, in which case a
conflict may arise. See "Risk Factors".
SHARE CAPITAL OF THE CORPORATION
The share capital of the Corporation currently consists of an unlimited number
of common shares and an unlimited number of first preferred shares. As at the
date hereof, one hundred common shares of the Corporation are outstanding. Such
shares are held by the Trustee for and on behalf of the Trust. The voting of
such shares is governed by the provisions of the Trust Indenture and the Trust
is not entitled, without the direction of Unitholders, to exercise its rights as
a shareholder of the Corporation except as permitted by the Trust Indenture. See
"Trust Indenture - Exercise of Voting Rights Attached to Shares of the
Corporation".
DESCRIPTION OF CAPITAL STRUCTURE
Trust Units
For a description of the Trust Units, see below under the section titled "Trust
Indenture".
Common Shares of the Corporation
Subject to the provisions of the ABCA, the holders of Common Shares are entitled
to receive notice of, to attend and vote at all meetings of the shareholders of
The Corporation and are entitled to one vote, in person or by proxy, for each
Common Share held.
As at the date hereof, one hundred common shares of the Corporation are
outstanding. Such shares are held by the Trustee for and on behalf of the Trust.
The voting of such shares is governed by the provisions of the Trust Indenture
and the Trust is not entitled, without the direction of Unitholders, to exercise
its rights as a shareholder of the Corporation except as permitted by the Trust
Indenture.
The holders of Common Shares are entitled to receive, if, as and when declared
by the directors of The Corporation, non-cumulative dividends at such rate and
payable on such date as may be determined from time to time by the directors of
The Corporation. Distributions may be made only where such distribution does not
result in the Corporation having insufficient net assets to redeem or purchase
the First Preferred Shares (see below).
On the liquidation, dissolution or winding-up of The Corporation, or any other
distribution of the assets of The Corporation among its shareholders for the
purpose of winding-up its affairs, the holders of the Common Shares shall be
entitled to receive the remaining property and assets of The Corporation after
property and assets have been distributed to holders of First Preferred Shares.
Exchangeable Shares of the Corporation
Exchangeable shares were issued pursuant to the Plan of Arrangement on June 30,
2004 to Canadian-resident former shareholders of Storm Energy Ltd. who elected
to receive such shares. The exchangeable shares are exchangeable into Trust
Units at a pre-determined exchange ratio, which is increased for each
distribution made by the trust following the Plan of Arrangement. The
exchangeable shares rank above Common Shares with respect to the payment of
dividends and the distribution of assets of the Corporation.
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The Corporation may redeem up to 20% of the exchangeable shares on an annual
basis. Once the number of exchangeable shares outstanding is less than 500,000,
the Corporation may redeem all outstanding exchangeable shares. The Corporation
may also redeem all remaining outstanding exchangeable shares at its option
beginning on June 30, 2006. Any exchangeable shares outstanding on June 30, 2009
will be automatically redeemed by the Corporation.
First Preferred Shares of the Corporation
First Preferred Shares are redeemable and retractable, with the holder entitled
to receive notice of, to attend and vote at all meetings of the shareholders of
The Corporation and to one vote for each First Preferred Share held. As at the
date hereof, no First Preferred Shares of the Corporation are outstanding.
Holders of First Preferred Shares are entitled to receive, if, as and when
declared by the directors of the Corporation, non-cumulative dividends at such
rate and payable on such date as may be determined from time to time by the
directors of the Corporation.
On the liquidation, dissolution or winding-up of the Corporation, or any other
distribution of the assets of the Corporation among its shareholders for the
purpose of winding-up its affairs, the holders of the First Preferred Shares
shall be entitled to receive the remaining property and assets of the
Corporation before any property or assets are distributed to holders of Common
Shares.
TRUST INDENTURE
The following is a summary of the Trust Indenture and other matters regarding
the structure and operations of the Trust.
Trust Units
An unlimited number of Trust Units may be created and issued pursuant to the
Trust Indenture. As of March 16, 2005, there were 42,585,278 Trust Units issued
and outstanding. Each Trust Unit entitles the holder thereof to one vote at any
meeting of the holders of Trust Units and represents an equal undivided
beneficial interest in any distribution from the Trust (whether of net income,
net realized capital gains or other amounts) and in any net assets of the Trust
in the event of termination or winding-up of the Trust. All Trust Units
outstanding from time to time shall be entitled to equal shares of any
distributions by the Trust, and in the event of termination or winding-up of the
Trust, in any net assets of the Trust. All Trust Units shall rank among
themselves equally and rateably without discrimination, preference or priority.
Each Trust Unit is transferable, is not subject to any conversion or pre-emptive
rights and entitles the holder thereof to require the Trust to redeem any or all
of the Trust Units held by such holder (see "Redemption Right" below) and to one
vote at all meetings of Unitholders for each Trust Unit held. See "Risk Factors
- - Nature of Trust Units".
Special Voting Units
At the 2004 Unitholders' Meeting, the Unitholders approved an amendment to the
Trust Indenture to provide for the issuance of an unlimited number of special
voting units. Each special voting unit will entitle the holder thereof to such
number of votes at meetings of Unitholders as may be prescribed by the Board of
Directors of the Corporation in the resolution authorizing the issuance of any
such special voting units.
Unitholder Limited Liability
The Trust Indenture provides that no Unitholder, in its capacity as such, shall
incur or be subject to any liability in contract or in tort in connection with
the Trust Fund or the obligations or affairs of the Trust or with respect to any
act or omission of the Trustee or any other person in the performance or
exercise, or purported performance or exercise, of any obligation, power,
discretion or authority conferred upon the Trustee or such other person
hereunder
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or with respect to any transaction entered into by the Trustee or by any other
person pursuant to the Trust Indenture. No Unitholder shall be liable to
indemnify the Trustee or any such other person with respect to any such
liability or liabilities incurred by the Trustee or by any such other person or
persons or with respect to any taxes payable by the Trust or by the Trustee or
by any other person on behalf of or in connection with the Trust.
Notwithstanding the foregoing, to the extent that any Unitholders are found by a
court of competent jurisdiction to be subject to any such liability, such
liability shall be enforceable only against, and shall be satisfied only out of,
the Trust Fund and the Trust (to the extent of the Trust Fund) is liable to, and
shall indemnify and save harmless any Unitholder against any costs, damages,
liabilities, expenses, charges or losses suffered by any Unitholder from or
arising as a result of such Unitholder not having any such limited liability.
The provinces of Alberta and Ontario have recently passed legislation providing
unitholders of mutual fund trusts the same protections afforded shareholders of
corporations. See "Risk Factors - Unitholder Limited Liability".
Issuance Of Trust Units
The Trust Indenture provides that Trust Units, including rights, warrants and
other securities to purchase, to convert into or to exchange into Trust Units,
may be created, issued, sold and delivered on such terms and conditions and at
such times as the Harvest Board may determine. The Trust Indenture also provides
that the Corporation may authorize the creation and issuance of debentures,
notes and other evidences of indebtedness of the Trust from time to time on such
terms and conditions to such persons and for such consideration as the
Corporation may determine.
Borrowing By the Trust
Pursuant to the Trust Indenture, the Trustee is permitted to, directly or
indirectly, borrow money from or incur indebtedness to any person and in
connection therewith, to guarantee, indemnify or act as a surety with respect to
payment or performance of any indebtedness, liabilities or obligation of any
kind of any person, including, without limitation, the Corporation and any
subsidiary of the Trust; to enter into any other obligations on behalf of the
Trust; or enter into any subordination agreement on behalf of the Trust or any
other person, and to assign, charge, pledge, hypothecate, convey, transfer,
mortgage, subordinate, and grant any security interest, mortgage or encumbrance
over or with respect to all or any of the Trust Fund or to subordinate the
interests of the Trust in the Trust Fund to any other person.
Debt service costs incurred by the Trust are deducted in computing the Cash
Available For Distribution.
Redemption Right
Trust Units are redeemable at any time on demand by the holders thereof upon
delivery to the Trust of the certificate or certificates representing such Trust
Units, accompanied by a duly completed and properly executed notice requiring
redemption. Upon receipt of the notice to redeem Trust Units by the Trust, the
holder thereof shall only be entitled to receive a price per Trust Unit (the
"Market Redemption Price") equal to the lesser of: (i) 90% of the "market price"
of the Trust Units on the principal market on which the Trust Units are quoted
for trading during the 10 trading day period commencing immediately after the
date on which the Trust Units are tendered to the Trust for redemption; and (ii)
the closing market price on the principal market on which the Trust Units are
quoted for trading on the date that the Trust Units are so tendered for
redemption.
For the purposes of this calculation, "market price" will be an amount equal to
the simple average of the closing price of the Trust Units for each of the
trading days on which there was a closing price; provided that, if the
applicable exchange or market does not provide a closing price but only provides
the highest and lowest prices of the Trust Units traded on a particular day, the
market price shall be an amount equal to the simple average of the average of
the highest and lowest prices for each of the trading days on which there was a
trade; and provided further that if there was trading on the applicable exchange
or market for fewer than 5 of the 10 trading days, the market price shall be the
simple average of the following prices established for each of the 10 trading
days: the average of the last bid and last ask prices for each day on which
there was no trading; the closing price of the Trust Units for each day that
there was trading if the exchange or market provides a closing price; and the
average of the highest and lowest prices of the Trust Units for each day that
there was trading, if the market provides only the highest and lowest prices of
Trust Units traded on a particular day.
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The "closing market price" shall be: an amount equal to the closing price of the
Trust Units if there was a trade on the date; an amount equal to the average of
the highest and lowest prices of the Trust Units if there was trading and the
exchange or other market provides only the highest and lowest prices of Trust
Units traded on a particular day; and the average of the last bid and last ask
prices if there was no trading on the date.
