EXHIBIT 2.1
SHARE PURCHASE AGREEMENT
THIS AGREEMENT made the 30th day of May, 2002.
AMONG:
XXXX XXXXXXX, of Calgary Alberta;
OF THE FIRST PART
- and -
XXXXX X. XXXXX, of Calgary Alberta;
OF THE SECOND PART
- and -
XXXX XXXXXXXX, of Lloydminster, Alberta;
OF THE THIRD PART
individually called "Vendor" and collectively called
"Vendors")
AND
ASSURE OIL & GAS CORP., a body corporate, incorporated under
the laws of the Province of Ontario (hereinafter called
"Purchaser")
OF THE FOURTH PART
WHEREAS WESTERRA 2000 INC. (the "Corporation") is the beneficial owner of the
Assets; and
WHEREAS the Vendors own all of the issued and outstanding shares of the
Corporation; and
WHEREAS the Vendors wish to sell all the shares of the Corporation to the
Purchaser and the Purchaser wishes to purchase the shares of the Corporation
from Vendors;
NOW THEREFORE THIS AGREEMENT WITNESSETH that in consideration of the premises
hereto, the receipt and sufficiency of which is hereby acknowledged by the
Parties, and the mutual covenants, warranties, representations, agreements and
payments herein set forth, the Parties mutually covenant and agree as follows:
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ARTICLE 1
INTERPRETATION
1.1 DEFINITIONS
In this Agreement, including the recitals hereto, this Section and the
Schedules, unless otherwise defined or the context so requires:
(a) "AFE" means an authority for expenditure pursuant to which the
Corporation or another Person on its behalf has authorized the
undertaking of operations or a project for which the
Corporation shall be obligated to pay a portion thereof
determined in accordance therewith an applicable agreement;
(b) "Accounting Principles" means generally accepted accounting
principles, consistently applied, as established from time to
time by the Canadian Institute of Chartered Accountants;
(c) "Agreement" means the main body of this Agreement together
with all Schedules and attachments hereto;
(d) "Assets" means, collectively, the Natural Gas Rights, the
Tangibles, the Facilities and the Miscellaneous Interests;
(e) "AltaGas Loan Agreement" means the Loan Agreement between the
Corporation and AltaGas Services Inc. dated June 1, 2001;
(f) "AltaGas Loan" means the Bridge Loan and the Working Capital
Loan Amount as such terms are defined in the AltaGas Loan
Agreement, for which the payout amounts are detailed in
Schedule "L";
(g) "Business Day" means a day other than Saturday or Sunday or a
statutory holiday in the Province of Alberta;
(h) "Close" means to close the Transaction on the basis
contemplated hereby;
(i) "Closing" means the closing of the Transaction on the Closing
Date;
(j) "Closing Date" means the date upon which Closing is to occur,
which shall be May 30, 2002 or such other date as the Parties
agree to in writing;
(k) "Corporation" means Westerra 2000 Inc., a body corporate,
incorporated under the laws of the Province of Alberta;
(l) "Directors" means the directors of the Corporation from time
to time;
(m) "Dollar" or "$" means dollars of the lawful currency of
Canada;
(n) "Effective Date" means April 1, 2002;
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(o) "Employees" means employees or contract personnel employed or
retained by the Corporation from time to time on or before the
Closing Date, including Officers;
(p) "Environment" means the components of the earth and includes:
(i) air, land and water;
(ii) all layers of the atmosphere;
(iii) all organic and inorganic matter and living
organisms; and
(iv) the interacting natural systems that include
components referred to in sub-paragraphs (i) to (iii)
above;
(q) "Environmental Damage" means any loss, injury, damage or other
event of any kind whatsoever, and howsoever or whenever
occurring, to the Environment (including but not limited to
any loss or damage to real or personal property) in respect of
which any liability or obligation has or may in future accrue
to the Corporation, to incur any abandonment, remediation,
reclamation, clean-up expenses or fines, penalties and other
expenses or to compensate any Person, whether by reason of any
equitable, common law, statutory or civil liability or
obligation, or remedy available, applicable by reason of the
ownership of the Assets or responsibility for any operations
conducted on or in respect thereof at any time in the past,
present or future, and whether or not resulting from
negligence, nuisance or otherwise, which loss, injury or
damages shall include but not be limited to all damages,
awards, expenses and costs (including legal costs on a
solicitor and his own client basis) incurred in any way
relating to such matters;
(r) "Facilities" means all of the facilities used or useful in the
production, gathering, storage, processing, transmission or
treatment of Petroleum Substances, including, without limiting
the generality of the foregoing, all pipelines, flow lines,
gathering systems, batteries and plants and including those
facilities set forth on Schedule "B";
(s) "Financial Statements" means the audited financial documents
of the Corporation appended hereto as Schedule "K";
(t) "I.T.A." means the Income Tax Act, (Canada) and the
regulations thereunder, as amended from time to time including
any amendments proposed thereto in any public pronouncement by
the Department of Finance of the Government of Canada;
(u) "Implementation Documents" includes all transfers, agreements,
instruments, consents, resignations, waivers, releases and
other documents as may be necessary or appropriate in
connection with and for purposes of completion of the
Transaction;
(v) "Lands" means the lands set forth and described in Schedule
"B", and includes the Petroleum Substances within, upon or
under such lands, together with the right to explore for and
recover the same insofar as such rights are granted by the
Leases;
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(w) "Leases" means, collectively, the leases, reservations,
permits, licences, contracts or other documents of title under
and by virtue of which the holder thereof is entitled to drill
for, win, take, own, store and remove the Petroleum Substances
underlying all or any part of the Lands or lands pooled or
unitized therewith and which are described in Schedule "B"
hereto;
(x) "Letter of Intent" means the letter of intent among the
parties hereto agreed to on March 29, 2002;
(y) "Natural Gas Rights" means the entire right, title, estate and
interest of the Corporation in and to the Leases and the Lands
set forth and described in Schedule "B", as encumbered by the
Permitted Encumbrances;
(z) "XxXxxx Lands" means an estate in fee simple of and in all
mines and minerals within, upon or under the North East
Quarter of Xxxxxxx 00, Xxxxxxxx 00, Xxxxx 00, Xxxx of the
Third Meridian, Saskatchewan except 4.58 acres for right of
way for the Canadian Pacific Railway on Plan AF 3323;
(aa) "Miscellaneous Interests" means, collectively, the entire
right, title, estate and interest of the Corporation in and to
all property, assets and rights (other than the Natural Gas
Rights and the Tangibles) pertaining to the Natural Gas Rights
or the Tangibles and to which the Corporation is entitled as
at the Closing Date, including, but without limiting the
generality of the foregoing, the entire interest of the
Corporation in and to:
(i) all contracts, agreements, documents, production
sales contracts, books and records and all seismic,
geological, geophysical, production and engineering
data, information and reports relating to the Natural
Gas Rights or the Tangibles, and any and all rights
in relation thereto;
(ii) all subsisting rights to enter upon, use and occupy
the surface of any of the Lands or any lands with
which the same have been pooled or unitized or any
lands used or intended for use to gain access to any
of the foregoing;
(iii) any right, estate or interest in or to any asset
which relates to but does not comprise part of the
Natural Gas Rights or the Tangibles;
(iv) all shut-in, suspended, producing, water-injection or
other xxxxx utilized, or that have been utilized, for
purposes relating to the production of Petroleum
Substances from the Lands or lands with which the
same have been pooled or unitized (including all
casing in such xxxxx) but specifically excluding
xxxxx properly abandoned in accordance with the
Regulations; and
(v) all royalty interests;
(bb) "Officer" means an individual holding a title commonly
referred to and recognized at law, as an officer of the
Corporation;
(cc) "Party" or "Parties" means a party or parties to and bound by
this Agreement;
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(dd) "Permitted Encumbrances" means, in respect of the Assets:
(i) all royalties, burdens, encumbrances or other charges
of any kind which are set forth in Schedule "B" in
relation to the Assets;
(ii) pre-emptive rights in favour of third Persons, and
requirements to obtain third Person's consents or
approvals, applicable to dispositions of the Assets
or any of them in the ordinary and usual course which
have been disclosed to the Purchaser, other than
those which may arise by reason of this Agreement;
(iii) the terms and conditions of the Leases and other
existing title documents and the Regulations
applicable thereto, including, without limitation,
the requirement to pay any bonuses, rentals or
royalties to the grantor thereof (or any successor
thereto) to maintain the same in good standing;
(iv) any rights reserved to or vested in any grantor,
government or other public authority by the terms of
any of the Leases or by the Regulations applicable
thereto to terminate or otherwise deal with any of
the same;
(v) easements, rights of way, servitudes or other similar
rights or interests in land, including but not
limited to, all rights of way and servitudes for
highways, railways, sewers, drains, gas and oil
pipelines, gas and water mains, electric light,
power, telephone or cable television conduits, poles,
wires or cables;
(vi) taxes on Petroleum Substances to the extent not due
and payable or delinquent, and all Regulations
pertaining to production rates from the Xxxxx and
operations being conducted thereon or with respect
thereto;
(vii) the provisions of the Production Sales Contracts;
(viii) the Regulations and any rights reserved to or vested
in any municipality or governmental, statutory or
public agency or authority to control or regulate any
of the Assets in any manner or that otherwise pertain
thereto;
(ix) undetermined or inchoate liens incurred or created as
security in favour of any Person with respect to the
exploration, development or operation of any of the
Assets, to the extent of the Corporation's share of
the costs and expenses associated therewith, and to
the extent not due and payable or delinquent;
(x) the reservations, limitations, provisos and
conditions in any grants or transfers from the crown
applicable to any of the Lands or any lands pooled or
unitized therewith, or any statutory exceptions to
title thereto and such reservations, limitations,
provisions and conditions are vested in the crown in
right of Canada or a province or a successor in
interest to the crown;
(xi) provisions for independent operations penalties that
now exist or that could hereafter apply in relation
to the Assets or any of them;
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(xii) liens granted in the ordinary course of business to
any public utility, municipality or other
governmental agency or authority with respect to the
Assets or operations pertaining thereto;
(xiii) mechanics', builders', materialmens' or similar liens
applicable in respect of services rendered or goods
supplied not delinquent;
(xiv) agreements, arrangements, plans or schemes relating
to pooling, unitization or other joint production of
Petroleum Substances, pertaining to or including any
of the Lands or any lands with which the same have
been pooled or unitized;
(xv) all agreements respecting the production, processing,
treating or transmission of Petroleum Substances, or
the operation of Xxxxx by contract field operators,
applicable to the Lands or any lands with which the
same have been pooled or unitized; and
(xvi) the operating related provisions of all operating and
other agreements pertaining to the title or interest
of the Corporation in the Assets, operations
applicable thereto or otherwise pertaining to such
Assets;
(ee) "Person" means an individual, corporation, partnership or
other legal entity and includes any government or any
governmental department, agency or authority thereof;
(ff) "Petroleum Substances" means natural gas and all other
substances (other than petroleum), whether hydrocarbon or not,
the rights to which are granted by the Leases;
(gg) "Pre-Emptive Right" means a right of first refusal or other
pre-emptive right applicable to the Shares, or any of them,
whereby a third Person has, as a result of the entering into
of this Agreement by the Parties, a right to purchase the
Shares, or any of them, at a value determined on the basis
provided for in the applicable agreement giving rise to such
right of first refusal or other pre-emptive right;
(hh) "Production Sales Contracts" means all contracts relevant to
the production and sale of Petroleum Substances from the Lands
or lands pooled or unitized therewith, including but not
limited to those set forth in Schedule "G";
(ii) "Purchase Price" has the meaning ascribed to that phrase in
Section 2.2;
(jj) "Purchaser" means Assure Oil & Gas Corp.;
(kk) "Purchaser's Certificate" means a certificate of the Purchaser
to be in the form attached as Schedule "D";
(ll) "Purchaser's Counsel" means Burstall Winger LLP;
(mm) "Regulations" means all laws, statutes, regulations,
ordinances, orders (including court orders), directives,
approvals, licenses, permits, authorities or other such
instruments issued by any government or any governmental
department, agency or authority thereof, or registered stock
exchange, having jurisdiction, applicable to any of the
Parties, the
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Shares, the Assets or any of them, or the operations conducted
or to be conducted on or in respect thereof, or any other
matters relating to such Parties, Shares, Assets or
operations;
(nn) "Shares" means all of the issued and outstanding shares in the
capital of the Corporation, being an aggregate of 125 Class A
common shares, 60 Class B common shares and 15 Class C common
shares, which shares are owned of record and beneficially by
the Vendors as set forth in Schedule "A";
(oo) "Take or Pay Obligations" means any obligations in the nature
of take or pay obligations which the Corporation has under or
in respect of any of the Production Sales Contracts which have
arisen by reason of payments to or to the account or benefit
of the Corporation or to other Persons as agent on its behalf,
which now or at any time in the future require or may require
the Corporation to deliver Petroleum Substances to those
purchasers under such Production Sales Contracts without being
entitled to payment in full therefor or, in some
circumstances, to repay all or any portion of such payments;
(pp) "Tangibles" means the entire right, title, estate and interest
of the Corporation in and to all tangible depreciable
property, assets and facilities (including but not limited to
the Facilities) situate in, on or about the Lands or lands
pooled or unitized therewith, appurtenant thereto or used or
intended for use in connection therewith or with production
gathering, processing, storage, transmission or treatment of
the Petroleum Substances produced therefrom or other
operations thereon or relative thereto and includes the
surplus equipment described in Schedule "C";
(qq) "Taxes" means all Canadian and federal, provincial, state,
municipal and other taxes payable under or pursuant to a Tax
Act, including but not limited to income taxes, sales taxes,
excise taxes, petroleum and gas revenue taxes, value added
taxes, goods and services taxes, capital taxes, withholding
taxes, property taxes and production severance and other
similar taxes and assessments based upon or measured by
ownership or production of Petroleum Substances (or the
receipt of proceeds therefrom) and includes applicable
penalties, interest and fines with respect thereto;
(rr) "Tax Act" means the I.T.A. or any other applicable tax
legislation of governments, or their respective agencies or
authorities, having jurisdiction over the Parties or either of
them, or the subject matter of this Agreement, in any case as
the same may be amended from time to time;
(ss) "Tilikum Report" means the independent engineering report of
Tilikum Inc. dated effective December 31, 2001 in respect of
the natural gas reserves of the Corporation, a copy of which
is attached as Schedule "O";
(tt) "Time of Closing" means the time at which Closing occurs;
(uu) "Transaction" means the transaction or transaction provided
for in and contemplated by this Agreement;
(vv) "Vendors" means collectively the Vendors set forth in Schedule
"A" hereto and "Vendor" means any one of them;
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(ww) "Vendors' Certificate" means a certificate from each Vendor,
to be substantially in the form attached as Schedule "E", but
modified to the extent reasonably necessary to reflect the
different obligations of each Vendor hereunder;
(xx) "Vendors' Counsel" means Gowling Xxxxxxx Xxxxxxxxx LLP; and
(yy) "Xxxxx" means all abandoned, shut-in, suspended, capped,
producing, water injection, water source or other xxxxx
located on the Lands or lands pooled or unitized therewith,
including but not limited to any xxxxx that have been
abandoned where the lands upon which the same are located have
been remediated and reclaimed, or are in the process of being
remediated and reclaimed, in accordance with the Regulations
and the applicable surface lease has been properly surrendered
to the landowner in compliance with the requirements of the
Surface Rights Act (Alberta) or other applicable Regulations,
and includes the Xxxxx described in Part II of Schedule "B".
1.2 SCHEDULES
The following Schedules are attached to and by this reference
incorporated herein:
Schedule "A" - Vendors Information
Schedule "B" - Lands, Leases, Xxxxx and Facilities
Schedule "C" - Surplus Equipment;
Schedule "D" - Purchaser's Certificate;
Schedule "E" - Vendors' Certificate;
Schedule "F" - Lawsuits and Claims;
Schedule "G" - Production Sales Contracts;
Schedule "H" - Take or Pay Obligations;
Schedule "I" - Employee Matters;
Schedule "J" - Open AFEs;
Schedule "K" - Financial Statements;
Schedule "L" - AltaGas Loan Payout Amounts as at April 1, 2002 and as at the Closing Date
Schedule "M" - Notice of Default from AltaGas
Schedule "N" - Additional Disclosures
Schedule "O" - Tilikum Report
1.3 HEADINGS
The headings of the sections included herein and in the Schedules are
inserted for convenience of reference only and shall not affect the construction
or interpretation of the provisions of this Agreement.
1.4 INCLUDED WORDS
In this Agreement:
(a) words importing the singular include the plural and vice
versa, words importing one gender include other genders; and
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(b) where words are defined herein, derivatives of those words
shall have a corresponding meaning unless the context
otherwise requires.
1.5 REFERENCES
Except as otherwise expressly stated in this Agreement:
(a) references herein to "this Agreement", "hereto", "herein",
"hereof", "hereby", "hereunder" and similar expressions refer
to this Agreement in its entirety and not to any particular
section, paragraph, sub-paragraph or other portion hereof;
(b) references herein to a Schedule refer to a Schedule to this
Agreement;
(c) references in the main body of this Agreement or a Schedule to
a specific section, subsection, paragraph or sub-paragraph
refer to a section, subsection, paragraph or sub-paragraph of
such main body of this Agreement or the Schedule in which the
reference is made; and
(d) unless otherwise stated, references herein to monies means to
lawful money of Canada,
unless the particular context in which any such reference is used
otherwise requires.
1.6 CONFLICTS
Whenever any term or condition, whether express or implied, of any
Schedule attached hereto conflicts with or is at variance with any term or
condition of the main body of this Agreement, the latter shall prevail to the
extent of the conflict or variance.
1.7 INVALIDITY OF PROVISIONS
If any of the provisions of this Agreement are determined to be
invalid, illegal or unenforceable in any respect, the validity, legality or
enforceability of the remaining provisions hereof shall not in any way be
affected, impaired or limited thereby.
ARTICLE 2
PURCHASE AND SALE
2.1 PURCHASE AND SALE
Subject to and in accordance with the terms and conditions of this
Agreement, in consideration of the Purchase Price, the Vendors hereby agree to
sell, transfer and deliver the Shares to the Purchaser and the Purchaser hereby
agrees to purchase, receive and accept directly from Vendors the Shares on the
Closing Date effective on the Effective Date and the Purchaser shall have and
hold the same together with all benefits and advantages to be derived therefrom,
absolutely.
2.2 PURCHASE PRICE
The Purchase Price shall be $3,450,000, subject to adjustment pursuant
to paragraph 2.4 below.
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2.3 PAYMENT OF THE PURCHASE PRICE
The Purchase Price shall be payable as follows:
(a) $2,677,703.55 payable on the Closing Date by repayment on
behalf of the Corporation of the AltaGas Loan;
(b) $772,296.45 in cash ("Cash Payment") payable to the Vendors
pro rata in proportion to the number of Shares owned by each
Vendor as set forth in Schedule "A", and payable on the
following dates:
(i) $422,296.45 payable on the Closing Date; and
(ii) $350,000 payable upon Four West Land Consultants Ltd.
obtaining registered title to the XxXxxx Lands.
2.4 ADJUSTMENTS
The Cash Payment shall be adjusted as follows:
(a) in the event that the aggregate of the amounts payable by the
Corporation as at the Effective Date pursuant to the AltaGas
Loan exceeds $2,677,703.55 the Cash Payment shall be reduced
by the corresponding amount;
(b) net revenues and prepaid expenses of the Corporation
attributable to periods ending prior to the Effective Date but
received by the Corporation after the Effective Date shall be
credited to the Vendors; and
(c) net revenues and prepaid expenses of the Corporation
attributable to periods ending after the Effective Date but
received by the Corporation before the Closing Date shall be
credited to the Purchaser.
2.5 INCOME TAX RETURNS
All income tax returns required by a Tax Act applicable in respect of
the Corporation and applying to that period of time ending on or prior to the
Closing Date shall be prepared and filed in a timely fashion by the Corporation,
subject to review and approval by the Purchaser, acting reasonably.
2.6 ACCOUNTS RECEIVABLE
Vendors covenant to pay or cause to be paid at or prior to the Closing
Date, all amounts due to the Corporation, from the Vendors, the officers,
directors or all prior officers and directors or from related corporations.
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ARTICLE 3
CLOSING
3.1 CLOSING
The Transaction shall be Closed at 10:00 a.m. Calgary time on the
Closing Date at the offices of Purchaser's Counsel, or at such other time and
location as the Parties agree upon in writing.
3.2 VENDORS' CLOSING OBLIGATIONS
Subject to the terms and conditions hereof, at Closing Vendors shall:
(a) execute and deliver this Agreement;
(b) deliver all of the existing share certificates issued in the
name of each Vendor for all of the issued and outstanding
Shares, duly endorsed for transfer, necessary to convey the
Shares from Vendors to the Purchaser;
(c) deliver, or cause to be delivered, the resignations and
releases of all of the current and prior Directors, Officers,
employees and consultants of the Corporation;
(d) cause to be delivered a Vendors' Certificate dated as of the
Closing Date from each of the Vendors to the effect that the
statements made in Article 4 to the extent applicable to them,
are true in all material respects at and as of the Closing
Date;
(e) deliver a certified copy of a resolution of the board of
directors of the Corporation approving the transfer of the
Shares to the Purchaser;
(f) deliver the minute book and corporate seal of the Corporation,
containing, without limitation, all of the minutes of any
meetings, resolutions of directors and shareholders duly
executed, and annual returns;
(g) cause Xxxx Xxxxxxx to enter an employment agreement or
consulting contract with the Corporation in form satisfactory
to the Purchaser and Xxxx Xxxxxxx with a term of up to six
months from Closing;
(h) cause Roswell Petroleum Corporation, 970313 Alberta Ltd. and
Xxxxx Venture I Inc. to enter into a Farmout and Option
Agreement in the form contemplated by the Letter of Intent;
(i) cause to be prepared documentation in respect of the discharge
of the obligations of the Corporation under the AltaGas Loan;
and
(j) cause to be delivered an opinion of Vendors' Counsel in form
and content acceptable to the Purchaser, acting reasonably,
addressing certain matters referred to in Article 4.
3.3 PURCHASER'S CLOSING OBLIGATIONS
Subject to the terms and conditions hereof, or any contrary written
agreement of the parties, at Closing the Purchaser shall:
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(a) execute and deliver this Agreement;
(b) pay the AltaGas Loan;
(c) tender to each Vendor such Vendor's proportionate share of the
Cash Payment;
(d) cause to be delivered a Purchaser's Certificate dated as of
the Closing Date to the effect that the statements made in
Article 5 are true in all material respects at and as of the
date specified therein; and
(e) cause the Corporation to enter into the Farmout and Option
Agreement in the form contemplated by the Letter of Intent
with Roswell Petroleum Corporation, 970313 Alberta Ltd. and
Xxxxx Venture I Inc.
3.4 VENDORS' CLOSING CONDITIONS
The obligation of Vendors to complete the Transaction is subject to and
conditional upon the satisfaction by the Purchaser on the Closing Date the
following conditions precedent:
(a) satisfaction by the Purchaser of the Purchaser's closing
obligations as set forth in Section 3.3; and
(b) all representations and warranties of the Purchaser set forth
in Article 5 shall be true in all material respects and the
Purchaser has performed and satisfied all of its obligations
to be performed and satisfied by it on or before the Closing
Date.
3.5 VENDORS' BENEFIT AND WAIVER
The conditions set forth in Section 3.4 are for the sole benefit of
Vendors and may, without prejudice to any of the rights of Vendors hereunder, be
waived by them in writing, in whole or in part at any time. If any of the
conditions set forth in Section 3.4 are not satisfied, or waived by Vendors on
or prior to the Closing Date, Vendors shall be entitled to rescind and terminate
this Agreement by written notice to the Purchaser whereupon no Party shall,
except as otherwise provided herein, have any further rights or obligations
whatsoever to any other Party hereunder, nor shall the Purchaser have any claim
or right whatsoever to all or any part of the Shares or the Assets.
3.6 PURCHASER'S CLOSING CONDITIONS
The obligation of the Purchaser to complete the Transaction is subject
to the satisfaction, on or before the Closing Date, or the time specified
herein, of the following conditions precedent:
(a) satisfaction by the Vendors of the Vendors' closing
obligations as set forth in Section 3.2;
(b) all representations and warranties of Vendors set forth in
Section 4.1 and 4.2 shall be true in all material respects as
of the dates specified therein and Vendors shall have
performed and satisfied all of their obligations hereunder to
be performed and satisfied by them on or before the Closing
Date;
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(c) the Purchaser shall be satisfied by the Closing Date, acting
reasonably, of the Corporation's right, title and interest in
and to the Assets;
(d) the Purchaser shall be satisfied by the Closing Date, as to
the amounts owing to AltaGas pursuant to the AltaGas Loan and
shall have received discharge or transfer documents
satisfactory to it in respect of such loans;
(e) the Purchaser shall be satisfied by the Closing Date, acting
reasonably, with the Financial Statements of the Corporation;
and
(f) no suit, action or other proceeding shall at Closing be
pending against any of the Vendors or the Corporation, before
any court or governmental agency which may mutually adversely
affect the Purchaser or the Corporation.
3.7 PURCHASER'S BENEFIT AND WAIVER
The conditions set forth in Section 3.6 are for the sole benefit of the
Purchaser and may, without prejudice to any of the rights of the Purchaser
hereunder, be waived by it in writing, in whole or in part, at any time. If any
of the conditions precedent set forth in Section 3.6 are not satisfied, complied
with or waived by the Purchaser at or prior to the Closing Date, or any other
date specified therein for the satisfaction thereof, either Party shall be
entitled to rescind and terminate this Agreement by written notice to the other
Party whereupon neither Party shall, except as otherwise provided herein, have
any further rights or obligations whatsoever to the other Party hereunder, nor
shall the Purchaser have any claim or right whatsoever to all of any part of the
Shares.