The aggregate Market Redemption Price payable by the Trust in respect of any
Trust Units surrendered for redemption during any calendar month shall be
satisfied by way of a cheque drawn on a Canadian chartered bank or trust company
in Canadian money payable on the last day of the following month. The
entitlement of Unitholders to receive cash upon the redemption of their Trust
Units is subject to the limitation that the total amount payable by the Trust in
respect of such Trust Units and all other Trust Units tendered for redemption in
the same calendar month and in any preceding calendar month during the same year
shall not exceed $100,000; provided that, the Corporation may, in its sole
discretion, waive such limitation in respect of any calendar month. If this
limitation is not so waived, the Market Redemption Price payable by the Trust in
respect of Trust Units tendered for redemption in such calendar month shall be
paid on the last day of the following month as follows: (i) firstly, by the
Trust distributing Notes having an aggregate principal amount equal to the
aggregate Market Redemption Price of the Trust Units tendered for redemption,
and (ii) secondly, to the extent that the Trust does not hold Notes having a
sufficient principal amount outstanding to effect such payment, by the Trust
issuing its own promissory notes (herein referred to as "Redemption Notes") to
the Unitholders who exercised the right of redemption having an aggregate
principal amount equal to any such shortfall.
If, at the time Trust Units are tendered for redemption by a Unitholder, the
outstanding Trust Units are not listed for trading on the TSX and are not traded
or quoted on any other stock exchange or market which the Corporation considers,
in its sole discretion, to represent fair market value for the Trust Units or
the normal trading of the outstanding Trust Units is suspended or halted on any
stock exchange on which the Trust Units are listed for trading or, if not so
listed, on any market on which the Trust Units are quoted for trading, on the
date such Trust Units are tendered for redemption or for more than five trading
days during the 10 trading day period, commencing immediately after the date
such Trust Units were tendered for redemption then such Unitholder shall,
instead of the Market Redemption Price, be entitled to receive a price per Trust
Unit (the "Appraised Redemption Price") equal to 90% of the fair market value
thereof as determined by the Corporation as at the date on which such Trust
Units were tendered for redemption. The aggregate Appraised Redemption Price
payable by the Trust in respect of Trust Units tendered for redemption in any
calendar month shall be paid on the last day of the third following month by, at
the option of the Trust: (i) a cash payment; or (ii) a distribution of Notes
and/or Redemption Notes as described above.
It is anticipated that this Redemption Right will not be the primary mechanism
for holders of Trust Units to dispose of their Trust Units. Redemption Notes
which may be distributed in specie to Unitholders in connection with a
redemption will not be listed on any stock exchange and no market is expected to
develop in such Redemption Notes. Redemption Notes may not be qualified
investments for trusts governed by registered retirement savings plans,
registered retirement income funds, deferred profit sharing plans and registered
education savings plans.
Non-Resident Unitholders
It is in the best interests of Unitholders that the Trust qualify as a "unit
trust" and a "mutual fund trust" under the Tax Act. Certain provisions of the
Tax Act require that the Trust not be established nor maintained primarily for
the benefit of Non-Residents. Accordingly, in order to comply with such
provisions, the Trust Indenture contains restrictions on the ownership of Trust
Units by Unitholders who are Non-Residents. In this regard, the Trust shall,
among other things, take all necessary steps to monitor the ownership of the
Trust Units. If at any time the Trust becomes aware that the beneficial owners
of 49% or more of the outstanding Trust Units are or may be Non-Residents or
that such a situation is imminent, the Trust, by or through the Corporation on
the Trust's behalf, shall take such action as may be necessary to carry out the
intentions evidenced herein. For the purposes of this Section, "Non-Residents"
means non-residents of Canada within the meaning of the Tax Act.
Meetings of Unitholders
The Trust Indenture provides that meetings of Unitholders must be called and
held for, among other matters, the election or removal of the Trustee, the
appointment or removal of the auditors of the Trust, the approval of amendments
to the Trust Indenture (except as described under "- Amendments to the Trust
Indenture"), the sale of
56
the property of the Trust as an entirety or substantially as an entirety, and
the commencement of winding-up the affairs of the Trust. Meetings of Unitholders
will be called and held annually for, among other things, the election of the
directors of the Corporation and the appointment of the auditors of the Trust.
A meeting of Unitholders may be convened at any time and for any purpose by the
Corporation and must be convened, except in certain circumstances, if
requisitioned by the holders of not less than 20% of the Trust Units then
outstanding by a written requisition. A requisition must, among other things,
state in reasonable detail the business purpose for which the meeting is to be
called.
Unitholders may attend and vote at all meetings of Unitholders either in person
or by proxy and a proxyholder need not be a Unitholder. Two persons present in
person or represented by proxy and representing in the aggregate at least 10% of
the votes attaching to all outstanding Trust Units shall constitute a quorum for
the transaction of business at all such meetings.
The Trust Indenture contains provisions as to the notice required and other
procedures with respect to the calling and holding of meetings of Unitholders in
accordance with the requirements of applicable laws.
Exercise of Voting Rights Attached to Shares of the Corporation
The Trust Indenture prohibits the Trustee from voting the shares of the
Corporation with respect to (i) the election of directors of the Corporation,
(ii) the appointment of auditors of the Corporation or (iii) the approval of the
Corporation's financial statements, except in accordance with an Ordinary
Resolution adopted at an annual meeting of Unitholders. The Trust Indenture also
provides that the Trustee shall not vote the shares to authorize:
(a) any sale, lease or other disposition of, or any interest in, all or
substantially all of the assets of the Corporation, except in
conjunction with an internal reorganization of the direct or
indirect assets of the Corporation as a result of which either the
Corporation or the Trust has the same, or substantially similar,
interest, whether direct or indirect, in the assets as the interest,
whether direct or indirect, that it had prior to the reorganization;
(b) any statutory amalgamation of the Corporation with any other
corporation, except in conjunction with an internal reorganization
as referred to in paragraph (a) above;
(c) any statutory arrangement involving the Corporation except in
conjunction with an internal reorganization as referred to in
paragraph (a) above;
(d) any amendment to the articles of the Corporation to increase or
decrease the minimum or maximum number of directors; or
(e) any material amendment to the articles of the Corporation to change
the authorized share capital or amend the rights, privileges,
restrictions and conditions attaching to any class of the
Corporation's shares in a manner which may be prejudicial to the
Trust;
without the approval of the Unitholders by Special Resolution at a meeting of
Unitholders called for that purpose.
Trustee
Valiant Trust Company is the trustee of the Trust. All of the administrative and
management powers of the Trustee relating to the Trust and the operations of the
Trust have been delegated to the Corporation pursuant to the Trust Indenture and
the Administration Agreement. See "Description of the Trust - Delegation of
Authority, Administration and Trust Governance". Notwithstanding this general
delegation, pursuant to the Administration Agreement, the Trustee has agreed not
to delegate any authority to manage the following affairs of the Trust:
(a) the issue, certification, countersigning, transfer, exchange and
cancellation of certificates representing Trust Units;
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(b) the maintenance of a register of Unitholders;
(c) the distribution of Distributable Cash to Unitholders, although the
calculation of the amount of the distribution shall be made by the
Corporation and approved by the Harvest Board and submitted by the
Corporation to the Trustee for distribution to the Unitholders;
(d) the mailing of notices, financial statements and reports to
Unitholders pursuant to the Trust Indenture, although the
Corporation shall be responsible for the preparation or causing the
preparation of such notices, financial statements and reports;
(e) the provision of a basic list of registered Unitholders to
Unitholders in accordance with the procedures outlined in the Trust
Indenture;
(f) the amendment or waiver of the performance or breach of any term or
provision of the Trust Indenture on behalf of the Trust;
(g) the renewal or termination of the Administration Agreement on behalf
of the Trust; and
(h) any matter which requires the approval of the Unitholders under the
terms of the Trust Indenture.
The Trustee is required under the Trust Indenture to exercise its powers and
carry out its functions thereunder as Trustee honestly, in good faith and in the
best interests of the Trust and the Unitholders and, in connection therewith,
shall exercise that degree of care, diligence and skill that a reasonably
prudent trustee would exercise in comparable circumstances.
At each annual meeting, the Unitholders shall reappoint or appoint a successor
to the Trustee at the annual meeting of Unitholders. The Trustee may also be
removed by the Corporation upon delivery of a notice in writing by the
Corporation to the Trustee in limited circumstances. Such resignation or removal
becomes effective only upon the approval of the Unitholders by Special
Resolution, the acceptance or appointment of a successor trustee and the
assumption by the successor trustee of all obligations of the Trustee and in the
same capacity.
Liability of the Trustee
The Trustee, its directors, officers, employees, shareholders and agents shall
not be liable to any Unitholder or any other person, in tort, contract or
otherwise, in connection with any matter pertaining to the Trust or the Trust
Fund, arising from the exercise by the Trustee of any powers, authorities or
discretion conferred under the Trust Indenture, including, without limitation,
any action taken or not taken in good faith in reliance on any documents that
are, prima facie, properly executed, any depreciation of, or loss to, the Trust
Fund incurred by reason of the sale of any asset, any inaccuracy in any
valuation provided by any other appropriately qualified person, any reliance on
any such evaluation, any action or failure to act of the Corporation, or any
other person to whom the Trustee has, with the consent of the Corporation,
delegated any of its duties under the Trust Indenture, or any other action or
failure to act (including failure to compel in any way any former trustee to
redress any breach of trust or any failure by the Corporation to perform its
duties under or delegated to it under the Trust Indenture or any other
contract), unless such liabilities arise out of the gross negligence, wilful
default or fraud of the Trustee or any of its directors, officers, employees or
shareholders. If the Trustee has retained an appropriate expert, adviser or
legal counsel with respect to any matter connected with its duties under the
Trust Indenture or any other contract, the Trustee may act or refuse to act
based on the advice of such expert, adviser or legal counsel, and the Trustee
shall not be liable for and shall be fully protected from any loss or liability
occasioned by any action or refusal to act based on the advice of any such
expert, adviser or legal counsel. In the exercise of the powers, authorities or
discretion conferred upon the Trustee under the Trust Indenture, the Trustee is
and shall be conclusively deemed to be acting as Trustee of the assets of the
Trust and shall not be subject to any personal liability for any debts,
liabilities, obligations, claims, demands, judgments, costs, charges or expenses
against or with respect to the Trust or the Trust Fund. In addition, the Trust
Indenture contains other customary provisions limiting the liability of the
Trustee.