3.8 SATISFACTION OF CONDITIONS
Each of the Parties covenants and agrees with each of the other Parties
that they shall use their best efforts to assure that all of the covenants made
by them, and all conditions to their obligations to close the Transaction
contained herein, are satisfied on or before the time required therefore to
enable Closing to occur on the Closing Date on the basis set forth herein.
ARTICLE 4
VENDORS' REPRESENTATIONS
4.1 VENDORS' REPRESENTATIONS AND WARRANTIES
Each Vendor hereby represents, warrants and covenants to and with the
Purchaser as of the Closing Date, or such other date as is specifically referred
to in this Section 4.1, acknowledging that the Purchaser is relying upon the
same in entering into this Agreement, that:
(a) Residency - such Vendor is resident at the address set forth
in Schedule "A" and is not a non-resident for purposes of the
I.T.A.;
(b) Authority - such Vendor has all requisite capacity, power and
authority to enter into this Agreement and to perform all of
such Vendor's obligations under this Agreement;
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(c) Title to Shares - immediately prior to Closing such Vendor
shall have good and marketable title to such Vendor's Shares
free and clear of any mortgages, liens, charges, security
interests, adverse claims, pledges, encumbrances, options,
Pre-emptive Rights, restrictions, claims or demands, of any
kind or nature whatsoever; and
(d) Binding Obligation - this Agreement has been, and the
Implementation Documents executed by such Vendor will be, upon
Closing, duly executed and delivered by such Vendor, and shall
constitute legal, valid and binding obligations of such Vendor
enforceable against such Vendor in accordance with their
respective terms.
4.2 VENDORS' REPRESENTATIONS AND WARRANTIES REGARDING THE CORPORATION
Each Vendor hereby represents, warrants and covenants to and with the
Purchaser as of the Closing Date, or such other date as is specifically referred
to in this Section 4.2, acknowledging that the Purchaser is relying upon the
same and entering into this Agreement, that:
(a) Organization - The Corporation is duly organized, incorporated
and validly existing under the laws of the Province of Alberta
and is duly registered under the laws of those jurisdictions
in which it is required to be registered by reason of the
nature of its operations or the location of the Assets;
(b) Capital Structure of the Corporation:
(i) The authorized capital of the Corporation consists of
an unlimited number of Class A common shares, an
unlimited number of Class B common shares, an
unlimited number of Class C common shares, an
unlimited number of Class D common shares, an
unlimited number of Class E common shares, an
unlimited number of Class F Preferred Shares and an
unlimited number of Class G Preferred Shares of which
125 Class A common shares, 60 Class B common shares
and 15 Class C common shares and no other shares are
issued and are outstanding;
(ii) There are no restrictions in either the constating
documents or the by-laws of the Corporation, each as
amended, nor are there any collateral agreements,
including without limitation any unanimous
shareholders agreement, or voting trust agreement or
Pre-Emptive Rights which would arise by reason of the
execution of this Agreement or the Implementation
Documents, completion of the Transaction or
otherwise, which would affect the transferability of
the Shares of the Corporation from Vendors to the
Purchaser other than the consent of the directors of
the Corporation;
(iii) No Person, other than the Purchaser pursuant hereto
has any agreement, or any right or privilege that may
become an agreement, including but not limited to
convertible securities, option agreements, warrants
or convertible obligations of any kind or nature, for
the purchase, subscription, allotment or issuance of
any shares in the capital of the Corporation or any
securities of the Corporation;
(iv) At the time of Closing, the minute book and share
ledger of the Corporation will be true and correct in
all material respects and the minute book shall
contain
17
copies of all meetings of the Directors and
shareholders of the Corporation and all resolutions
by consent (if any) of the said directors and
shareholders; and
(v) The Corporation is not now nor will it be, at any
time prior to Closing, a party to any contract or
agreement to merge or consolidate with any other
corporation, to acquire any assets or shares of any
other person, or to sell all or any part of its
interest in the Assets;
(c) Execution of Agreements - the execution and delivery of this
Agreement and each and every agreement, instrument or document
to be executed and delivered hereunder or pursuant hereto and
the consummation of the Transaction do not and will not:
(i) result in the breach of or violate any term or
provision of the Corporation's articles, by-laws or
other constating documents;
(ii) to such Vendor's knowledge, information or belief,
conflict with, result in a breach of, or constitute a
default under any agreement, instrument, license,
permit or authority to which the Corporation is a
party or by which the Corporation is bound, or to
which any property of the Corporation is subject, or
result in the creation of any lien, charge, or
encumbrance upon the Assets or the Shares under any
such agreement, instrument, license, permit or
authority; or
(iii) to such Vendor's knowledge, information or belief,
violate any Regulations applicable to the Vendors,
the Corporation or the Shares;
(d) Brokers' Fees - neither the Corporation nor any of the Vendors
have incurred any obligation or liability, contingent or
otherwise, for brokers' or finders' fees in respect of the
Transaction for which the Corporation or the Purchaser shall
have any obligation or liability;
(e) Title to Assets - The Vendors do not warrant the Corporation's
title to the Assets, but each Vendor does represent and
warrant to the Purchaser that:
(i) except as has been disclosed in writing to the
Purchaser, neither it, nor the Corporation, have done
any act or thing, nor is it aware of any act or thing
having been done, whereby any of the Corporation's
interest in and to the Assets may be canceled or
terminated;
(ii) the Corporation has not encumbered, granted a
security interest in or transferred, leased,
licensed, farmed out or otherwise disposed of any of
its interests in and to the Assets or any interest
therein; and
(iii) the Assets are free and clear of all liens,
encumbrances, adverse claims, demands and royalties
created by, through or under the Corporation, except
for the Permitted Encumbrances;
(f) Quiet Enjoyment - subject to the rents, covenants, conditions
and stipulations in the Leases and any agreements pertaining
to the Assets and on the lessee's or holder's part thereunder
to be paid, performed and observed, the Corporation shall, as
at Closing, continue to hold and enjoy its interest in the
Assets for the residue of their respective
18
terms and all renewals or extensions thereof, where
applicable, for its own use and benefit without any lawful
interruption of or by any of the Vendors or any other Person
whomsoever claiming by, through or under any of the Vendors or
the Corporation;
(g) Lawsuits - the Corporation is not a party to any action, suit
or other legal, administrative or arbitration proceeding or
government investigation, whether actual or threatened, which
the Purchaser is not aware of, and which might reasonably be
expected to result in a liability or obligation of the
Corporation, or the Corporation's interest in the Assets, or
any part thereof, except as set forth in Schedule "F", and
there is no particular circumstance, matter or thing which
could reasonably be anticipated to give rise to any such
action, suit or other legal, administrative or arbitration
proceeding or government investigation;
(h) AFEs - the Corporation has not received nor is the Corporation
subject to any outstanding AFEs approved by it pursuant to
agreements applicable to the Assets, except as disclosed in
Schedule "J";
(i) Production Sales Contracts - the Corporation does not have any
Production Sales Contracts except for those described in
Schedule "G";
(j) Notices of Default - except for a notice of default received
from AltaGas Services Inc., a copy of which is attached as
Schedule "M", the Corporation has not received any notices of
default, including any relating to the Assets or any of them
and all relevant deposits, rentals and royalties have been
paid within applicable time limits and all obligations and
covenants required to keep the Leases in full force and effect
have been performed and observed;
(k) Xxxxx - the Xxxxx that have been drilled and, if completed,
completed and subsequently operated or abandoned have been
done so in accordance with good oilfield and gas industry
practice, in compliance with the Regulations and in accordance
with the terms and conditions of all agreements applicable
thereto;
(l) Payment of Liabilities - other than Taxes payable in respect
of the sale of Petroleum Substances from the Assets, all
liabilities and Taxes have been properly and fully paid and
discharged with respect to the Corporation;
(m) Reduction of Interests - the working interests set forth in
Schedule "B" in respect of the Leases, lands, xxxxx or
production are not subject to reduction on any account
whatsoever as a result of actions or omissions taken or
omitted by the Corporation or on its behalf, and none of the
encumbrances described in Schedule "B" are convertible or
subject to change to an interest of any other size or nature,
except as specifically set forth in Schedule "B";
(n) Defaults - the Corporation has not received any notices of any
breach by it of any Regulations or contracts or agreements
including without limitation in relation to the Assets or the
operation thereof;
(o) Directors/Employees - the Corporation is not a party to:
19
(i) any employment, collective bargaining or similar
written agreement; or
(ii) any pension, retirement, profit sharing, deferred
compensation, stock or cash bonus, stock option or
purchase, incentive, health, life insurance,
disability, severance or other similar plan, policy
or arrangement applicable to persons employed in, or
in connection with the Corporation;
nor shall it have any Employees, Directors, Officers or
consultants at Closing, for which the Corporation will have
any continuing liability or responsibility after Closing other
than the employment or consulting agreement to be entered into
with Xxxx Xxxxxxx;
(p) Gas Balancing Agreements - the Corporation has not entered
into, and the Vendor is not aware of any agreements or
arrangements (commonly known as a gas balancing, swaps,
over-production or underlift-overlift agreements or
arrangements) by other Persons on the Corporation's behalf
which are among two or more Persons owning interests in a
portion of the Lands or lands pooled or unitized therewith,
nor has there been any circumstance or case whereby one of
such Persons has taken, or may hereafter take, a share of the
production of Petroleum Substances from such lands greater
than it would otherwise be entitled to by virtue of its
interest in such lands and which excess taking entitles the
other Persons to a credit in respect of subsequent production
of that the Corporation's Petroleum Substances produced from
such lands by which the Corporation is bound;
(q) Documents - all corporate and title documents in the
Corporation's possession have been or will be made available
promptly prior to Closing to the Purchaser or the Purchaser's
Counsel;
(r) Take or Pay Obligations - the Corporation or the Assets are
not affected by any Take or Pay Obligations except as set
forth in Schedule "H";
(s) Business - The Corporation has all requisite corporate power
and authority to own the Assets and to carry on its business
as it will be conducted at the Closing Date;
(t) Books - the books of account and other records of the
Corporation have been maintained and will be maintained until
Closing in accordance with prudent business practices;
(u) Financial Disclosure - other than as set forth in this
Agreement, the Schedules or the Financial Statements as of
March 31, 2002 and those existing commitments related to the
Assets (such as but not limited to rentals, royalty payments,
operating costs, processing fees, gathering fees and
transportation fees), the Corporation has no other liabilities
or obligations of any kind or manner, whether direct, accrued
or otherwise, other than the AltaGas Loan;
(v) Financial Condition - the Financial Statements fairly present
the financial condition of the business of the Corporation as
of and for the year ended March 31, 2002 in accordance with
Accounting Principles and the results of the operations of the
business of the Corporation for the period then ending, based
on reasonable estimates;
(w) Tax Returns -
20
(i) the Corporation has duly filed all Tax returns
required to be filed by it (up to and including the
fiscal period ended March 31, 2001;
(ii) the Corporation has made complete and accurate
disclosure of all material facts and amounts in such
returns and in all materials accompanying such
returns;
(iii) the Corporation has paid all Taxes due and payable;
(iv) the Corporation has paid all tax assessments and
reassessments and any penalties, interest, fines,
governmental charges and other amounts which the
relevant authority is entitled to collect from the
Corporation;
(v) there are no actions, audits, assessments,
reassessments, suits, proceedings, investigations or
claims now pending against the Corporation in respect
of Taxes paid or payable affecting the business
carried on by the Corporation;
(vi) there are no matters under discussion with, or the
subject of any agreement with any governmental
authority relating to claims for additional Taxes
which affect the Corporation;
(vii) there are no agreements, waivers or other
arrangements providing for an extension of time with
respect to the assessment or reassessment of any Tax
or the filing of any Tax returns by, or the payment
of any Tax by, or levy of any governmental charge
against the Corporation; and
(viii) the Corporation has withheld from each payment made
by it the amount of all Taxes and other deductions
required to be withheld therefrom and have paid all
such amounts due and payable before the date hereof
to the proper taxing or other authority within the
time prescribed under the relevant Tax Act;
(x) Bank and Investment Accounts - Corporation has no bank
accounts, investment accounts, or safety deposit boxes other
than those located at National Bank of Canada, 000 - 0 Xxx.
X.X. Xxxxxxx, Xxxxxxx X0X 0X0;
(y) Allowables - none of the Xxxxx have been produced in excess of
applicable production allowables imposed by the Regulations
and such Xxxxx are not subject to any production penalty,
except as has been disclosed in writing to the Purchaser;
(z) Withholdings - all Taxes and other assessments and levies
which the Corporation is required by law to withhold or
collect have been duly withheld and collected and paid over to
the proper authorities or held by the Corporation for such
payments;
(aa) Equipment Leases - the Corporation has not entered into any
leases, buy-sell, lease-backs or similar arrangements with
respect to any equipment or the Facilities except a lease for
a screw compressor located at 00-00-00-00 W3, a copy of which
has been provided to the Purchaser;
21
(bb) Payment of Taxes and Royalties - all royalties and all ad valorem,
property, production, severance and similar taxes and assessments,
based on or measured by the ownership of the Assets or the production
of Petroleum Substances from the Lands or the receipt of proceeds
therefrom, payable by the Corporation up to March 31, 2002 have been
paid and discharged;
(cc) No Offset Obligations - the Corporation has not received notice that
any of the Lands are subject to any offset obligations;
(dd) No Dividends - since incorporation, the Corporation has not (i)
declared and paid or set aside for payment any dividend, whether in
cash, shares or otherwise; or (ii) reduced the Corporation's stated
capital in any manner or purchased, acquired, canceled or redeemed, or
agreed to purchase, acquire, cancel or redeem, any outstanding shares
in the Corporation's issued capital;
(ee) Area of Mutual Interest - except as has been disclosed in writing to
the Purchaser pursuant to Schedule "N", none of the Lands are subject
to an area of mutual interest obligation, where the failure to comply
would materially adversely affect the value of such property;
(ff) Subsidiaries. The Corporation has no "subsidiaries", as such term is
defined in the Business Corporations Act (Alberta);
(gg) Flow-Through Shares. The Corporation has no obligations to incur and
renounce exploration and development expenses pursuant to any
flow-through share subscription agreements;
(hh) Environmental Claims - the Corporation is not aware of, nor has it
received any order or directive which relates to environmental matters
and which requires any material work, repairs, construction, or capital
expenditures; or any demand or notice with respect to the material
breach of any environmental, health or safety law applicable to the
Corporation or any of its business undertakings, including, without
limitation, any regulations respecting the use, storage, treatment,
transportation, or disposition of environmental contaminants;
(ii) Material Contracts - There are no agreements material to the conduct of
the Corporation's business except as disclosed above. The Purchaser has
been provided with true and complete copies of such material agreements
or access thereto. Such agreements do not contain any "change of
control" provisions which would be triggered or affected by the
Transaction;
(jj) Private Company - the Corporation:
(i) is a "private company", as defined in the Securities Act
(Alberta):
(ii) has no published market for its securities; and
22
(iii) has never filed a prospectus in the Province of Alberta and
has no filing or reporting obligations pursuant to the
securities legislation of any the Province of Alberta or any
other applicable jurisdiction.
4.3 PURCHASE ON AN AS IS WHERE IS BASIS
The Purchaser hereby acknowledges its understanding and agreement that,
except as expressly stated in Sections 4.1 and 4.2, Vendors make no
representations or warranties whatsoever as to the quality, quantity or
recoverability of the Petroleum Substances from the Lands or lands pooled or
unitized therewith, the value of the Assets or any future revenues that may be
expected to be received therefrom, the quality, condition, merchantability,
serviceability, suitability for any purpose of all or any of the Tangibles, any
Environmental Damage, reclamation or abandonment obligations that exist or may
in future exist in respect of the Xxxxx, the Lands or any wellsites or locations
where other surface related or other operations have been or are now conducted,
or for the presence or absence of any obligations that now exist or that may in
future exist in any way in relation to the Assets pursuant to the Regulations as
amended from time to time.
ARTICLE 5
PURCHASER'S REPRESENTATIONS
5.1 REPRESENTATIONS AND WARRANTIES OF PURCHASER
The Purchaser hereby represents, warrants and covenants to and with
Vendors, as of the Closing Date, or such other date specifically referred to in
this Section 5.1, acknowledging that Vendors are relying upon the same in
entering into this Agreement, that:
(a) Organization of the Purchaser - the Purchaser is a corporation
duly organized and existing under the laws of its jurisdiction
of incorporation, and it, or its duly authorized agent, is or
shall be duly organized and existing under the laws of all
jurisdictions in which it is required to be so registered;
(b) Authority - the Purchaser has all requisite capacity, power
and authority to enter into this Agreement, to purchase and
pay for and accept title to the Shares on the terms described
herein, to perform all of its obligations under this
Agreement;
(c) Execution of Agreements - the execution and delivery of this
Agreement and each and every agreement, instrument or document
to be executed and delivered hereunder or pursuant hereto and
the consummation of the Transaction do not and will not:
(i) result in the breach of or violate any term or
provision of the Purchaser's articles, by-laws or
other constating documents;
(ii) to the Purchaser's knowledge, information or belief,
conflict with, result in a breach of, or constitute a
default under any agreement, instrument, license,
permit or authority to which the Purchaser is a party
or by which it is bound, or to which any property of
the Purchaser is subject; or
(iii) to the Purchaser's knowledge, information or belief,
violate any Regulations applicable to it;
23
(d) Binding Obligation - this Agreement has been, and the
Implementation Documents executed by the Purchaser will be,
upon Closing, and other Agreements executed pursuant hereto
after Closing will be, duly executed and delivered by the
Purchaser and shall constitute legal, valid and binding
obligations of the Purchaser enforceable against it in
accordance with their terms;
(e) Regulatory Approvals - the Purchaser has complied with, or
when permitted shall hereafter comply with, and obtain all
approvals required by, all Regulations applicable to its
purchase of the Shares and the completion of the Transaction
on the basis provided for hereunder, including but not limited
to any applicable Canadian securities laws;
(f) Financial Resources - the Purchaser has the financial
resources in place to enable it to pay the Purchase Price and
Close the Transaction on the Closing Date in accordance with
and on the basis contemplated by the Agreement; and
(g) Brokers' Fees - the Purchaser has not incurred any obligation
or liability, contingent or otherwise, for brokers' or
finders' fees in respect of the Transaction for which Vendors
shall have any obligation or liability.
ARTICLE 6
NO MERGER AND SURVIVAL
6.1 NON-MERGER
The covenants, representations and warranties set forth in Articles 4 and 5
shall be deemed to apply to all assignments, conveyances, transfers and
documents conveying, any of the Shares from any Vendors to the Purchaser and
there shall not be any merger of any covenant, representation or warranty in
such assignments, transfers or documents notwithstanding any rule of law, equity
or statute to the contrary and all such rules are hereby waived to the full
extent permitted by law.
6.2 SURVIVAL
The covenants, representations and warranties set forth in Articles 4
and 5 shall survive Closing for the benefit of the Parties for 15 months
following Closing, except in the case of representations and warranties in
respect of Taxes and the Tax Act which shall survive until the expiry of any
applicable limitation periods in respect of such Taxes.
ARTICLE 7
INDEMNITY, DISCLAIMER AND SUBROGATION
7.1 VENDORS' INDEMNITIES
Each Vendor shall indemnify and hold the Purchaser harmless from and
against any losses, costs or expenses (including legal costs on a solicitor and
to his own client basis) directly resulting from any breach by the Vendors of
any covenant or agreement given hereunder or from any representation or warranty
of the Vendors in this Agreement (or any certificate or document delivered
pursuant hereto) being inaccurate or untrue, except that the aggregate amount
payable by the Vendors under such
24
indemnity shall not exceed the aggregate of (a) the Cash Payment received by the
Vendors; and (b) the value of the Reconveyed Interest at Payout as determined by
Tilikum Inc. based upon a 15% discount rate.
7.2 PURCHASER'S INDEMNITY
The Purchaser shall indemnify and hold Vendors and each of them
harmless from and against any liability and any losses, costs, expenses or
damages relating thereto, directly resulting from any breach by the Purchaser of
any covenant or of any representation or warranty of the Purchaser, respectively
contained in this Agreement (or any certificate or document delivered pursuant
hereto) being inaccurate or untrue.
ARTICLE 8
DUE DILIGENCE/INTERIM OPERATIONS
8.1 ACCESS
At any time prior to the Closing Date, Vendors shall, upon prior
reasonable notice, make available, or cause to be made available, at the offices
of the Corporation in Calgary, Alberta during usual business hours, or its duly
authorized representatives, all documents, contracts and agreements relating to
the Corporation and the Assets or any to them which the Purchaser may reasonably
request, which are in the possession of Vendors and which Vendors are legally
permitted to disclose, and Vendors shall co-operate with the Purchaser and its
representatives to cause to be made available any such records that may be in
the possession of other Persons. Vendors shall, unless prevented by the
Regulations or applicable agreement, allow the Purchaser to take a reasonable
number of photostatic copies of such documents. The Purchaser agrees to maintain
strict confidentiality in relation to all corporate documents and information
supplied to it by Vendors in this regard, and to not disclose the same to any
third Persons without Vendors' prior written consent. If the Transaction does
not close for any reason whatsoever, the Purchaser shall forthwith return to
Vendors all copies of all documents, contracts, agreements or information
provided to it, or made available to it by Vendors.
ARTICLE 9
RECONVEYANCE OF WORKING INTEREST
9.1 DEFINITIONS
In this Article,
(a) "Administrative Overhead" means general and administrative
expenses relating to the Assets as set out in the Operating
Statements, but which amount shall not exceed $1,250 per
month;
(b) "GAAP" means generally accepted accounting principles;
(c) "Operating Statements" means the monthly statements prepared
by the Purchaser in accordance with GAAP with respect to the
Assets evidencing the revenues and expenditures with respect
to the Assets;
25
(d) "Payout" means the date on which the net revenue generated by
the Assets for the period following the Effective Date, as set
forth in the Operating Statements, is equal to the Purchase
Price; and
(e) "Reconveyed Interest" has the meaning given in paragraph
9.3(a) below.
9.2 OPERATING STATEMENTS AND PAYOUT ACCOUNT
(a) The Purchaser shall establish and maintain at its registered
office, accounting records for the calculation of the
Operating Statements and Payout in accordance with GAAP.
(b) The Purchaser shall supply the Vendors with a written
statement evidencing in reasonable detail all debits and
credits made in preparing the Operating Statements and
calculating Payout (including supporting calculations for
those debits and credits) determined on or by the last day of
each month.
9.3 ELECTION FOR RECONVEYANCE AT PAYOUT
(a) Within 60 days following Payout, the Purchaser shall give
notice of Payout and the date thereof to the Vendors. Within
30 days of receipt of such notice by the Vendors and for no
additional consideration, each of the Vendors may elect, by
notice to the Purchaser, to require the Purchaser to cause the
Corporation to convey an aggregate 25% working interest in the
Assets to the Vendors, or to each Vendor's nominee, who elect
as set forth below (the "Reconveyed Interest"):
Xxxx Xxxxxxx: an undivided 15.625%
Xxxx Xxxxxxxx: an undivided 7.5%; and
Xxxxx X. Xxxxx: an undivided 1.875%.
(b) If some of the Vendors do not elect as set forth in clause (a)
above, the Vendor(s) who have elected shall be entitled, by
further electing within 10 days of notice by the Purchaser, to
take up a proportionate share of the Reconveyed Interest of
the Vendor(s) who have not elected.
9.4 OPERATING PROCEDURE The operating procedure governing the Assets at the time
of Payout shall apply as between the Vendors who elect to convert and the
Corporation.
9.5 LATE NOTICE OF PAYOUT If Payout occurs and the Purchaser has not issued
notice of Payout to the Vendors or has issued notice to the Vendors at a date
later than required by this Article, the Purchaser will be deemed to have issued
notice of Payout at the date provided in clause 9.3(a). In such event, the
Vendors may require the conveyance of the Reconveyed Interest, and if the
Vendors so elect, the accounts of the Parties will be retroactively adjusted to
the date Payout actually occurred.
ARTICLE 10
AUDIT OF ALTAGAS LOAN
10.1 NOTICE OF AUDIT
At any time subsequent to the Closing, the Purchaser shall, upon
written demand by any of the Vendors, at the sole cost and expense of the
Vendors (which cost shall include a reasonable fee for
26
administrative time spent by the Corporation), cause to be conducted by the
Corporation, an audit of the records and accounts of AltaGas Services Inc. and
Cedar Energy Inc., relating to the AltaGas Loan (including, without limitation,
all matters pertaining to the AltaGas Loan Agreement and the letter of intent
which pre-dated the AltaGas Loan Agreement) and of all joint venture accounts
between the Corporation, AltaGas Services Inc. and Cedar Energy Inc. for
operations conducted on or with respect to the Assets for all periods up to and
including the Effective Date.
10.2 ADJUSTMENT RESULTING FROM AUDIT
Upon receipt of a notice pursuant to this Article, the Purchaser shall
cause the Corporation to commence the conduct of that audit within 60 days by an
accredited third party selected by the Vendors and to conduct any such audit
within a reasonable time period. If the result of any such audit discloses a
credit payable to the Corporation, the Purchaser shall cause the Corporation to
take all reasonable steps to ensure that any such credit is received by the
Corporation. The Corporation shall cause any such net amount received by the
Corporation to be paid to the Vendors as a post-closing adjustment to the Cash
Payment in accordance with Paragraph 2.4 of this Agreement. If the result of any
such audit discloses that the Corporation is subject to a negative variance, the
Vendors shall cause any such amount so disclosed to be paid by the Vendors to
the Corporation as a post-closing adjustment to the Cash Payment in accordance
with Paragraph 2.4 of this Agreement.