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Amendments to the Trust Indenture
The Trust Indenture may be amended or altered from time to time by Special
Resolution. The Trustee may, without the consent, approval or ratification of
any of the Unitholders, amend the Trust Indenture for the purpose of:
o ensuring the Trust's continuing compliance with applicable laws or
requirements of any governmental agency or authority of Canada or of any
province;
o ensuring that the Trust will satisfy the provisions of each of subsections
108(2) and 132(6) of the Tax Act as from time to time amended or replaced;
o ensuring that such additional protection is provided for the interests of
Unitholders as the Trustee may consider expedient;
o removing or curing any conflicts or inconsistencies between the provisions
of the Trust Indenture or any supplemental indenture, any Direct Royalties
Sale Agreement, and any other agreement of the Trust or any Offering
Document pursuant to which securities of the Trust are issued with respect
to the Trust, or any applicable law or regulation of any jurisdiction,
provided that in the opinion of the Trustee the rights of the Trustee and
of the Trust Unitholders are not prejudiced thereby;
o providing for the electronic delivery by the Trust to Unitholders of
documents relating to the Trust (including annual and quarterly reports,
including financial statements, notices of Unitholder meetings and
information circulars and proxy related materials) once applicable
securities laws have been amended to permit such electronic delivery in
place of normal delivery procedures, provided that such amendments to the
Trust Indenture are not contrary to or do not conflict with such laws;
o curing, correcting or rectifying any ambiguities, defective or
inconsistent provisions, errors, mistakes or omissions, provided that in
the opinion of the Trustee the rights of the Trustee and of the
Unitholders are not prejudiced thereby; and
o making any modification in the form of the Trust Unit certificates to
conform with the provisions of the Trust Indenture, or any other
modifications provided the rights of the Trustee and the Unitholder are
not prejudiced thereby.
Take-Over Bid
The Trust Indenture contains provisions to the effect that if a take-over bid is
made for the Trust Units and not less than 90% of the Trust Units (other than
Trust Units held at the date of the takeover bid by or on behalf of the offeror
or associates or affiliates of the offeror) are taken up and paid for by the
offeror, the offeror will be entitled to acquire the Trust Units held by
Unitholders who did not accept the takeover bid on the terms offered.
Termination of the Trust
Unitholders may vote to terminate the Trust at any meeting of the Unitholders
duly called for that purpose, subject to the following: (a) a vote may only be
held if requested in writing by the holders of not less than 20% of the
outstanding Trust Units; (b) a quorum of 50% of the issued and outstanding Trust
Units is present in person or by proxy; and (c) the termination must be approved
by Special Resolution of Unitholders.
Unless the Trust is earlier terminated or extended by vote of the Unitholders,
the Trustee shall commence to wind-up the affairs of the Trust on December 31,
2099. In the event that the Trust is wound-up, the Trustee will sell and convert
into cash the Direct Royalties and other assets comprising the Trust Fund in one
transaction or in a series of transactions at public or private sale and do all
other acts appropriate to liquidate the Trust Fund, and shall in all respects
act in accordance with the directions, if any, of the Unitholders in respect of
termination authorized pursuant to the Special Resolution authorizing the
termination of the Trust. However, in no event shall the Trust be wound-up until
the Direct Royalties have been disposed of. After paying, retiring or
discharging, or making
59
provision for the payment, retirement, or discharge of all known liabilities and
obligations of the Trust and after providing for indemnity against any other
outstanding liabilities and obligations, the Trustee shall distribute the
remaining part of the proceeds of the sale of the assets together with any cash
forming part of the property of the Trust among the Unitholders in accordance
with their Pro Rata Share.
Reporting to Unitholders
The consolidated financial statements of the Trust will be audited annually by
an independent recognized firm of chartered accountants. The audited
consolidated financial statements of the Trust, together with the report of such
chartered accountants, will be mailed by the Corporation to Unitholders and the
unaudited interim consolidated financial statements of the Trust will be mailed
to Unitholders within the periods prescribed by securities legislation. The year
end of the Trust is December 31. The Trust is subject to the continuous
disclosure obligations under all applicable securities legislation.
TRUST UNIT INCENTIVE PLAN
The Trust has adopted the Unit Incentive Plan which permits the Harvest Board to
grant non-transferable rights to purchase Trust Units ("Incentive Rights") to
the directors, officers, consultants, employees and other ongoing service
providers of the Trust and its subsidiaries, including the Corporation. The
purpose of the Unit Incentive Plan is to provide an effective long term
incentive to eligible participants and to reward them on the basis of long term
performance and distributions. Effective June 22, 2004 the total number of Trust
Units issuable under the Unit Incentive Plan was increased from 1,121,000 Trust
Units to a cumulative maximum number of 1,487,250 Trust Units. The total number
of Trust Units outstanding under the Unit Incentive Plan as at March 16, 2005
was 1,189,000.
The Harvest Board administers the Unit Incentive Plan and determines
participants in the Unit Incentive Plan, numbers of Incentive Rights granted,
and the terms of vesting of Incentive Rights. The grant price of the Incentive
Rights (the "Grant Price") shall be equal to the per Trust Unit closing price on
the trading date immediately preceding the date of grant, unless otherwise
permitted. Management has proposed in its Information Circular - Proxy dated
March 30, 2005 that the grant price be revised in connection with changes to the
TSX rules. Under these new rules, grant price cannot exceed market price, which
is based on the volume weighted average trading price of the trust units for the
5 trading days prior to the date of grant The exercise price ("Exercise Price")
per Right shall be calculated by deducting from the Grant Price in respect of
each distribution made by the Trust after the Grant Date (on a per Unit basis)
an amount that will in no case exceed the amount of the distribution, provided
the Trust's net operating cash flow for that month in which the distribution was
made exceeds 0.833% of the Trust's recorded cost of capital assets less all
debt, working capital deficiency (surplus) or debt equivalent instruments,
depletion, depreciation and amortization charges, asset retirement obligations
and any future income tax liability associated with such capital assets at the
end of each month. When Incentive Rights are exercised, the amount by which
distributions since the grant date exceed the cumulative reduction in the
exercise price is paid to the holder in cash on a semi-annual basis.
Incentive Rights are exercisable for a maximum of five years from the date of
the grant thereof and are subject to early termination upon the holder ceasing
to be an eligible participant, or upon the death of the holder. In the case of
early termination, a holder is entitled, from the date the holder ceased to be
an eligible participant to the earlier of 30 days and the end of the exercise
period, to exercise vested Incentive Rights. In the case of death, the estate of
the holder is entitled, from the date of death to the earlier of 6 months and
the end of the exercise period, to exercise vested Incentive Rights at the
Exercise Price in effect at the date of death. Incentive Rights not vested at
the date of termination of the holder or at date of the holder's death are
immediately null and void. The holder has the option to settle outstanding
Incentive Rights with Trust Units and/or cash. The number of Trust Units to be
issued to settle outstanding Incentive Rights shall equal the amount determined
by multiplying the number of Incentive Rights by the quotient obtained by
dividing the difference between the current market price of a Trust Unit and the
Exercise Price by the current market price of a Trust Unit. Cash paid to settle
outstanding Incentive Rights will equal the difference between the current
market price of a Trust Unit less the Exercise Price multiplied by the number of
Incentive Rights to be settled.
60
The following table sets forth information with respect to the Incentive Rights
outstanding under the Unit Incentive Plan as at March 16, 2005:
Weighted Average
Exercise Price Market Value of
Range of Incentive Trust Units Weighted Average as at March 16, Incentive Right
Group Rights Grant Dates Under Option Grant Price 2005(1) (2)
- ----------------- ------------------- -------------- ------------------- ------------------ ---------------
Executive November 25, 2002
Officers (4) to July 14, 2004 406,050 $9.61 $5.05 $8,291,541
November 25, 2002
Directors (5) to February 14, 2003 100,000 $8.69 $3.39 $2,208,000
Employees and November 25, 2002
Consultants (92) to March 16, 2005 682,950 $15.11 $12.64 $8,762,249
Notes:
(1) Includes the value accrued to holders to the extent that distributions
since the grant date exceed cumulative exercise price reductions.
(2) Based on the difference between the closing price of $25.47 per Trust Unit
on the TSX on March 16, 2005 and the exercise price of the Incentive Right
multiplied by the number of Trust Units under the Incentive Right.
DRIP PLAN
The Trust has received all applicable regulatory approvals and has implemented a
DRIP Plan. The DRIP Plan is not available to Unitholders who are residents of
the United States. The DRIP Plan provides eligible holders of Trust Units the
means of accumulating additional Trust Units by reinvesting any Distributable
Cash received. At the discretion of the Corporation, Trust Units will either be
acquired at prevailing market rates (not exceeding 115% of the volume weighted
average trading price of the Trust Units on the TSX for the 10 trading days
immediately preceding the date the Trust Units are purchased) or issued from
treasury at 95% of the market price of the Trust Units (calculated as the
weighted average trading price of the Trust Units on the TSX for the period
commencing on the second Business Day following the distribution record date and
ending on the second Business Day immediately prior to the distribution payment
date on which at least a board lot of Trust Units is traded). Participants in
the DRIP Plan are also permitted to purchase additional Trust Units at 100% of
the market price (as described above) of the Trust Units by investing additional
sums to a maximum of $5,000 per month and a minimum of $1,000 per remittance;
provided that the total number of Trust Units that may be issued each fiscal
year pursuant to optional cash payments is restricted to not more than 2% of the
number of issued and outstanding Trust Units at the commencement of that year.
As at March 16, 2005, 1,913,686 Trust Units have been issued from treasury since
February 15, 2003 for proceeds of approximately $27,233,179 million due to DRIP
Plan participation associated with cash distributions by the Trust.
CONFLICTS OF INTEREST
Properties will not be acquired from officers or directors of the Corporation or
persons not at arm's length with such persons at prices which are greater than
fair market value, nor will Properties be sold to officers or directors of the
Corporation or persons not at arm's length with such persons at prices which are
less than fair market value in each case as established by an opinion of an
independent financial advisor and approved by the independent members of the
Harvest Board. There may be circumstances where certain transactions may also
require the preparation of a formal valuation and the affirmative vote of
Unitholders in accordance with the requirements of Ontario Securities Commission
Rule 61-501.
Circumstances may arise where members of the Harvest Board serve as directors or
officers of corporations which are in competition with the interests of the
Corporation and the Trust. No assurances can be given that opportunities
identified by such board members will be provided to the Corporation and the
Trust.