ARTICLE 11
ACKNOWLEDGEMENT OF XXXXX HELD IN TRUST
11.1 DEFINITIONS
In this Article,
(a) "Xxxxx" means well 4B-12-49-1-W4M ("Well 4B") and well
9B-12-49-1-W4M ("Well 9B") and any and all associated well
licences and registrations; and
(b) "Well Owners" means with respect to Well 4B, Xxxxx Venture I
Inc. as to 49% and Roswell Petroleum Corporation as to 51%,
and means with respect to Well 9B, Barcomp Petroleum Ltd. as
to 25%, Xxxxx Venture I Inc. as to 36.75% and Roswell
Petroleum Corporation as to 38.25%.
11.2 XXXXX IN TRUST
The Purchaser and the Corporation hereby acknowledges its understanding
and agreement that
(a) the Xxxxx are licensed in the name of the Corporation; and
(b) the Xxxxx are beneficially owned by the Well Owners and that
the Corporation only holds the license to the Xxxxx as bare
trustee for and on behalf of the Well Owners.
11.3 The Purchaser shall, at any time subsequent to the Closing, upon written
demand by any of the Well Owners, cause the Corporation to transfer, at the Well
Owners expense, the Xxxxx to the Well Owners, or to any other party as the Well
Owners may otherwise direct in writing.
27
ARTICLE 12
MISCELLANEOUS
12.1 GOVERNING LAW AND ATTORNMENT
This Agreement shall, in all respects, be governed by, subject to and
be interpreted, construed and enforced in accordance with the laws in effect
within the Province of Alberta. Each Party hereby expressly attorns to the
jurisdiction of the courts of the Province of Alberta and all courts of appeal
therefrom, and hereby waives any claim or defence of inconvenient forum.
12.2 TIME OF THE ESSENCE
Time shall in all respects be of the essence of this Agreement.
12.3 NOTICES
Delivery of notices, and service of any suit, action or proceeding
arising out of or related to this Agreement, may be effected for each of the
Parties at the following addresses:
Vendors: to the addresses given in Schedule "A",
With a copy to:
Gowling Xxxxxxx Xxxxxxxxx LLP
Suite 1400
000 -0xx Xx. X.X.
Xxxxxxx, Xxxxxxx X0X 0X0
Attention: X. Xxxxxx Xxxxxx
Fax (000) 000-0000
The Purchaser:
Assure Oil & Gas Corp.
Xxxxx 0000
Xxx Xxxxxxxx Xxxxx
X.X. Xxx 000
130 King Street West
Toronto, Ontario
M5X 1E3
Attention: The President
Fax: (000) 000-0000
With a copy to:
Burstall Winger LLP
3100, 000 - 0 Xxx. X.X.
00
Xxxxxxx, Xxxxxxx X0X 0X0
Attention: Xxxxx XxxXxxx
Fax (000) 000-0000
Each Party may from time to time change its address for service
hereunder by giving written notice to the other Party in accordance with this
Section 12.3. Any notice required or contemplated hereby may be served by
personal service upon an officer or director of a Party, or by facsimile
transmission, or mailing the same (except during periods of actual or
anticipated postal disruptions) by prepaid registered post in a properly
addressed envelope, to the Party at its address for service hereunder, as the
same may be amended from time to time in accordance herewith. Any notice given
by personal service upon an officer or director of a Party shall be deemed to be
given on the date of such service. Any notice given by mail shall be deemed to
be given to and received by the addressee on the fifth Business Day after the
mailing thereof. Any notice given by facsimile transmission shall be deemed to
be given to and received by the addressee on the first Business Day immediately
following the day upon which transmission thereof is made and appropriate answer
back has been received.
12.4 PRIOR AGREEMENTS
This Agreement supersedes and replaces any and all prior agreements,
discussions, negotiations, documents, understandings or other verbal or written
communications between the Parties relating to the Transaction and may be
amended only by written instrument signed by all Parties.
12.5 ENTIRE AGREEMENT
This Agreement sets forth the entire agreement between the Parties
pertaining to the Shares, the Assets, the Transaction or otherwise relating to
the subject matter hereof.
12.6 AMENDMENTS AND WAIVERS
No supplements, amendments or other modifications to this Agreement, or
any waiver of the application of a provision hereof, shall be binding upon a
Party, unless that Party has consented thereto in writing. No waiver by a Party
of any provision of this Agreement shall be deemed to or will constitute a
waiver of any other provision hereof (whether or not of a like or similar
nature) nor will a waiver constitute a continuing waiver, unless expressly
provided for in a written waiver executed by that Party.
12.7 ASSIGNMENT
Prior to Closing no Party shall assign or be entitled to assign this
Agreement or any portion hereof or any right or obligation hereunder, without
the prior written consent of the other Parties, which consent may be withheld
for any reason. In no circumstances shall the liabilities or obligations of the
Parties hereunder be increased or altered in any material way as a result of any
assignment that has been consented to pursuant to this Section 10.7 being
implemented. Subsequent to Closing, no assignment of a right or benefit under
this Agreement shall be binding upon a Party unless it has consented in writing
to such assignment, such consent not to be unreasonably withheld.
12.8 CONFIDENTIALITY
29
The Parties confirm their agreement and understanding that the terms
and conditions hereof are confidential. Except as required by law, no Party
shall disclose or use any information provided to it pursuant hereto for any
purpose other than related to the Transaction and the Closing thereof until
after Closing has occurred.
12.9 ENUREMENT
This Agreement shall enure to the benefit of and be binding upon the
Parties and their respective successors, receivers, receiver-managers, trustees,
heirs, administrators and permitted assigns, as the case may be.
12.10 FURTHER ASSURANCES
As and from the Closing Date, as may be necessary or desirable, and
without further consideration, the Parties shall execute, acknowledge and
deliver such other instruments and documents, and take all such other actions as
may be reasonably necessary, to carry out their respective obligations under
this Agreement in order to complete the Transaction on the basis and at the time
specified or contemplated hereby.
12.11 GENERAL OBLIGATIONS
Notwithstanding anything set forth in, or otherwise applicable under,
this Agreement or any other agreement to the contrary the obligations and
liabilities of Vendors hereunder are several, and not joint or joint and
several, it being the stated intention of the Parties that any rights,
liabilities or obligations of Vendors hereunder shall be determined in the
proportion that the number of Shares held by that Vendor bears to the total
Shares of the Corporation sold to the Purchaser hereunder.
12.12 SOLICITATIONS
Vendors covenant and agree that they will not, and will not permit the
Corporation to, solicit, entertain or negotiate any offer or invitation for the
sale of the Shares or the Assets or any rights or interest in respect thereto,
unless this Agreement is terminated prior thereto in accordance with the
provisions hereof.
12.13 FACSIMILE EXECUTION
Delivery of this Agreement may be effected by a Party by facsimile
transmission of the execution page hereof to the other Parties. A Party so
delivering this Agreement shall thereafter forthwith deliver to the other
Parties an original execution page hereof with its original signature located
thereon, provided however, that any failure by a Party to so deliver such
original execution page shall not effect the validity or enforceability hereof
against that Party.
12.14 SEVERABILITY
If any of the provisions of this Agreement are determined by a Court of
competent jurisdiction to be unenforceable, such provisions shall be deemed to
be severed from this Agreement, and of no force or effect whatsoever. All
remaining terms and conditions of this Agreement shall remain in full force and
effect between the Parties, enforceable in accordance with their respective
terms.
30
12.15 COUNTERPART EXECUTION
This Agreement may be executed in counterpart and all counterparts
shall together constitute one Agreement.
IN WITNESS WHEREOF the Parties have executed this Agreement as of the date first
above written.
ASSURE OIL & GAS CORP.
By: /s/ Xxxxx X. Xxxxx
----------------------------------
(illegible) /s/ Xxxx Xxxxxxx
-------------------------------- ---------------------------------------
Witness XXXX XXXXXXX
(illegible) /s/Xxxxx Xxxxx
-------------------------------- ---------------------------------------
Witness XXXXX XXXXX
(illegible) /s/Xxxx Xxxxxxxx
-------------------------------- ---------------------------------------
Witness XXXX XXXXXXXX
31
SCHEDULE "A"
NAME AND NUMBER AND PERCENTAGE OF
ADDRESS OF VENDOR SHARES OWNED
Xxxx Xxxxxxx 125 Class A common shares (62.5%)
000 - 00 Xxxxxx X.X.
Xxxxxxx, Xxxxxxx X0X 0X0
Fax No. (000) 000-0000
Xxxx Xxxxxxxx 60 Class B common shares (30%)
0000 - 00xx Xxx.
Xxxxxxxxxxxx, Xxxxxxx X0X 0X0
Fax No. (000) 000-0000
Xxxxx Xxxxx 15 Class C common shares (7.5%)
000, 000 - 0 Xxx. X.X.
Xxxxxxx, Xxxxxxx X0X 0X0
32
SCHEDULE "B"
SCHEDULE "B"LANDS, LEASES, XXXXX AND FACILITIES INVENTORY
Working
Legal Description Title Document Rights Assigned Interest
----------------- -------------- --------------- --------
Section 15-49-27-W3M FH Lease between Montreal Trust as NG in Sparky Zone, 60%
Lessor and Northwestern Utilities Lloydminster Zone, and
Limited Xxxxxxxx Zone
N1/2-23-49-28-W3M FH Lease between Xxxxx Xxxxx XX in Colony Zone 60%
Xxxxxxxx and Xxxx Xxxxx
Xxxxxxxxxxx as Lessors and
Northwestern Utilities Limited as
Lessee dated January 31st, 1992
Legal Description Tangibles Encumbrances
----------------- --------- ------------
Section 15-49-27-W3M Xxxxx at D14-15, and All petroleum rights are farmed out to a third party
D15-15 plus associated and not available.
equipment NG royalty of 16 2/3%
N1/2-23-49-28-W3M Well at 16-23 plus FH royalty of 15%
associated equipment
33
Working
Legal Description Title Document Rights Assigned Interest
----------------- -------------- --------------- --------
Section 24-49-28-W3M North East Quarter to be leased by NG in Colony Zone 60%
Four West to Westerra/Cedar upon
title transfer.
Lsds 13 & 14; SEM PO3019
South Half; SEM PN13,622 NG in Colony Zone 60%
Lsd 11; SEM PN5675
NG in Colony Zone 60%
Lsd 12; SEM PN5676
NG in Colony Zone 60%
NG in Colony Zone 60%
Legal Description Tangibles Encumbrances
----------------- --------- ------------
Section 24-49-28-W3M Xxxxx at 12-24, B13-24, NE quarter is being purchased by Four West. Leases
C13-24, 15-24 plus will follow successful title purchase.
associated equipment CAPL 91 lease royalty 15%.
Crown s/s royalty
Crown s/s royalty
Crown s/s royalty
Crown s/s royalty
34
Working
Legal Description Title Document Rights Assigned Interest
----------------- -------------- --------------- --------
Section 25-49-28-W3M FH lease between Xxxxxxxx Xxx the NG in Colony Zone 60%
Younger, Xxxx Xxx and Xxxx Xxxxx
Xxx as Lessor and Northwestern
Utilities Limited as Lessee dated
September 6, 1991
SE-26-49-28-W3M FH Lease with Salts as Lessor and NG in Colony Zone 60%
Xxxxx Development Company as Lessee
NE-14-50-28-W3M SEM NG in Colony Zone and 60%
Lsds 9, 15, 16 P02593 Lloydminster Zone.
Lsd 10 P06458
Section 27-49-01-W4M SEM NG in Colony 60%
Legal Description Tangibles Encumbrances
----------------- --------- ------------
Section 25-49-28-W3M Xxxxx at 2-25, 6-25, Railroad minerals excepted from DSU. Application in
13-25 plus associated progress to recoup lands into Fox title. Lease signed
equipment by Foxes and waiting for title work to be completed.
Royalty reduction agreement with Lessors to reduce
royalty to 12.5%. Agreed to pay for 50% of work
required to bring farm distribution system up to code
standards.
Lessor is entitled to free gas usage.
SE-26-49-28-W3M Well at 1-26 plus XX Xxxxxx Royalty plus use of free gas
associated equipment
NE-14-50-28-W3M Well at 10-14 plus These lands are being swapped with CNRL for their 45%
Lsds 9, 15, 16 associated equipment interest in the certain gas rights in Section
Lsd 10 9-50-01-W4M
Crown s/s Royalty
Section 27-49-01-W4M Well at 15-27 Crown Royalty
35
Working
Legal Description Title Document Rights Assigned Interest
----------------- -------------- --------------- --------
Lsds 10, 11, 14, 15 GL2645
Section 09-50-01-W4M FH leased between The Governor and Stored NG in Sparky Zone 60%
Company of Adventurers of England
Trading into Xxxxxx'x Bay also
known as Xxxxxx'x Bay Company and
Xxxxxx'x Bay Oil and Gas Limited
dated March 1st, 1948.