61
AUDIT COMMITTEE INFORMATION
Audit Committee Mandate and Terms of Reference
The Mandate and Terms of Reference of the Audit Committee of the board of
directors is attached hereto as Appendix "D". The members of the Audit Committee
are John Brussa, Verne Johnson and Hector McFadyen. Mr. Brussa is deemed to be
the financial expert. By May 4, 2005, the date of Harvest's next annual general
and special meeting of unitholders, Mr. Brussa will no longer sit on the Audit
Committee as he is a Related Director given that his law firm provides services
to the Trust. The Board will be required to appoint another Director to the
Audit Committee in his place.
Composition of the Audit Committee
The members of the Audit Committee are independent (in accordance with National
Instrument 52-110) except as noted above and are financially literate.
Relevant Education and Experience
The financial expert, Mr. Brussa, has been a partner of his law firm for a
number of years and is considered a leading tax practitioner in Canada. Mr.
Brussa sits on the boards and audit committees of several other public
companies.
Pre-Approval of Policies and Procedures
All non-audit or special services performed by any independent accountants must
be first approved by the Audit Committee. All remuneration provided to the
Trust's auditor and any independent accountants are also approved by the Audit
Committee. The Trust's auditor meets with the Audit Committee, without
management present, at least annually and more often at the request of either
the Audit Committee or the auditor.
External Auditor Service Fees
Audit Fees
The aggregate fees billed by the Corporation's external auditor in each of the
last two fiscal years for audit services (audit and review of Harvest's annual
financial statements and review of quarterly financial statements), were
$377,634 in 2004 and $238,500 in 2003.
Audit and Related Fees
The aggregate fees billed in each of the last two fiscal years for assurance
related services by the Corporation's external auditor that are reasonably
related to the performance of the audit or review of the Corporation's financial
statements that are not reported under "Audit Fees" above were $83,510 in 2004
and $42,500 in 2003. These fees are primarily related to French translation
fees.
Tax Fees
The aggregate fees billed in each of the last two fiscal years for professional
services rendered by the Corporation's external auditor for regular tax
compliance, tax advice and tax planning were $111,275 in 2004 and $65,820 in
2003.
All Other Fees
The aggregate fees billed in each of the last two fiscal years for products and
services provided by the Corporation's auditors other than services reported
above were nil in 2004 and in 2003.
62
PROMOTERS
Kevin A. Bennett and M. Bruce Chernoff may be considered to be the promoters of
the Corporation by reason of their initiative in organizing the business and
affairs of the Corporation. The following table sets forth the number of
securities owned, directly or indirectly, by Messrs. Bennett and Chernoff.
- ----------------------------------------------------------------------------------------------------------------------
Name and Municipality of Number of
Residence of Promoter Type of Ownership Trust Units Owned Percentage of Trust Units
- ----------------------------------------------------------------------------------------------------------------------
Kevin A. Bennett Direct and Beneficial 500,000(1) 1.2%
Calgary, Alberta
- ----------------------------------------------------------------------------------------------------------------------
M. Bruce Chernoff Direct and Beneficial 7,645,130(2) 18.0%
Calgary, Alberta
- ----------------------------------------------------------------------------------------------------------------------
Notes:
(1) Does not include units held by Mr. Bennett's spouse.
(2) Includes Trust Units held by companies controlled by Mr. Chernoff, and
Trust Units held in RESP accounts for the benefit of Mr. Chernoff's
children.
Mr. Chernoff has from time to time, directly or indirectly, provided various
loans to the Trust. The terms of such loans are described in "Description of the
Trust - Borrowing by the Trust - Equity Bridge Notes".
LEGAL PROCEEDINGS
There are no legal proceedings which the Corporation or any subsidiary of the
Corporation is a party or of which any of their property is subject which are
material to the Corporation and the Corporation is not aware of any such
proceedings that are contemplated or pending.
RECORD OF CASH DISTRIBUTIONS
The following table sets forth the per Trust Unit amount of monthly cash
distributions paid by the Trust since the completion of the Initial Public
Offering.
2003 Distribution Per Trust Unit
January (1) $0.20
February $0.20
March $0.20
April $0.20
May $0.20
June $0.20
July $0.20
August $0.20
September $0.20
October $0.20
November $0.20
December $0.20
2004
January $0.20
February $0.20
March $0.20
April $0.20
May $0.20
------------------------------------------
63
June $0.20
July $0.20
August $0.20
September $0.20
October $0.20
November $0.20
December $0.20
2005
January $0.20
February(2) $0.20
March $0.20
April(3) $0.20
-----
$5.60
=====
Notes:
(1) This distribution was the first cash distribution paid by the Trust
following the completion of the Initial Public Offering.
(2) The Trust announced on February 28, 2005 that it would pay an extra
distribution valued at $0.252 in the form of trust units to holders of
record on March 31, 2005.
(3) The Trust announced on March 14, 2005 that the next monthly cash
distribution of $0.20 per Trust Unit will be paid on April 15, 2005 to
Unitholders of record on March 31, 2005.
Unitholders of record on a Record Date will be entitled to receive monthly cash
distributions of the Distributable Cash which will become payable on the 15th
day following the Record Date, and if such date of payment is not a Business Day
on the next Business Day after the 15th day following the Record Date.
ESCROWED SECURITIES
To the knowledge of the Corporation, no securities of the Corporation are held
in escrow.
INTERESTS OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS
There were no material interests, direct or indirect, of directors and senior
officers of the Corporation, any shareholder who beneficially owns more than 10%
of the outstanding Common Shares, or any known associate or affiliate of such
persons, in any transaction within the last fiscal year and in any proposed
transaction which has materially affected or would materially affect the
Corporation other than the transactions described under "Description of the
Trust - Borrowing by the Trust - Equity Bridge Notes".
TRANSFER AGENT AND REGISTRAR
Valiant Trust Company, at its principal offices in Calgary, Alberta, is the
transfer agent and registrar of the Trust Units, Exchangeable Shares, and
Convertible Debentures of the Corporation.
MATERIAL CONTRACTS
Except for contracts entered into in the ordinary course of business, the only
material contracts entered into by the Corporation within the most recently
completed financial year, or before the most recently completed financial year
but still in effect, are the following:
1. the Trust Indenture between Harvest Operations Corp. and Valiant Trust
Company described in "Trust Indenture";
2. the Indenture between Harvest Energy Trust, Harvest Operations Corp. and
Valiant Trust Company in connection with the convertible debentures
described in "Description of the Trust - Borrowing by the Trust -
Convertible Debentures";
64
3. the Indenture between Harvest Operations Corp., the Subsidiary Guarantors,
Harvest Energy Trust and U.S. Bank National Association in connection with
the senior notes as described in "Information Respecting the Corporation -
Borrowing by the Corporation - Senior Notes";
4. the Exchangeable Share provisions referred to under "Description of
Capital Structure - Exchangeable Shares of the Corporation";
5. the Support Agreement between Harvest Energy Trust, Harvest Operations
Corp., Harvest Exchangeco Ltd. and Valiant Trust Company referred to under
"Description of Capital Structure - Exchangeable Shares of the
Corporation";
6. the Voting and Exchange Trust Agreement between Harvest Energy Trust,
Harvest Operations Corp., Harvest Exchangeco Ltd. and Valiant Trust
Company referred to under "Description of Capital Structure - Exchangeable
Shares of the Corporation"; and,
7. the Trust's Trust Unit Rights Incentive Plan and Unit Award Incentive
Plan.
INTERESTS OF EXPERTS
There is no person or company whose profession or business gives authority to a
statement made by such person or company and who is named as having prepared or
certified a statement, report or valuation described or included in a filing, or
referred to in a filing, made under National Instrument 51-102 by the
Corporation during, or related to, the Corporation's most recently completed
financial year other than McDaniel, GLJ and PLA, the Corporation's Independent
Reserve Engineering Evaluators. As at the date hereof, none of the principals of
McDaniel and Associates Ltd., Gilbert Laustsen Jung Associates Ltd., and Paddock
Lindstrom and Associates Ltd., as a group, directly or indirectly, owned more
than 1% of the Units.
In addition, none of the aforementioned persons or companies, nor any director,
officer or employee of any of the aforementioned persons or companies, is or is
expected to be elected, appointed or employed as a director, officer or employee
of the Corporation or of any associate or affiliate of the Corporation.
MARKET FOR SECURITIES
The Trust Units and convertible debentures are listed and traded on the TSX. The
trading symbol for the Trust Units is "HTE.UN", and for the convertible
debentures is "HTE.DB" and "HTE.DB.A".
The following sets forth the price range and trading volume of the Trust Units
on the TSX (as reported by the TSX) for the periods indicated.
Price Range
------------------------
High Low Volume
------ ------ ---------
2004
January $14.40 $12.65 1,091,793
February $13.99 $12.15 1,061,991
March $15.18 $13.60 1,316,461
April $15.49 $14.55 1,397,530
May $15.45 $14.60 1,862,143
June $15.07 $13.80 959,139
July $17.53 $14.75 3,526,288
August $18.10 $16.00 8,758,948
September $20.79 $16.85 7,023,949
October $24.03 $20.56 12,071,497
November $23.64 $19.82 5,978,590
December $23.50 $21.40 3,544,495
65
Price Range
------------------------
High Low Volume
------ ------ ---------
2005
January $24.00 $22.10 2,987,380
February $25.97 $23.75 3,533,047
March (1-16) $26.14 $24.80 2,595,887
RISK FACTORS
The following are certain factors relating to the business of the Trust. The
following information is a summary only of certain risk factors and is qualified
in its entirety by reference to, and must be read in conjunction with, the
detailed information appearing elsewhere in this Annual Information Form.
Volatility of Commodity Prices and Foreign Exchange Risk
The Trust's results of operations and financial condition, and therefore the NPI
and the Direct Royalties, will be dependent on the prices received for
petroleum, natural gas and natural gas liquids production. Prices for petroleum,
natural gas and natural gas liquids have fluctuated widely during recent years
and are determined by supply and demand factors, including weather and general
economic conditions as well as conditions in other oil producing regions, which
are beyond the control of the Corporation or the Trust. Oil prices received from
production in Canada also reflect changes in the Canadian/U.S. currency exchange
rate. Any decline in petroleum oil and natural gas prices or increases in
differentials could have a material adverse effect on the Trust's operations,
financial condition and the level of funds available for the development of its
oil and natural gas reserves. The Corporation may manage the risk associated
with changes in commodity prices and foreign exchange rates by entering, or
causing the Trust to enter, from time to time, into crude oil and natural gas
price hedges and foreign exchange contracts. To the extent that the Corporation
or the Trust engages in risk management activities related to commodity prices
and foreign exchange rates, it will be subject to counterparty risk. In
addition, commodity hedge contracts may require, from time to time, margin
payments to be made which could impact negatively on the Trust's ability to make
distributions to Unitholders. To the extent that commodity prices increase
significantly, Cash Available for Distribution could be negatively affected.
Crude Oil Differentials
In the fourth quarter of 2004, the Corporation's crude oil production from the
Properties was approximately 33% light oil, 51% medium and heavy oil, 13%
natural gas, and 3% natural gas liquids. Processing medium oil and heavy oil is
more expensive than processing conventional light oil, and such processing
yields less valuable products compared to refining light oil; accordingly,
producers of heavy oil or medium oil receive lower wellhead prices. The
differential between light oil and heavy oil or medium oil has fluctuated widely
during recent years and when considered with the fluctuating prices of light
oil, substantially increases the volatility of prices for heavy oil and medium
oil. Any increase in the differentials could result in lower prices being
received for petroleum, natural gas and natural gas liquids and could have a
material adverse effect on the Trust's operations, financial condition and the
level of funds available for the development of its oil and natural gas
reserves. Volatility in the differential is a result of an availability of
supply, seasonal demand, pipeline constraints and conversion capacity of
refineries, which are beyond the control of the Trust or the Corporation.
Operational Matters
The operation of oil and natural gas wells involves a number of operating and
natural hazards which may result in blowouts, environmental damage and other
unexpected or dangerous conditions resulting in damage to the Corporation's
assets and possible liability to third parties. The Corporation will employ
prudent risk management
practices and maintain liability insurance, where available, in amounts
consistent with industry standards. Business interruption insurance may also be
purchased for selected facilities, to the extent that such insurance is
available. The Corporation may become liable for damages arising from such
events against which it cannot insure or against
66
which it may elect not to insure because of high premium costs or other reasons.
Costs incurred to repair such damage or pay such liabilities will reduce income
from the NPI.
Continuing production from a property and to some extent, the marketing of
production therefrom, are largely dependent upon the ability of the operator of
the property. To the extent the operator fails to perform these functions
properly, revenue may be reduced. Payments from production generally flow
through the operator and there is a risk of delay and additional expense in
receiving such revenues if the operator becomes insolvent. Although the
Corporation operates the majority of its Properties, there is no guarantee that
it will remain operator of such Properties or that the Corporation will operate
other Properties it may acquire.
A significant portion of the operating expenses at the East Central Alberta
Properties, Southern Alberta Properties and to a lesser degree, the Southeast
Saskatchewan Properties, is attributable to electrical power costs. Since
deregulation of the electrical power system in Alberta in recent years, the unit
cost of electrical power has been set by a market driven mechanism based upon
supply and demand. As a result, the prices for electrical power have become
volatile. This volatility in electrical power pricing can impact the
Corporation's operating expenses, and in turn, the Cash Available For
Distribution. The Corporation has implemented an electrical power hedging
program to mitigate its exposure to electrical power cost volatility. In respect
of the Southeast Saskatchewan Properties, the Saskatchewan power system is
regulated and as such, electrical power costs are not subject to significant
volatility. However, there can be no certainty that the Saskatchewan power
system will not deregulate in the future.
Although satisfactory title reviews will generally be conducted on the
Properties in accordance with industry standards, such reviews do not guarantee
or certify that a defect in title may not arise to defeat the claim of the
Corporation to certain Properties. A reduction of income from the NPI or income
from Direct Royalties could result in such circumstances.
Harvest's ability to market oil and natural gas from its wells also depends upon
numerous other factors beyond its control, including:
o The availability of capacity to refine heavy oil;
o The availability of natural gas processing capacity;
o The availability of pipeline capacity;
o The availability of diluent to blend with heavy oil to enable
transportation;
o The price of oilfield services
o the effects of inclement weather;
Because of these factors, Harvest may be unable to market all of the oil or
natural gas it produces or to obtain favourable prices for the oil and natural
gas it produces.
Reserve Estimates
The reserve and recovery information contained in the Reserve Report is only an
estimate, such estimates are complex to determine, and the actual production and
ultimate reserves recovered from the Properties may differ from the estimates
prepared by the Independent Reserve Engineering Evaluators.
Depletion of Reserves (Sustainability)
The Trust has certain unique attributes which differentiate it from other oil
and natural gas industry participants. Cash Available For Distribution in
respect of Properties, absent commodity price increases or cost effective
acquisition and development activities, will decline over time in a manner
consistent with declining production from typical oil, natural gas and natural
gas liquids reserves. The Trust and the Corporation will not be reinvesting cash
flow in the same manner as other industry participants as it makes cash
distribution payments to unitholders.
67
Accordingly, absent additional capital investment in Properties through the use
of the Capital Fund or otherwise, initial production levels and reserves
attributable to the Properties will decline.
The Corporation's future oil and natural gas reserves and production, and
therefore its cash flows, will be highly dependent on the Corporation's success
in exploiting its reserve base and acquiring additional reserves. Without
reserve additions through acquisition or development activities, the
Corporation's reserves and production will decline over time as reserves are
produced.
Trust Units will have no value when reserves from the Properties can no longer
be economically produced and, as a result, subscribers for Trust Units will need
to obtain a return of capital invested during the period when reserves can be
economically recovered.
There is strong competition relating to all aspects of the oil and natural gas
industry. The Corporation will actively compete for reserve acquisitions and
skilled industry personnel with a substantial number of other oil and natural
gas companies, many of which have significantly greater financial and other
resources than the Corporation.
There can be no assurance that the Corporation will be successful in developing
or acquiring additional reserves on terms that meet the Corporation's investment
objectives.
Debt Service
As at the date hereof, the Trust had indebtedness of approximately $90 million
under the Current Bank Facility. In addition, the New Lender has issued letters
of credit to third parties of approximately $5 million on behalf of the
Corporation to secure services on the Properties. The Corporation issued
U.S.$250 million of senior notes due October 15, 2011 on which semi-annual
interest payments are due. See "Information Respecting the Corporation -
Borrowing by the Corporation".
The Current Lenders have been provided with security over all of the assets of
the Operating Subsidiaries. If the Corporation experiences an unremedied
borrowing base shortfall or default, commits an event of default or the Current
Lenders demand repayment, the Current Lenders may foreclose on or sell the
Properties free from, or together with, the NPI.
Dividends and other distributions by the Corporation are prohibited in certain
circumstances upon a borrowing base shortfall or default, or upon an event of
default or demand for repayment under the Current Bank Facility. The NPI, any
indebtedness of the Corporation or other Operating Subsidiaries to the Trust,
and amounts payable to the Trustee under the Trust Indenture are subordinate to
the Current Bank Facility pursuant to subordination agreements between the
Current Lenders, the Trustee, and the Operating Subsidiaries dated September 1,
2004. These subordination agreements may restrict the ability of the Corporation
or the Operating Subsidiaries to pay the NPI to the Trust or pay interest or
principal on any indebtedness to the Trust or other amounts owing to the Trust,
and therefore may limit or eliminate the Cash Available For Distribution.
The Corporation must meet certain ongoing financial and other covenants under
the Current Bank Facility. The covenants are customary restrictions on the
Corporation's operations and activities, including restrictions on the incurring
of indebtedness, the granting of security, the issuance of incremental debt, and
the sale of its assets.
The Corporation is also subject to certain covenants under its senior note
indenture, including limitations on the ability of the Corporation or the Trust
to issue incremental debt, and to pay cash distributions to unitholders in
certain circumstances.
Dilution
The Trust Indenture provides that Trust Units, including rights, warrants and
other securities to purchase, to convert into or to exchange into Trust Units,
may be created, issued, sold and delivered on such terms and conditions and at
such times as the Harvest Board may determine. In addition, the Trust may issue
additional Trust Units from time to time pursuant to the Unit Incentive Plan and
the DRIP Plan. The possible issuance of these Trust Units could result in
dilution to holders of Trust Units. See "Trust Indenture - Issuance of Trust
Units", "Trust Unit Incentive Plan" and "DRIP Plan".
68
Failure to Realize an Adequate Rate of Return on Prices Paid for Properties
The prices paid for the purchase of acquisitions made during the current and
prior years were based, in part, on engineering and economic assessments made by
independent engineers. These assessments include a number of material
assumptions regarding such factors as recoverability and marketability of crude
oil, natural gas and natural gas liquids, future prices of oil, natural gas and
natural gas liquids and operating costs, future capital expenditures and
royalties and other government levies which will be imposed over the producing
life of the reserves. Many of these factors are subject to change and are beyond
the control of the Corporation and the Trust. In particular, changes in the
prices of and markets for petroleum, natural gas and natural gas liquids from
those anticipated at the time of making such assessments will affect the return
on the value of the Trust Units. In addition, all such assessments involve a
measure of geological and engineering uncertainty which could result in lower
production and reserves than those currently attributed to the Properties.
Changes in Legislation
There can be no assurance that income and capital tax laws, government incentive
programs and regulations relating to the oil and natural gas industry, such as
the status of mutual fund trusts, the resource allowance and environmental and
operating regulations, will not be changed in a manner which adversely affects
Unitholders.
Investment Eligibility
If the Trust ceases to qualify as a mutual fund trust, the Trust Units will
cease to be qualified investments for registered retirement savings plans
("RRSPs"), registered retirement income funds ("RRIFs"), deferred profit sharing
plans ("DPSPs") and registered education savings plans ("RESPs") (collectively,
"Exempt Plans"). Where at the end of any month an Exempt Plan holds Trust Units
that are not qualified investments, the Exempt Plan must, in respect of that
month, pay a tax under Part XI.1 of the Tax Act equal to 1% of the fair market
value of the Trust Units at the time such Trust Units were acquired by the
Exempt Plan. In addition, where a trust governed by an RRSP holds Trust Units
that are not qualified investments, the trust will become taxable on its income
attributable to the Trust Units or any gains realized on a disposition of the
Trust Units while they are not qualified investments.