SE-22-50-02-W4M AE Lease # 6771 NG in Colony Zone and Waseca 60%
Xxxx
X0/0-00-00-00-X0X XX Xxxxx #XX 000 XX in Colony Zone 60%
Legal Description Tangibles Encumbrances
----------------- --------- ------------
Lsds 10, 11, 14, 15 Well at 6-9 plus These lands are currently part of a swap with CNRL.
associated equipment If successful all NG in all zones will be available.
Section 09-50-01-W4M Storage Agreement between Imperial Oil Limited and
Xxxxxx'x Bay Oil and Gas Limited and the Lloydminster
Development Company Limited dated January 19th, 1960
Well at 8-22 plus Crown Royalty
associated equipment
SE-22-50-02-W4M
None Crown Royalty
W1/2-22-50-02-W4M
36
WESTERRA/CEDAR LLOYDMINSTER FACILITIES INVENTORY
LSD 00-00-00-00 W3M
- One (1) dual zone gas well completed and producing from both Xxxxxxxx
and Lloydminster formations.
- Wellbore includes 7" Casing, and two (2) strings of 1-1/2" coil
tubing c/w hangers and dual assembly wellhead.
- Three (3) 12" x 5' s.t.s. 300 ANSI (715 psig) sweet separator/meter
skid packages c/w separator, junior meter run, Xxxxxx 2 pen recorder,
skid mounted 500 gallon methanol tank, Texsteam pneumatic methanol pump
and hard core building. Year Built 2001.
- Wellhead and separators surrounded by chain link security fencing.
- One (1) 200 bbl double walled steel internally coated water storage
tank c/w gauge board, ladder and thief hatch. Year Built 2001.
LSD 00-00-00-00 W3M
- One (1) single zone gas well completed and producing from the Sparky
formation.
- Wellbore includes 7" casing, 2-3/8" master valve, and one (1) string
of 1-1/2" coil tubing c/w hanger.
- One (1) Methanol sphere and gauge assembly
- One (1) 200 gallon Methanol tank c/w overhead stand.
- Separator located at the adjacent 14-15 lease.
LSD 00-00-00-00 W3M
- One (1) single zone gas well completed and producing from the Colony
formation.
- Wellbore includes 7" Casing, 2-3/8" master valve, and one (1) string
of 2-3/8" tubing.
- Two (2) 12" x 5' s.t.s. 300 ANSI (715 psig) sweet separator/meter
skid packages c/w separator, junior meter run, Xxxxxx 2 pen recorder,
skid mounted 500 gallon methanol tank, Texsteam pneumatic methanol pump
and hard core building. Year Built 2001.
37
- Wellhead and separators surrounded by chain link security fencing.
LSD 00-00-00-00 W3M
- One (1) single zone gas well completed and producing from the Colony
formation.
- Wellbore includes 7" Casing, 2-3/8" master valve, one (1) string of
2-3/8" tubing and one (1) string of 1-1/4" coil tubing c/w hanger.
- One (1) 12" x 5' s.t.s. 300 ANSI (715 psig) sweet separator/meter
skid package c/w separator, junior meter run, Xxxxxx 2 pen recorder,
skid mounted 500 gallon methanol tank, Texsteam pneumatic methanol pump
and hard core building. Year Built 2001.
- Wellhead and separator surrounded by chain link security fencing.
LSD B13-24-49-28 W3M
- One (1) single zone gas well completed in the Colony formation. Well
is currently shut-in Wellbore includes 7" Casing, 2-3/8" master valve,
one (1) string of 2-3/8" tubing, and one (1) string of 1-1/4" coil
tubing c/w hanger.
- Wellhead surrounded by chain link security fencing.
- Separator located at the adjacent C13-24 lease.
LSD C13-24-49-28 W3M
- One (1) single zone gas well completed in the Colony formation. Well
is currently shut-in. Wellbore includes 7" Casing, 2-3/8" master valve,
and one (1) string of 2-3/8" tubing.
- One (1) 12" x 5' s.t.s. 300 ANSI (715 psig) sweet separator/meter
skid package c/w separator, junior meter run, Xxxxxx 2 pen recorder,
skid mounted 500 gallon methanol tank, Texsteam pneumatic methanol pump
and hard core building. Year Built 2001.
- Wellhead and separator surrounded by chain link security fencing.
LSD 00-00-00-00 W3M
38
- One (1) single zone gas well completed in the Colony formation. Well
is currently shut-in.
- Wellbore includes 7" Casing, 2-3/8" master valve, one (1) string of
2-3/8" tubing, and one (1) string of 1-1/4" coil tubing c/w hanger.
- One (1) 12" x 5' s.t.s. 300 ANSI (715 psig) sweet separator/meter
skid package c/w separator, junior meter run, Xxxxxx 2 pen recorder,
skid mounted 500 gallon methanol tank, Texsteam pneumatic methanol pump
and hard core building. Year Built 2001.
- Wellhead and separator surrounded by chain link security fencing.
LSD 2-25-49-28 W3M
- One (1) single zone gas well completed in the Colony formation. Well
is currently shut-in. Wellbore includes 7" Casing, 2-3/8" master valve,
and one (1) string of 2-3/8" tubing.
- One (1) 12" x 5' s.t.s. 300 ANSI (715 psig) sweet separator/meter
skid package c/w separator, junior meter run, Xxxxxx 2 pen recorder,
skid mounted 500 gallon methanol tank, Texsteam pneumatic methanol pump
and hard core building. Year Built 2001.
- Wellhead and separator surrounded by chain link security fencing.
LSD 6-25-49-28 W3M
- One (1) single zone gas well completed and producing from the Colony
formation.
- Wellbore includes 7" Casing, 2-3/8" master valve, one (1) string of
2-3/8" tubing, and one (1) string of 1-1/4" coil tubing c/w hanger.
- One (1) 12" x 5' s.t.s. 300 ANSI (715 psig) sweet separator/meter
skid package c/w separator, junior meter run, Xxxxxx 2 pen recorder,
skid mounted 500 gallon methanol tank, Texsteam pneumatic methanol pump
and hard core building. Year Built 2001.
- Wellhead and separator surrounded by chain link security fencing.
LSD C13-25-49-28 W3M
- One (1) single zone gas well completed and producing from the Colony
formation.
- Wellbore includes 8 5/8" Casing, 2-3/8" master valve, one (1) string
of 2-3/8" tubing,
39
and one (1) string of 1-1/4" coil tubing c/w hanger.
- One (1) 12" x 5' s.t.s. 300 ANSI (715 psig) sweet separator/meter
skid package c/w separator, junior meter run, Xxxxxx 2 pen recorder,
skid mounted 500 gallon methanol tank, Texsteam pneumatic methanol pump
and hard core building. Year Built 2001.
- Wellhead and separator surrounded by chain link security fencing.
LSD 1-26-49-28 W3M
- One (1) single zone gas well completed and producing from the Colony
formation.
- Wellbore includes 7" Casing, 2-3/8" master valve, one (1) string of
2-3/8" tubing, and one (1) string of 1-1/4" coil tubing c/w hanger.
- Wellhead surrounded by chain link security fencing.
- Separator located at the adjacent 16-23 lease.
LSD 00-00-00-00 W3M * SEE GENERAL NOTES
- One (1) single zone gas well completed in the Colony formation. Well
is currently suspended.
- Wellbore includes 7" Casing, one (1) string of 2-3/8" tubing, one (1)
string of rods, and one (1) downhole pump.
- One (1) 16" x 19'-6" 6 tray dehydrator skid package. Package is in
good condition.
- One (1) 400Bbl Single walled steel tank c/w skid, burner, and
insulation.
- One (1) Pumpjack American 80,000 In-Lbs Approx. 50 inch stroke.
- One (1) Arrow C-46 engine.
- Wellhead and equipment surrounded by chain link security fencing.
LSD 15-24-49-1 W4M
- One (1) single zone gas well completed in the Colony formation. Well
is currently suspended.
40
- Wellbore includes 7" Casing, one (1) string of 2-3/8" tubing, one (1)
string of rods, and one (1) downhole pump.
- Equipment on this lease is already itemized on the surplus equipment
list.
- Wellhead and equipment surrounded by chain link security fencing.
XXX 0-0-00-0 X0X
- One (1) single zone gas well completed in the Sparky formation. Well
is currently suspended.
- Wellbore includes 7" Casing, one (1) string of 2-3/8" tubing, and one
2-3/8" master valve.** See General Notes
- Equipment on this lease is already itemized on the surplus equipment
list.
- Wellhead and equipment surrounded by chain link security fencing.
This site is also used for the storage of surplus equipment.
LSD 8-22-50-2 W4M
- One (1) single zone gas well completed in the Colony formation. Well
is currently suspended.
- Wellbore includes 7" Casing, one (1) string of 2-3/8" tubing, and one
2-3/8" master valve.
OTHER GENERAL NOTES:
* Equipment on this lease has not been included in the surplus equipment
list, and is part of the ongoing land swap with CNRL for Section 9-50-1 W4M.
** Wellbore is leased from ESSO. Westerra and partner Cedar have an obligation
to abandon the wellbore after use.
*** The information listed for these items may not be completely accurate and
is based on memory from previous site visits.
**** All producing properties including those shut-in xxxxx are flowlined into
an Altagas gathering and compression facility. Those xxxxx indicated as being
suspended either have no tie-
41
ins, or are tied-in to an ATCO gathering and distribution system.
42
SCHEDULE "C"
SURPLUS EQUIPMENT
WESTERRA/CEDAR LLOYDMINSTER SURPLUS INVENTORY
15B-27-49-01 W/4
DEHY $10,000**
1 - ABSORBER SEPARATOR, SERIAL #E742246-V2 CRN #C289.2,
D.O.B.=1975, OD 16" X 19'6" MWP=835PSI, CA=0, TEMP= 100,
SHELL=SA53B, T.S=60000 HEAD=SA51570, TS=70000, .500 SHELL,
HYDRO=12600 J.FFF.=100%, 4" INLET X 3" OUTLET SKIDDED &
HOUSED, NEEDS TLC
1 - REBOILER, SERIAL #E74224814, DOB 1975
75000 BTU/HR, 15PSI FUEL GAS
1 - TEXAS CARBINE - GLYCOL PUMP 1"
UNIT NEEDS TO BE GONE THROUGH, NEEDS NEW INSTRUMENT LINES & PAINT,
PIPING CHECKED.
PUMPJACK *$2,500**
1 - PUMPJACK, AMERCAN 80,000 IN-LBS APPROX. 50 IN STROKE.
ENGINE * $500**
1 - XXXXXXX 10 HP NATURAL GAS SINGLE CYLINDER ENGINE
NOTE: THIS EQUIPMENT IS LOCATED AT THE 15B-27-49-01 W4M SITE.
06B-25-49-28 W/3
DEHY $20,000**
1 - NATCO ABSORBER, D.O.B.= 08/1989
CRN#A-1011.3, A 2574402, SERIAL #LS-3899, MWP=4964KPA, 720PSI,
SHELL = 17MM OR .67", HEAD = 14.5MM OR .572",
CORR ALLOW = 1.6MM OR .0625"
T.P. = 7447, ORDER #5302-V1, 54O C. OR 129O F., SO-NO-5302-V1
1 - VERTICAL SEPARATOR, MODEL #D-6-720-2P
D.O.B.=1989, 720PSI, 100O F., CRN #02212.21
43
1 - NATCO REBOILER
18" X 43", 0-5PSI, D.O.B.=1989, SERIAL #LGR-1843-1436, DWG
#FA-5302-04
1 - XXXXXX & X'XXXXX ORDORANT TANK
8 5/8" X 2' 10", 720PSI, 100O F, A#2500605, CR#K200512
1 - TEXAS CARBINE - GLYCOL PUMP 1"
UNIT NEEDS TO BE GONE THROUGH, NEEDS NEW INSTRUMENT LINES & PAINT, PIPING
CHECKED
TANK* $2,000**
1 - 100 BBL EXTERNALLY INSULATED TANK C/W BURNER
NOTE: THIS EQUIPMENT HAS BEEN RELOCATED TO THE 6-9-50-1 W4M STORAGE SITE.
13B-24-49-28 W/3
DEHY $18,500**
1 - XXXXXXXX XXXXX, XXXXXX #X-0000-00
X#000000, 00X X, 0000XXX, 14.8MM SHELL, 14.3MM HEAD 4"
INLET X 3" OUTLET 1 - TEXAS CARBINE 1" GLYCOL PUMP
1 - REBOILER, SERIAL #SA178-001-V4, MODEL #32-C1-6068.LP
90000BTU, D.O.B. = 1981
UNIT NEEDS TO BE GONE THROUGH, NEEDS NEW INSTRUMENT LINES & PAINT, PIPING
CHECKED
NOTE: THIS EQUIPMENT HAS BEEN RELOCATED TO THE 6-9-50-1 W4M STORAGE SITE.
13C-24-49-28 W/3
DEHY $18,500**
1 - ABSOBER TOWER, SERIAL #80-171-3
6895KPA, 66O C, D.O.B.03/1980, CRN#D5894.2, A#158337
44
SHELL - SA-53-B, HEAD - SA-516-70, SHELL & HEAD - 14.3MM
1 - REBOILER (NO INFORMATION AVAILABLE) 90000BTU
1 - TEXAS CARBINE GLYCOL PUMP, 1"
UNIT NEEDS TO BE GONE THROUGH, NEEDS NEW INSTRUMENT LINES & PAINT, PIPING
CHECKED
NOTE: THIS EQUIPMENT HAS BEEN RELOCATED TO THE 6-9-50-1 W4M STORAGE SITE.
00-00-00-00 W3M
PUMPJACK *$2,500**
1 - PUMPJACK, AMERCAN 80,000 IN-LBS APPROX. 50 IN STROKE.
ENGINE * $750**
1 - ARROW C-46 APPROX. 10 HP NATURAL GAS SINGLE CYLINDER ENGINE
TANK* $2,000**
1 - 100 BBL EXTERNALLY INSULATED TANK C/W BURNER
NOTE: THIS EQUIPMENT HAS BEEN RELOCATED TO THE 6-9-50-1 W4M STORAGE SITE.
6-9-50-1 W4M
COMPRESSOR PACKAGE * $15,000**
1 - AJAX DPC 80 (80 HP INTEGRAL ENGINE/COMPRESSOR PACKAGE)
RECENTLY REBUILT, MISSING X-PROOF WIRING HARNESS, NO PROCESS COOLER. THIS
COMPRESSOR WAS USED TO BOOST PRESSURE INTO THE SPARKY STORAG POOL.
NOTE: THIS EQUIPMENT IS LOCATED AT THE 6-9-50-1 W4M SITE.
OTHER GENERAL NOTES:
* THE INFORMATION LISTED FOR THESE ITEMS MAY NOT BE ACCURATE AND IS BASED
ON MEMORY FROM PREVIOUS SITE VISITS.
** ALL PRICES ARE APPROXIMATE MARKET VALUES.
45
SCHEDULE "D"
PURCHASER'S CERTIFICATE
Re: Share Purchase Agreement dated April 1, 2002 (the "Purchase Agreement")
Xxxxx X. Xxxxx, President of Assure Oil & Gas Ltd. (the "Purchaser"),
hereby certify that as of the date of this Certificate:
1. Unless otherwise defined herein, all capitalized terms used in this
Certificate are as defined in the Purchase Agreement.
2. The covenants, representations and warranties of the Purchaser
contained in Section 5.1 of the Purchase Agreement were true and
correct in all material respects at and as of the date of such
agreement, have continued to be true in all material respects from that
date to the date hereof and are true and correct in all materials
respects at and as of the Closing Date.
3. This Certificate is made for and on behalf of the Purchaser and is
binding upon it and the deponent herein is not and will not incur any
personal liability whatsoever with respect to it except in the case of
fraud by the deponent.
4. This Certificate is made with full knowledge that Vendors are relying
on the same for the Closing of the Transaction contemplated by the
Purchase Agreement.
IN WITNESS WHEREOF the undersigned has executed this Certificate as of
the Closing Date.
ASSURE OIL & GAS CORP.
Per: ________________________________
Xxxxx X. Xxxxx, President
46
SCHEDULE "E"
VENDOR'S CERTIFICATE
Re: Share Sale and Purchase Agreement dated -, 2002
I, [INSERT NAME], hereby certify that as of the date of this
Certificate:
1. Unless otherwise defined herein, all capitalized terms used in this
Certificate are as defined in the Purchase Agreement.
2. The covenants, representations and warranties of me as a Vendor
contained in Section 4.2 of the Purchase Agreement are true and correct
in all materials respects at and as of the Closing Date.
3. This Certificate is made for and on behalf of myself as a Vendor and
not on behalf of or related in any way to any other Person.
4. This Certificate is made with full knowledge that - is relying on the
same for the Closing of the Transaction contemplated by the Purchase
Agreement.
IN WITNESS WHEREOF the undersigned has executed this Certificate as of
the Closing Date.
________________________________
[VENDOR'S NAME]
47
SCHEDULE "F"
LAWSUITS AND CLAIMS
NIL
48
SCHEDULE "G"
PRODUCTION SALES CONTRACTS
Natural Gas Purchase Agreement dated January 23, 2002 between AltaGas
Services Inc. and the Corporation.
49
SCHEDULE "H"
TAKE OR PAY OBLIGATIONS
NIL
50
SCHEDULE "I"
EMPLOYEE MATTERS
1. Resignations and Releases
On or before Closing, Vendors shall cause the Directors, Officers,
employees and consultants of Corporation to resign effective as of the
Closing Date or earlier and on or before the Closing Date shall obtain
releases from each of them.
2. Severance:
Nil
51
SCHEDULE "J"
OPEN AFEs
AFE (attached) for the rebuild of the Fox distribution system.
52
WESTERRA 2000 INC.
[INTEGRA FOX DISTRIBUTION SYSTEM
ENERGY CONSULTING LOGO] AFE COST BREAKDOWN
PROJECT #:__________
AFE #:__________
________________________________________________________________________________________
Activity AFE Risk
No. Subtotal Cost Probability Capital
________________________________________________________________________________________
0513 Engineering Design Qty $ 448 90% $ 45
Mechanical Engineering 2 days $ --
Drafting 1 day $ 440
PST on Professional
Services (1.8%) $ 8
________________________________________________________________________________________
0541 Line Pipe Qty
1" yellow Polyethylene
Pipe 1500 $1,500 $3,313 90% $ 331
1" Yellow PE x Sched 40
Anodeless Transition
Risers 19 $ 950
HDPE Fittings 1 lot $ 300
16 Gauge Tracer Wire 1,500 $ 375
PST on Materials (6%) $ 188
Source: Xxxxxxxx/Polytubes
________________________________________________________________________________________
0543 Pipe, Valves, & Fittings Qty
Pipe, Fittings 1 lot $1,500 $3,032 90% $ 303
33B15T1A (1" Ball Xxxxx) 00 $1,250
Z1N60T5A (1/2" Needle
Valve) 2 $ 110
PST on Materials (6%) $ 172
Source:
________________________________________________________________________________________
0549 Instrumentation Qty $1,855 90% $ 000
X-000 Xxxxxxxxxx 14 $1,750
PST on Materials (6%) $ 105
Source: Guest Controls
________________________________________________________________________________________
0559 Mechanical Construction Qty $2,400 90% $ 240
Pipefitter 4 days $1,440
Labourer 4 days $ 960
Source: R&D Plumbing
________________________________________________________________________________________
0562 Pipeline Construction Qty $14,210 90% $1,421
Remove Xxxx $1,500
Line Locate 1 day $ 640
Trench, Install Pipe,
Backfill 1500 $6,000
Backhoe 2 days $1,120
Fusions 50 $1,500
Gas Permit 14 $ 000
Xxxx Xxxxxxxxx 10 $2,000
Pressure Test 1500 $ 750
Source: R&D Plumbing
________________________________________________________________________________________
0566 Cathodic Protection Qty $ 159 90% $ 16
Sacrificial Anode on
Gas Risers $ 150
PST on Materials $ 9
Source: Previous Projects
________________________________________________________________________________________
0580 Contingency
As summarized in Risk
Capital column. $2,542 $2,542 100%
________________________________________________________________________________________
0595 Overhead (5%)
5% on Project Sub-total $1,271 $1,271 100%
________________________________________________________________________________________
AFE Sub-Total $29,228 91% $2,542
______________________________________________
53
SCHEDULE "K"
FINANCIAL STATEMENTS
54
WESTERRA 2000 INC.
FINANCIAL STATEMENTS
MARCH 31, 2002
55
WESTERRA 2000 INC.
INDEX TO FINANCIAL STATEMENTS
MARCH 31, 2002
Page
AUDITORS' REPORT 1
FINANCIAL STATEMENTS
Balance Sheet 2
Statement of Loss and Deficit 3
Statement of Cash Flows 4
Notes to Financial Statements 5-8
56
AUDITOR'S REPORT
To the Shareholders of Westerra 2000 Inc.
We have audited the balance sheet of Westerra 2000 Inc. as at March 31, 2002 and
the statements of loss and deficit and cash flows for the year then ended. These
financial statements are the responsibility of the company's management. Our
responsibility is to express an option on these financial statements based on
our audit.
We conducted our audit in accordance with Canadian generally accepted auditing
standards. Those standards require that we plan and perform an audit to obtain
reasonable assurance whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
In our opinion, these financial statements present fairly, in all material
respects, the financial position of the company as at March 31, 2002 and the
results of its operations and its cash flows for the year then ended in
accordance with Canadian generally accepted accounting principles.
/s/ Daunheimer & Dow LLP
--------------------------
Calgary, Alberta Chartered Accountants
May 10, 2002
57
WESTERRA 2000 INC.
BALANCE SHEET
MARCH 31, 2002
2002 2001
---- ----
ASSETS
CURRENT
Cash $ 14,492 $ 19
Accounts receivable 28,894
Goods and services tax recoverable 41,997
Prepaid expenses 1,665 853
----------- -----------
87,048 19
PROPERTY, PLANT AND EQUIPMENT (Note3) 2,600,078 --
----------- -----------
$ 2,678,078 $ 19
----------- -----------
LIABILITIES AND SHAREHOLDERS' DEFICIENCY
CURRANT
Accounts payable and accrued liabilities $ 58,438 $ 1,372
Acquisition loan payable (Note4) 2,700,789 --
----------- -----------
2,759,236 1,372
PROVISION FOR SITE RESTORATION 14,700 --
----------- -----------
2,773,936 1,372
----------- -----------
SHAREHOLDERS' DEFICIENCY
Share capital (Note 5) 20 20
Deficit (86,878) (1,373)
----------- -----------
(86,858) (1,353)
----------- -----------
$ 2,687,078 $ 19
----------- -----------
(All amounts are expressed in $Canadian.)
SEE ACCOMPANYING NOTES
Daunheimer & Dow LLP
Chartered Accountants
58
WESTERRA 2000 INC.
STATEMENT OF LOSS AND DEFICIT
YEAR ENDED MARCH 31, 2002
2002 2001
---- ----
REVENUE
Gas revenue $ 950,940 $ --
--------- ---------
ROYALTIES
Crown royalties 172,618 --
Freehold royalties 79,167 --
--------- ---------
251,785
NET OIL AND GAS REVENUE 699,155
--------- ---------
EXPENSES
Production expenses 315,513 --
Depletion and site restoration 215,986 --
Interest 192,752 --
General and administrative 60,409 1,373
--------- ---------
784,660 1,373
--------- ---------
NET LOSS (85,505) (1,373)
DEFICIT - Beginning of year (1,373) --
--------- ---------
DEFICIT - END OF YEAR $ (86,878) $ (1,373)
--------- ---------
(All amounts are expressed in $Canadian.)
SEE ACCOMPANYING NOTES
Daunheimer & Dow LLP
Chartered Accountants
59
WESTERRA 2000 INC
STATEMENT OF CASH FLOWS
YEAR ENDED MARCH 31, 2002
2002 2001
---- ----
OPERATING ACTIVITIES
Net loss $ (85,505) $ (1,373)
Item not affecting cash:
Depletion and site restoration 215,986 --
----------- -----------
130,481 (1,373)
----------- -----------
Changes in non-cash working capital:
Accounts receivable (28,894) --
Prepaid expenses (1,665) --
Accounts payable and accrued liabilities 57,066 1,372
GST payable (receivable) (41,997) --
----------- -----------
(15,490) 1,372
----------- -----------
Cash flow from (used by) operating activities 114,991 (1)
----------- -----------
INVESTING ACTIVITIES
Additions to capital assets (2,801,316) --
Cash flow from financing activities (2,801,316) --
FINANCING ACTIVITIES
Acquisition loan payable 2,508,114 --
Interest payable 192,684 --
Issue of share capital -- 20
----------- -----------
Cash flow from financing activities 2,700,798 20
----------- -----------
INCREASE IN CASH FLOW 14,473 19
CASH - Beginning of year 19 --
----------- -----------
CASH - END OF YEAR $ 14,492 $ 19
----------- -----------
(All amounts are expressed in $Canadian.)
SEE ACCOMPANYING NOTES
Daunheimer & Dow LLP
Chartered Accountants
60
WESTERRA 2000 INC.
NOTES TO FINANCIAL STATEMENTS
YEAR ENDED MARCH 31, 2002
--------------------------------------------------------------------------------
1. DESCRIPTION OF OPERATIONS
Westerra 2000 Inc. (the "Company") is a private company extra-provincially
incorporated under the Alberta and Saskatchewan Business Corporations
Acts, and is engaged in production, development and exploration of oil and
natural gas in Canada.
--------------------------------------------------------------------------------
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The financial statements of the Company have been prepared by management
in accordance with Canadian generally accepted accounting principles. The
preparation of financial statements in conformity with Canadian generally
accepted accounting principles requires management to make estimates and
assumptions that affect the amounts reported in the financial statements
and accompanying notes. Actual results could differ from those estimates.
The financial statements have, in management's opinion, been properly
prepared using careful judgement with reasonable limits of materiality and
within the framework of the significant accounting polices summarized
below.