Environmental Concerns
The oil and natural gas industry is subject to environmental regulation pursuant
to local, provincial and federal legislation. A breach of such legislation may
result in the imposition of fines or the issuance of clean up orders in respect
of the Corporation or the Properties. Such legislation may be changed to impose
higher standards and potentially more costly obligations on the Corporation. See
"Industry Conditions - Environmental Regulation".
In December 2002, the Government of Canada ratified the Kyoto Protocol (the
"Protocol"). The Protocol calls for Canada to reduce its greenhouse gas
emissions to 6 percent below 1990 levels during the period between 2008 and
2012. The Protocol was subsequently ratified and became legally binding, and is
expected to affect the operation of all industries in Canada, including the oil
and natural gas industry. As details of the implementation of this Protocol have
yet to be announced, it is difficult to determine what, if any, the impact the
Protocol may have on the Corporation's ongoing environmental liabilities, on
prices for oil and natural gas or on other general economic factors, which may
affect the Trust's Cash Available For Distribution.
Debt Repayment
The Corporation and the Trust are permitted to borrow funds to finance the
purchase of Properties, capital expenditures, or other financial obligations in
respect of the Properties or for working capital purposes. Borrowings of the
Corporation to fund the purchase of Canadian resource properties may be repaid
with funds received from the Trust. Debt service costs of the Operating
Subsidiaries are deducted in computing income from the NPI and debt service
costs of the Trust are deducted in computing Cash Available For Distribution.
Variations in interest rates could result in significant changes in the amount
required to be applied to debt service before payment of the NPI and Cash
Available For Distribution. Interest and principal payable pursuant to the
senior notes is payable in U.S. dollars. The Corporation is permitted to borrow
funds under the Current Credit Facility in U.S. dollars and would be
69
required to settle interest and principal amounts in the same currency.
Variations in the Canadian/U.S. dollar exchange could result in a significant
increase in the amount of the interest paid under the Current Bank Facility and
the Senior Notes, thereby reducing the Cash Available For Distribution. See
"Information Respecting the Corporation - Borrowing by the Corporation".
Delay in Cash Distributions
In addition to the usual delays in payment by purchasers of oil and natural gas
to the operators of the Properties, and by the operator to the Corporation,
payments between any of such parties may also be delayed by restrictions imposed
by lenders, delays in the sale or delivery of products, delays in the connection
of wells to a gathering system, blowouts or other accidents, recovery by the
operator of expenses incurred in the operation of Properties or the
establishment by the operator of reserves for such expenses.
Variability of Cash Distributions
The Operating Subsidiaries retain a portion of the cash flows from the
Properties in their Reserve Fund to facilitate future acquisitions and
development of the Properties. Management of the Corporation believes this will
assist in maintaining distributions for a longer period than would otherwise be
the case if all cash flows from the Properties were paid to the Trust and
subsequently distributed to the Unitholders. Future cash flows generated by such
additional Properties may not be similar to those of the existing Properties and
may not generate sufficient cash flows to allow the Operating Subsidiaries to
generate sufficient income to allow the Trust to maintain consistent
distributions from the Trust over a long period of time.
Reliance on Management of the Corporation
Unitholders will be dependent on the management of the Corporation in respect of
the administration and management of all matters relating to the Properties, the
NPI, the Direct Royalties, the Trust, and the Trust Units. Investors who are not
willing to rely on the management of the Corporation should not invest in the
Trust Units.
Return of Capital
Trust Units will have no value when reserves from the underlying assets of the
Trust can no longer be economically produced and, as a result, cash
distributions do not represent a "yield" in the traditional sense as they
represent both return of capital and return on investment.
Additional Financing
To the extent that external sources of capital, including the issuance of
additional Trust Units, becomes limited or unavailable, the Trust's and the
Corporation's ability to make the necessary capital investments to maintain or
expand its oil and natural gas reserves will be impaired. To the extent the
Trust or the Corporation is required to use cash flow to finance capital
expenditures or property acquisitions, the level of Cash Available For
Distribution will be reduced.
Impact of Future Capital Expenditures
The Reserve Value of the Properties as estimated by Independent Reserve
Engineering Evaluators is based in part on cash flows to be generated in future
years as a result of future capital expenditures. The Reserve Value of the
Properties as estimated by the Independent Reserve Engineering Evaluators will
be reduced to the extent that such capital expenditures on the Properties do not
achieve the level of success assumed in such engineering reports.
Competition
There is strong competition relating to all aspects of the oil and natural gas
industry. The Corporation and the Trust will actively compete for capital,
skilled personnel, undeveloped land, reserve acquisitions, access to drilling
rigs, service rigs and other equipment, access to processing facilities and
pipeline and refining capacity, and in all other
70
aspects of its operations with a substantial number of other organizations, many
of which may have greater technical and financial resources than the Corporation
and the Trust. Some of those organizations not only explore for, develop and
produce oil and natural gas but also carry on refining operations and market
petroleum and other products on a world-wide basis and as such have greater and
more diverse resources on which to draw.
Potential Conflicts of Interest
Circumstances may arise where members of the Board of Directors or officers of
the Corporation are directors or officers of corporations which are in
competition to the interests of the Corporation and the Trust. No assurances can
be given that opportunities identified by such board members will be provided to
the Corporation and the Trust. See "Conflicts of Interest".
Nature of Trust Units
Securities such as the Trust Units are hybrids in that they share certain
attributes common to both equity securities and debt instruments. Trust Units
are dissimilar to debt instruments in that there is no principal amount owing to
Unitholders. The Trust Units do not represent a traditional investment in the
oil and natural gas sector and should not be viewed by investors as shares in
the Corporation. The Trust Units represent a fractional interest in the Trust.
As holders of Trust Units, Unitholders will not have the statutory rights
normally associated with ownership of shares of a corporation including, for
example, the right to bring "oppression" or "derivative" actions. The Trust's
sole assets will be Permitted Investments, the NPI, the Direct Royalties and
related contractual rights and units in other wholly-owned trusts. The market
price per Trust Unit will be a function of anticipated Cash Available For
Distribution, the value of the Properties acquired by the Corporation and the
Corporation's ability to effect long-term growth in the value of the Trust. The
issue price of each Trust Unit is greater than the per Trust Unit Reserve Value
of the Properties. The market price of the Trust Units will be sensitive to a
variety of market conditions including, but not limited to, interest rates and
the ability of the Trust to acquire suitable oil and natural gas properties.
Changes in market conditions may adversely affect the trading price of the Trust
Units.
Unitholder Limited Liability
The Trust Indenture provides that no Unitholder, in its capacity as such, shall
incur or be subject to any liability in contract or in tort in connection with
the Trust Fund or the obligations or affairs of the Trust or with respect to any
act performed by the Trustee or by any other person pursuant to the Trust
Indenture or with respect to any act or omission of the Trustee or any other
person in the performance or exercise, or purported performance or exercise, of
any obligation, power, discretion or authority conferred upon the Trustee or
such other person hereunder or with respect to any transaction entered into by
the Trustee or by any other person pursuant to the Trust Indenture. No
Unitholder shall be liable to indemnify the Trustee or any such other person
with respect to any such liability or liabilities incurred by the Trustee or by
any such other person or persons or with respect to any taxes payable by the
Trust or by the Trustee or by any other person on behalf of or in connection
with the Trust. Notwithstanding the foregoing, to the extent that any
Unitholders are found by a court of competent jurisdiction to be subject to any
such liability, such liability shall be enforceable only against, and shall be
satisfied only out of, the Trust Fund, and the Trust (to the extent of the Trust
Fund) is liable to, and shall indemnify and save harmless any Unitholder against
any costs, damages, liabilities, expenses, charges or losses suffered by any
Unitholder from or arising as a result of such Unitholder not having any such
limited liability.
The Trust Indenture also provides that all contracts signed by or on behalf of
the Trust, whether by the Corporation, the Trustee, or otherwise, must (except
as the Trustee or the Corporation may otherwise expressly agree with respect to
their own personal liability) contain a provision to the effect that such
obligation will not be binding upon Unitholders personally. Notwithstanding the
terms of the Trust Indenture, Unitholders may not be protected from liabilities
of the Trust to the same extent a shareholder is protected from the liabilities
of a corporation. Personal liability may also arise in respect of claims against
the Trust (to the extent that claims are not satisfied by the Trust) that do not
arise under contracts, including claims in tort, claims for taxes and possibly
certain other statutory liabilities. The possibility of any personal liability
to Unitholders of this nature arising is considered unlikely by the Harvest
Board in view of the fact that all business operations are carried on by the
Corporation.
71
The activities of the Trust and the Corporation, its wholly-owned subsidiary,
are conducted and are intended to be conducted, upon the advice of counsel, in
such a way and in such jurisdictions as to avoid as far as possible any material
risk of liability to the Unitholders for claims against the Trust including by
obtaining appropriate insurance, where available, for the operations of the
Corporation and having contracts signed by or on behalf of the Trust include a
provision that such obligations are not binding upon Unitholders personally.
The provinces of Alberta and Ontario have recently passed legislation providing
unitholders of mutual fund trusts the same limited liability protections
afforded shareholders of corporations.
Net Asset Value
The net asset value of the Trust will vary dependent upon a number of factors
beyond the control of management, including oil and natural gas prices. The
trading prices of the Trust Units is also determined by a number of factors
which are beyond the control of management and such trading prices may be
greater than or less than the net asset value of the Trust.
Change in the Trust's Status Under Tax Laws
Harvest presently qualifies as a mutual fund trust for purposes of the Tax Act
and it is intended that the Trust continue to qualify as a mutual fund trust for
such purposes; however, should the status of the Trust as a mutual fund trust be
lost or successfully challenged by a relevant tax authority, certain adverse
consequences may arise. The material consequences of losing mutual fund trust
status are as follows: (i) Trust Units would not constitute qualified
investments for Exempt Plans upon the Trust ceasing to be a mutual fund trust.
Where at the end of any month an Exempt Plan holds Trust Units that are not
qualified investments, the Exempt Plan must, in respect of that month, pay a tax
under Part XI.1 of the Act equal to 1% of the fair market value of the Trust
Units at the time such Trust Units were acquired by the Exempt Plan. An RRSP or
RRIF holding Trust Units that are not qualified investments would become taxable
income attributable to the Trust Units while they are not qualified investments.
RESPs which hold Trust Units that are not qualified investments may have their
registration revoked by the Canada Customs and Revenue Agency; (ii) the Trust
would be required to pay a tax under Part XII.2 of the Tax Act on certain types
of income distributed to unitholders including income generated by oil and
natural gas royalties held by the Trust. The payment of the Part XII.2 tax by
the Trust may have adverse income tax consequences for certain Unitholders,
since the amount of cash available for distribution would be reduced by the
amount of the tax; (iii) the Trust would cease being eligible for the capital
gains refund mechanism available under the Tax Act upon ceasing to be a mutual
fund trust; (iv) Trust Units held by Unitholders that are not residents of
Canada would become taxable Canadian property upon the Trust ceasing to be a
mutual fund trust. Such Unitholders would be subject to Canadian income tax on
any gains realized on a disposition of Trust Units constituting taxable Canadian
property; and (v) the Trust would be subject to alternative minimum tax under
Part I of the Tax Act.
Structure of the Trust
From time to time, the Trust may take steps to organize its affairs in a manner
that minimizes taxes and other expenses payable with respect to the operation of
the Trust and the Operating Subsidiaries and maximizes the amount of cash
available for distributions to Unitholders. If the manner in which the Trust
structures its affairs is successfully challenged by a taxation or other
authority, the amount of cash available for distribution to Unitholders may be
affected.
Change to Non-Resident Taxation
In 2004, the Department of Finance introduced legislation that changes the
Trust's obligation to withhold tax on payments of distributions to
non-residents. Previously, the portion of a distribution that was considered a
return of capital was not subject to withholding tax. As a result of these
proposals being passed into law, 100% of the distribution will be subject to
withholding tax beginning in 2005, regardless of the nature of its components.
72
ADDITIONAL INFORMATION
Additional information including remuneration of directors and officers of the
Corporation, principal holders of the Trust Units, is contained in the
Information Circular - Proxy Statement of the Trust dated March 16, 2005 which
relates to the Annual and Special Meeting of Unitholders to be held on May 4,
2005, and additional financial information is provided in the consolidated
financial statements of the Trust for the year ended December 31, 2004.
The Trust shall provide to any person, upon request to the Secretary of the
Corporation on behalf of the Trust:
(a) a prospectus filed in respect of a distribution of its securities or
debt;
(b) one copy of the Annual Information Form of the Trust, together with
one copy of any document, or the pertinent pages of any document,
incorporated by reference in the Annual Information Form;
(c) one copy of the consolidated financial statements of the Trust for
the most recently completed fiscal year together with the
accompanying report of the auditor and one copy of any subsequent
interim financial statements;
(d) one copy of the Information Circular - Proxy Statement of the Trust
dated March 16, 2005; and
(e) one copy of any other documents that are incorporated by reference
into a prospectus and are not required to be provided under (a) to
(d) above; or
(f) at any other time, one copy of any other documents referred to
above, provided the Trust may require the payment of a reasonable
charge if the request is made by a person who is not a security
holder of the Trust.
For additional copies of the Annual Information Form and the materials listed in
the preceding paragraphs please contact:
Harvest Energy Trust
c/o Harvest Operations Corp.
2100, 330 - 5th Avenue S.W.
Calgary, Alberta T2P 0L4
Toll free in Canada: 1-866-666-1178
Fax: (403) 265-3940
APPENDIX A
REPORT OF MANAGEMENT AND DIRECTORS ON RESERVES DATA AND OTHER INFORMATION
Management of Harvest Operations Corp. (the "Company") on behalf of Harvest
Energy Trust (the "Trust") are responsible for the preparation and disclosure of
information with respect to the Company's and the Trust's other subsidiaries'
oil and natural gas activities in accordance with securities regulatory
requirements. This information includes reserves data, which consist of the
following:
(a) (i) proved and proved plus probable oil and natural gas reserves
estimated as at December 31, 2004 using forecast prices and
costs; and
(ii) the related estimated future net revenue; and
(b) (i) proved oil and natural gas reserves estimated as at December
31, 2004 using constant prices and costs; and
(ii) the related estimated future net revenue.
An independent qualified reserves evaluator has evaluated the Company's and the
Trust's other subsidiaries' reserves data. The report of the independent
qualified reserves evaluator is presented below.
The Reserves, Safety & Environment Committee (the "RSE Committee")
of the board of directors of the Company has
(c) reviewed the Company's procedures for providing information to the
independent qualified reserves evaluators;
(d) met with the independent qualified reserves evaluators to determine
whether any restrictions affected the ability of the independent
qualified reserves evaluators to report without reservation; and
(e) reviewed the reserves data with management and the independent
qualified reserves evaluators.
The RSE Committee of the board of directors has reviewed the Company's
procedures for assembling and reporting other information associated with oil
and natural gas activities and has reviewed that information with management.
The board of directors has, on the recommendation of the Audit Committee,
approved
(f) the content and filing with securities regulatory authorities of the
reserves data and other oil and natural gas information;
(g) the filing of the report of the independent qualified reserves
evaluators on the reserves data; and
(h) the content and filing of this report.
Because the reserves data are based on judgments regarding future events, actual
results will vary and the variations may be material.
(signed) "Jacob Roorda" (signed) "J. A. Ralston"
Jacob Roorda J. A. Ralston
President Vice President, Operations
(signed) "Verne Johnson" (signed) "Hank B. Swartout"
Verne Johnson Hank B. Swartout
Director and Chairman of the RSE Committee Director and Member of the RSE
February 3, 2005 Committee
APPENDIX B
Report on Reserves Data by Independent Qualified Reserves Evaluators
To the Board of directors of Harvest Operations Corp.(the "Corporation"):
1) We have evaluated the Corporation's reserves data as at December 31, 2004.
The reserves data consist of the following:
(a) (i) Proved and proved plus probable oil and gas reserves estimated
as at December 31, 2004 using forecast prices and costs; and
(ii) The related future net revenue; and
(b) (i) Proved oil and gas reserves estimated as at December 31,
2004 using constant prices and costs; and
(ii) +Proved oil and gas reserves estimated as at December 31, 2004
using constant prices and costs; and
2) The reserves data are the responsibility of the Corporation's management.
Our responsibility is to express and opinion on the reserves data base on
our evaluation.
We carried out our evaluation in accordance with standards set out in the
Canadian Oil and Gas Evaluation Handbook (the "COGE Handbook") prepared
jointly by the Society of Petroleum Evaluation Engineers (Calgary Chapter)
and the Canadian Institute on Mining, Metallurgy & Petroleum (Petroleum
Society).
3) Those standards require that we plan and perform an evaluation to obtain
reasonable assurance as to whether the reserves data are free of material
misstatement. An evaluation also includes assessing whether the reserves
data are in accordance with the principles and definitions presented in
the COGE Handbook.
4) The following table sets forth the estimated future net revenue (before
deductions of income taxes) attributed to proved plus probable reserve,
estimate using forecast prices and costs and calculated using a discount
rate of 10 percent, included in the reserves data of the Corporation
evaluated by us for the year ended December 31, 2004 and identifies the
respective portions thereof that we have evaluated and reported on to the
Corporation's Management.
Net Present Value of Future Net Revenue
(Before income taxes, 10% discount rate)
--------------------------------------------
Independent Qualified Descri ption and
Reserves Evaluator or Preparation Date of Location of
Auditor Evaluation Report Reserves Audited Evaluated Reviewed Total
- ------------------------------------------------------------------------------------------------------------
McDaniel and Associates
Consultants Ltd. December 31, 2004 Canada -- 889,738 -- 889,738
Gilbert Laustsen Jung and
Associates Ltd. December 31, 2004 Canada -- 150,375 -- 150,375
Paddock Lindstrom and
Associates Ltd. December 31, 2004 Canada -- 92,374 -- 92,374
-------------------------------------------
Totals 1,132,487 1,132,487
-------------------------------------------
5) In our opinion, the reserves data respectively evaluated by us have, in
all material respects, been determined and are in accordance with the COGE
Handbook. We express no opinion on the reserves data that we reviewed but
did not audit or evaluate.
6) We have no responsibility to update our reports referred to in paragraph 4
for events and circumstances occurring after their respective dates.
7) Because the reserves data are based on judgments regarding future events,
actual results will vary and the variations may be material.
Executed as to our report referred to above:
(signed) McDaniel & Associates Consultants Ltd. (signed) Gilbert Laustsen Jung Associates Ltd.
Calgary, Alberta, Canada Calgary, Alberta, Canada
(signed) Paddock, Lindstrom and Associates Ltd.
Calgary, Alberta, Canada
APPENDIX C
FINANCIAL STATEMENTS
1. Schedule of Revenues, Royalties and Expenses for the New Properties
Acquired from EnCana Corporation - Years Ended December 31, 2003 and 2002
and Three Months Ended March 31, 2004 and 2003.
NEW PROPERTIES
SCHEDULE OF REVENUES, ROYALTIES AND OPERATING EXPENSES
Years Ended December 31, 2003 and
2002 and the Three Months Ended March 31,
2004 and 2003 (unaudited)
($ thousands)
AUDITORS' REPORT
To the Trustee of Harvest Energy Trust and Directors of Harvest Operations Corp.
At the request of Harvest Energy Trust and Harvest Operations Corp., we
have audited the Schedule of Revenues, Royalties and Operating Expenses for the
two years ended December 31, 2003 and 2002 for the New Properties that Harvest
Energy Trust and Harvest Operations Corp. have entered into an agreement to
acquire dated July 15, 2004. This financial information is the responsibility of
management. Our responsibility is to express an opinion on this financial
information based on our audits.
We conducted our audits 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 financial information
presentation.
In our opinion, the Schedule of Revenues, Royalties and Operating Expenses
presents fairly, in all material respects, the revenues, royalties and operating
expenses for the New Properties for each of the years ended December 31, 2003
and 2002 in accordance with the basis of accounting disclosed in note 1.
(Signed)
Calgary, Canada "PRICEWATERHOUSECOOPERS LLP"
July 16, 2004 Chartered Accountants
NEW PROPERTIES
SCHEDULE OF REVENUES, ROYALTIES AND OPERATING EXPENSES ($ thousands)
Three Months Ended March 31 Year Ended December 31
--------------------------------------------------------
2004 2003 2003 2002
--------------------------------------------------------
(unaudited)
Revenues $62,794 $83,982 $274,617 $228,573
Royalties 7,597 10,102 34,250 27,072
--------------------------------------------------------
55,197 73,880 240,367 201,501
Operating expenses 10,498 11,715 45,397 44,854
Excess of revenues over operating expenses ................. $44,699 $62,165 $194,970 $156,647
--------------------------------------------------------
See accompanying Notes to Schedule
NEW PROPERTIES
NOTES TO SCHEDULE OF REVENUES, ROYALTIES AND OPERATING EXPENSES
For the Years Ended December 31, 2003
and 2002 and the Three Months Ended
March 31, 2004 and 2003
(unaudited) ($ thousands)
1. BASIS OF PRESENTATION
The Schedule of Revenues, Royalties and Operating Expenses includes the
operating results relating to the New Properties that Harvest Energy Trust
and Harvest Operations Corp. have entered into an agreement to acquire
dated July 15, 2004. Under the terms of the agreement, Harvest Breeze
Trust No. 1 and No. 2 will acquire Breeze Resources Partnership which owns
these New Properties ("the Properties").
The Properties consist of crude oil and natural gas assets located in the
Crossfield area of Alberta, in southeast Alberta and in east central
Alberta.
The Schedule of Revenues, Royalties and Operating Expenses for the
Properties does not include any provision for the depletion, depreciation
and amortization, asset retirement costs, future capital costs, impairment
of unevaluated properties, administrative costs and income taxes for the
Properties as these amounts are based on the consolidated operations of
the vendor of which the Properties form only a part.
2. SIGNIFICANT ACCOUNTING POLICIES
(A) Joint Venture Operations
Substantially all of the Properties are operated through joint ventures
therefore the schedule reflects only the vendor's proportionate interest.
(B) Revenue Recognition
Revenues are recorded net of related transportation costs when the product
is delivered. Gas revenues are recorded based on AECO reference pricing
used for sales between operating divisions of EnCana Corporation and do
not reflect ultimate marketing related activities. Oil revenues are
recorded based on blended prices established between operating divisions
of EnCana Corporation for similar quality product delivered to a common
carrier.
(C) Royalties
Royalties are recorded at the time the product is produced and sold.
Royalties are calculated in accordance with the applicable regulations
and/or the terms of individual royalty agreements. Crown royalties for
natural gas are based on the Alberta Government posted reference price.
Crown royalties for crude oil are taken in kind by the Alberta Petroleum
Marketing Commission.
(D) Operating Expenses
Operating expenses include amounts incurred on extraction of product to
the surface, gathering, field processing, treating and field storage.
APPENDIX D
HARVEST OPERATIONS CORP.
AUDIT COMMITTEE MANDATE AND TERMS OF REFERENCE
Role and Objective
The Audit Committee (the "Committee") is a committee of the board of directors
(the "Board") of Harvest Operations Corp. ("HOC") to which the Board has
delegated its responsibility for oversight of the nature and scope of the annual
audit, management's reporting on internal accounting standards and practices,
financial information and accounting systems and procedures, financial reporting
and statements and recommending, for approval of the Board, the audited
financial statements, interim financial statements and other mandatory
disclosure releases containing financial information. The primary objectives of
the Committee are as follows:
1. to assist directors to meet their responsibilities (especially for
accountability) in respect of the preparation and disclosure of the
financial statements of Harvest and related matters;
2. to provide better communication between directors and external auditors;
3. to enhance the external auditor's independence;
4. to increase the credibility and objectivity of financial reports; and
5. to strengthen the role of the outside directors by facilitating in depth
discussions between directors on the Committee, management and external
auditors.
Membership of Committee
1. The Committee shall be comprised of at least three (3) directors of HOC,
none of whom are members of management of HOC and all of whom are
"unrelated directors" (as such term is used in the Report of the Toronto
Stock Exchange on Corporate Governance in Canada) and "independent" (as
such term is used in Multilateral Instrument 52-110 -- Audit Committees
("MI 52-110") unless the Board shall have determined that the exemption
contained in Section 3.6 of MI 52-110 is available and has determined to
rely thereon.
2. The Board shall appoint the Committee Chair, who shall be an unrelated
director.
3. All of the members of the Committee shall be "financially literate" (as
defined in MI 52-110) unless the Board shall determine that an exemption
under MI 52-110 from such requirement in respect of any particular member
is available and has determined to rely thereon in accordance with the
provisions of MI 52-110.
Mandate and Responsibilities of Committee
1. It is the responsibility of the Committee to oversee the work of the
external auditors, including resolution of disagreements between
management and the external auditors regarding financial reporting.
2. It is the responsibility of the Committee to satisfy itself on behalf of
the Board with respect to Harvest's Internal Control Systems:
o identifying, monitoring and mitigating business risks; and
o ensuring compliance with legal, ethical and regulatory requirements.
3. It is a primary responsibility of the Committee to review the annual and
interim financial statements of Harvest and related management's
discussion and analysis ("MD&A") prior to their submission to the Board
for approval. The process should include but not be limited to:
o reviewing changes in accounting principles and policies, or in their
application, which may have a material impact on the current or
future years' financial statements;
o reviewing significant accruals, reserves or other estimates such as
the ceiling test calculation;
o reviewing accounting treatment of unusual or non-recurring
transactions;
o ascertaining compliance with covenants under loan agreements;
o reviewing disclosure requirements for commitments and contingencies;
o reviewing adjustments raised by the external auditors, whether or
not included in the financial statements;
o reviewing unresolved differences between management and the external
auditors; and
o obtain explanations of significant variances with comparative
reporting periods.
4. The Committee is to review the financial statements, prospectuses, MD&A,
annual information forms ("AIF") and all public disclosure containing
audited or unaudited financial information (including, without limitation,
annual and interim press releases and any other press releases disclosing
earnings or financial results) before release and prior to Board approval.
The Committee must be satisfied that adequate procedures are in place for
the review of Harvest's disclosure of all other financial information and
shall periodically assess the accuracy of those procedures.
5. With respect to the appointment of external auditors by the Board, the
Committee shall:
o recommend to the Board the external auditors to be nominated;
o recommend to the Board the terms of engagement of the external
auditor, including the compensation of the auditors and a
confirmation that the external auditors shall report directly to the
Committee;
o on an annual basis, review and discuss with the external auditors
all significant relationships such auditors have with the Trust to
determine the auditors' independence;
o when there is to be a change in auditors, review the issues related
to the change and the information to be included in the required
notice to securities regulators of such change; and
o review and pre-approve any non-audit services to be provided to
Harvest or its subsidiaries by the external auditors and consider
the impact on the independence of such auditors. The Committee may
delegate to one or more independent members the authority to
pre-approve non-audit services, provided that the member report to
the Committee at the next scheduled meeting such pre-approval and
the member comply with such other procedures as may be established
by the Committee from time to time.
6. Review with external auditors (and internal auditor if one is appointed by
Harvest) their assessment of the internal controls of Harvest, their
written reports containing recommendations for improvement, and
management's response and follow-up to any identified weaknesses. The
Committee shall also review
annually with the external auditors their plan for their audit and, upon
completion of the audit, their reports upon the financial statements of
Harvest and its subsidiaries.
7. The Committee shall review risk management policies and procedures of
Harvest (i.e. hedging, litigation and insurance).
8. The Committee shall establish a procedure for:
o the receipt, retention and treatment of complaints received by
Harvest regarding accounting, internal accounting controls or
auditing matters; and
o the confidential, anonymous submission by employees of Harvest of
concerns regarding questionable accounting or auditing matters.
9. The Committee shall review and approve Harvest's hiring policies regarding
partners and employees and former partners and employees of the present
and former external auditors of Harvest.
10. The Committee shall have the authority to investigate any financial
activity of Harvest. All employees of Harvest are to cooperate as
requested by the Committee.
11. The Committee may retain persons having special expertise and/or obtain
independent professional advice to assist in filling their
responsibilities at the expense of Harvest without any further approval of
the Board.
Meetings and Administrative Matters
1. At all meetings of the Committee every question shall be decided by a
majority of the votes cast. In case of an equality of votes, the Chairman
of the meeting shall not be entitled to a second or casting vote.
2. The Chair shall preside at all meetings of the Committee, unless the Chair
is not present, in which case the members of the Committee present shall
designate from among the members present the Chair for purposes of the
meeting.
3. A quorum for meetings of the Committee shall be a majority of its members,
and the rules for calling, holding, conducting and adjourning meetings of
the Committee shall be the same as those governing the Board unless
otherwise determined by the Committee or the Board.
4. Meetings of the Committee should be scheduled to take place at least four
times per year. Minutes of all meetings of the Committee shall be taken.
The Chief Financial Officer shall attend meetings of the Committee, unless
otherwise excused from all or part of any such meeting by the Chairman.
5. The Committee shall meet with the external auditor at least once per year
(in connection with the preparation of the year end financial statements)
and at such other times as the external auditor and the Committee consider
appropriate.
6. Agendas, approved by the Chair, shall be circulated to Committee members
along with background information on a timely basis prior to the Committee
meetings.
7. The Committee may invite such officers, directors and employees of the
Corporation as it may see fit from time to time to attend at meetings of
the Committee and assist thereat in the discussion and consideration of
the matters being considered by the Committee.
8. Minutes of the Committee will be recorded and maintained and circulated to
directors who are not members of the Committee or otherwise made available
at a subsequent meeting of the Board.
9. The Committee may retain persons having special expertise and/or obtain
independent professional advice to assist in fulfilling its
responsibilities at the expense of the Corporation.
10. Any members of the Committee may be removed or replaced at any time by the
Board and shall cease to be a member of the Committee as soon as such
member ceases to be a director. The Board may fill vacancies on the
Committee by appointment from among its members. If and whenever a vacancy
shall exist on the Committee, the remaining members may exercise all its
powers so long as a quorum remains. Subject to the foregoing, each member
of the Committee shall hold such office until the close of the next annual
meeting of unitholders following appointment as a member of the Committee.
11. Any issues arising from these meetings that bear on the relationship
between the Board and management should be communicated to the Chairman of
the Board by the Committee Chair.