Property, Plant and Equipment
The Company follows the full cost method of accounting for oil and gas
operations whereby all costs of exploring for and developing oil and gas
reserves are initially capitalized. Such costs include land acquisition
costs, geological and geophysical expenses, carrying charges on
non-producing properties, costs of drilling and overhead charges directly
related to acquisition and exploration activities.
Costs capitalized, together with the costs of production equipment, are
depleted and amortized on the unit-of-production method based on the
estimated gross proven reserves as determined by independent petroleum
engineers. Petroleum products and reserves are converted to a common unit
of measure using 6 MCF of natural gas to one barrel of oil.
Costs of acquiring and evaluating unproved properties are initially
excluded from depletion calculations. These unevaluated properties are
assessed periodically to ascertain whether impairment has occurred. When
proved reserves are assigned or the property is considered to be impaired,
the cost of the property or the amount of the impairment is added to costs
subject to depletion calculations.
Proceeds from a sale of petroleum and natural gas properties are applied
against capitalized costs, with no gain or loss recognized, unless such a
sale would alter the rate of depletion by more than 20%. Alberta Royalty
Tax Credits are included in oil and gas sales.
In applying the full cost method, the Company performs a ceiling test on
properties which restricts the capitalized costs less accumulated
depletion from exceeding an amount equal to the estimated undiscounted
value of future net revenues from proved oil and gas reserves, as
determined by independent engineers, based on sales prices achievable
under existing contracts and posted average reference prices in effect at
the end of the year, and current costs, and after deducting estimated
future general and administrative expenses, production related expenses,
financing costs, future site restoration costs and income taxes.
Site Restoration
Site restoration costs are accrued based on management's best estimate of
these future costs calculated on the unit-of-production basis, utilizing
proved producing reserves.
Daunheimer & Dow LLP
Chartered Accountants
61
WESTERRA 2000 INC.
NOTES TO FINANCIAL STATEMENTS
YEAR ENDED MARCH 31, 2002
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)
Joint Venture Accounting
Substantially all of the Company's operations are carried out through
joint ventures. These financial statements reflect only the Company's
proportionate interest in such activities.
Financial Instruments
The Company carries a number of financial instruments as detailed on the
balance sheet. It is management's opinion that the Company is not exposed
to significant interest, currency or credit risks arising from these
financial instruments. The fair values of these financial instruments
approximate their carrying values, unless otherwise noted.
Measurement Uncertainty
The amounts recorded for depletion of petroleum and natural gas properties
and equipment and the provision for future site restoration and
reclamation are based on estimates. The ceiling test is based on estimates
of proved reserves, production rates, oil and gas prices, future costs and
other relevant assumptions. By their nature, these estimates are subject
to measurement uncertainty and the effect on the financial statements of
changes and estimates in future periods could be significant.
The financial statements include accruals based on the terms of existing
joint venture agreements. Due to varying interpretations of the definition
of terms in these agreements the accruals made by management in this
regard may be significantly different from those determined by the
Company's joint venture partners. The effect on the financial statements
resulting from such adjustments, if any, will be reflected prospectively.
Future Income Taxes
The liability method of tax allocation is used in accounting for income
taxes. Under this method, future tax assets and liabilities are determined
based on differences between the financial reporting and tax bases of
assets and liabilities and measured using the substantially enacted tax
rates and laws that will be in effect when the differences are expected to
reverse. Future tax expense was based on items of income and expense that
were reported in different years in the financial statements and tax
returns and measured at the tax rate in effect in the year the difference
originated. Future income tax assets are evaluated and if realization is
considered "more likely than not" a valuation is provided.
--------------------------------------------------------------------------------
3. PROPERTY, PLANT AND EQUIPMENT
Cost Accumulated 2002 2001
Amortization NET BOOK Net book
VALUE value
------------------------------------------------------------
Petroleum and natural gas properties $ 2,801,316 $ 201,286 $ 2,600,030 $ -
============================================================
Daunheimer & Dow LLP
Chartered Accountants
62
WESTERRA 2000 INC.
NOTES TO FINANCIAL STATEMENTS
YEAR ENDED MARCH 31, 2002
4. INTEREST AND ACQUISITION LOAN PAYABLE
2002 2001
-----------------------
Interest payable $ 192,684 $ -
Acquisition loan payable - bridge loan 2,310,458 -
Acquisition loan payable - working capital loan 197,656 -
-----------------------
$2,700,798 $
=======================
The Company entered into a loan agreement with a joint venture operator to
finance the Company's purchase of its oil and gas properties. The loan is
comprised of two parts:
- Bridge loan, bearing interest at the bank prime rate plus 4.0%,
compounded daily. Interest only is payable on the first business day
following every month. The principal and any accrued interest is due and
payable on June 28, 2002.
- Working capital loan, including a commitment fee payable of $125,000 and
unpaid interest charges, not to exceed $450,000, bearing interest at the
bank prime rate plus 4.0%, compounded daily. Interest is payable on the
first business day following every month. The principal is repayable in
six monthly payments commencing January 31, 2002 and any unpaid amounts
are due and payable on June 28, 2002.
These loans are secured by a general security agreement.
--------------------------------------------------------------------------------
5. SHARE CAPITAL
2002 2001
Authorized:
Unlimited number of Class A voting common shares
Unlimited number of Class B voting common shares
Unlimited number of Class C voting common shares
Unlimited number of Class D non-voting common shares
Unlimited number of Class E non-voting common shares
Unlimited number of Class F non-voting preferred shares
Unlimited number of Class G non-voting preferred shares
Issued:
125 Class A common shares $ 12 $ 12
60 Class B common shares 6 6
15 Class C common shares 2 2
------------------
$ 20 $ 20
==================
--------------------------------------------------------------------------------
6. INCOME TAXES
At March 31, 2002, the Company had approximately $124,000 of loss
carryover balances which will expire in 2009. In addition, the Company has
capital cost pools, resource pools and deferred financing cost pools
approximating $2,480,000 to deduct against future taxable income.
--------------------------------------------------------------------------------
63
WESTERRA 2000 INC.
NOTES TO FINANCIAL STATEMENTS
YEAR ENDED MARCH 31, 2002
--------------------------------------------------------------------------------
7. RELATED PARTY TRANSACTIONS
During the year, the Company entered into the following transactions with
related parties:
The Company incurred consulting fees of $22,500 to a company owned by a
shareholder.
Included in accounts receivable is $26,049 due from a company owned by a
shareholder, pertaining to certain joint venture operations.
Included in accounts payable is $44,766 due to shareholders or to
companies and entities owned by shareholders pertaining to joint venture
operations, expenses paid on behalf of the Company and consulting fees
incurred.
Revenue and expense transactions were conducted at fair market value and
in the normal course of business.
--------------------------------------------------------------------------------
8. SUBSEQUENT EVENT
Subsequent to the year end, the Company shareholders entered into a
purchase and sale agreement to sell all the outstanding shares at March
31, 2002, to an arms length party for $3,450,000 effective April 1, 2002.
--------------------------------------------------------------------------------
9. COMPARATIVE FIGURES
Some of the comparative figures have been reclassified to conform to the
current year's presentation. The prior year's figures were reported on a
Notice to Reader basis.
--------------------------------------------------------------------------------
64
SCHEDULE "L"
ALTAGAS PAYOUT AMOUNTS
65
[ALTAGAS LOGO]
0000, 000-0xx Xxxxxx XX
Xxxxxxx, Xxxxxxx X0X 0X0
Westerra 2000 Inc.
000 Xxxxxxxxx Xx. XX
Xxxxxxx, Xxxxxxx X0X 0X0
REVISED LOAN STATEMENT AS OF MARCH 31, 2002
Principal:
Bridge Loan - Acquisition of Lloydminster $2,310,458.37
=============
Working Capital Loan - Commitment Fee
Commitment Fee $ 125,000.00
Additions to Working Capital 49,473.52
-------------
$ 174,473.52
=============
Interest (Prime + 4%) to March 31, 2002:
Bridge Loan $170,942.27
Working Capital Loan $ 21,829.39
-------------
Total Interest $ 192,771.66
=============
Total Loan Balances @ March 31, 2002:
Bridge Loan $2,310,458.37
Working Capital Loan (incl. Interest) $ 367,245.18
-------------
Total Loans $2,677,703.55
=============
66
[ALTAGAS LOGO]
0000, 000-0xx Xxxxxx XX
Xxxxxxx, Xxxxxxx X0X 0X0
Westerra 2000 Inc.
000 Xxxxxxxxx Xx. XX
Xxxxxxx, Xxxxxxx X0X 0X0
REVISED LOAN STATEMENT AS OF APRIL 30, 2002
Principal:
Bridge Loan - Acquisition of Lloydminster $2,310,458.37
=============
Working Capital Loan - Commitment Fee
Commitment Fee $ 125,000.00
Additions to Working Capital 49,473.52
-------------
$ 174,473.52
=============
Interest (Prime + 4%) to April 30, 2002:
Bridge Loan $ 185,881.12
Working Capital Loan $ 24,203.91
-------------
Total Interest $ 210,085.03
=============
Total Loan Balances @ April 30, 2002:
Bridge loan $2,310,458.37
Working Capital Loan (incl. Interest) $ 384,558.55
-------------
TOTAL LOANS EXCLUDING APRIL JOINT VENTURE XXXXXXXX AND G&P FEES $2,695,016.92
=============
DAILY INTEREST PER DIEM BEGINNING MAY 1, 2002 $ 581.09
=============
(Does not include interest on May Joint Venture Xxxxxxxx or
Gathering and Processing Fees)
67
SCHEDULE "M"
Notice of Default from AltaGas.
68
[ALTAGAS XXXX]
Xxxxx 00, 0000
XXX XXXXXXX and FAX (000) 000-0000
Westerra 2000 Inc.
000, 000 - 0xx Xxxxxx XX
Xxxxxxx, XX X0X OW7
Attention: President
Dear Sirs:
Re: LOAN AGREEMENT DATED JUNE 1, 2001 BETWEEN WESTERRA 2000 INC. AND
ALTAGAS SERVICES INC. (THE "LOAN AGREEMENT")
GENERAL SECURITY AGREEMENT DATED JUNE 1, 2001 BY THE BORROWER IN
FAVOUR OF THE LENDER
NOTICE OF DEFAULT
Due to Borrower's failure to make the payments required by Section 2.4 of
the Loan Agreement on January 31, 2002 and February 28, 2002, Borrower has
committed an Event of Default under and pursuant to Section 6.1(a) of the
Loan Agreement. Further, due to Borrower's failure to deliver the financial
statements required by Section 5.1(a) of the Loan Agreement, Borrower will
have committed an Event of Default under and pursuant to Section 6.1(c) of
the Loan Agreement if such statements are not delivered to Lender within
ten (10) Business Days from the date hereof.
Default under and pursuant to Section 6.1(a) of the Loan Agreement
constitutes default under and pursuant to the provisions of the Security
Agreement in accordance with the provisions of Section 5(a) thereof.
Default under and pursuant to the provisions of the Loan Agreement
constitutes default under and pursuant to the provisions of the Security
Agreement in accordance with the provisions of Section 5(b) thereof.
The Lender has currently elected not to declare, pursuant to Section 6.1 of
the Loan Agreement, the Loan Amount immediate due and payable together with
all accrued interest and fees and other amounts payable under and pursuant
to the Loan Agreement, in exchange for Borrower's agreement and
acknowledgement as follows:
1. As of February 28, 2002, Borrower was indebted to the Lender in
the following amounts:
Bridge Loan Amount $2,310,458.37
Working Capital Loan Amount 420,117.25
-------------
Loan Amount $2,730,575.62
=============
Additional amounts will accrue on account of interest and costs as
calculated under and pursuant to the provisions of the Loan Agreement.
Prior to making
69
2
payment of the amounts owing to the Lender, Borrower may contact Lender to
ascertain the exact amount owing on the date Borrower elects to make any
such payment.
2. Borrower acknowledges the foregoing Event of Default pursuant to Section
6.1(a) of the Loan Agreement, and the pending Event of Default pursuant to
Section 6.1(c) of the Loan Agreement.
3. Borrower will deliver to the Lender not later than May 15, 2002 a copy of
Borrower's annual consolidated financial statements together with the notes
thereto, prepared in accordance with generally accepted accounting
principals in Canada, consistently applied.
4. Borrower, on or before the last Business Day of each calendar month, will
provide a report to Lender detailing its progress towards being able to
repay by June 28, 2002 the Loan Amount, the interest accrued thereon, any
outstanding fees and all other amounts payable.
5. Borrower irrevocably requests and directs, effective immediately, that all
amounts due and owing to Borrower by:
a. Lender pursuant to a Gas Management and Supply Agreement between
Borrower and Lender dated June 1, 2001 be paid directly to Cedar
Energy Partnership ("Cedar") and be applied to Borrower's obligations
pursuant to a Joint Operating Agreement between Borrower and Cedar
dated June 1, 2001 (the "JOA");
b. Cedar pursuant to the JOA be paid directly to Lender and be applied to
reduce firstly any accrued interest and fees pursuant to the Loan
Agreement, secondly the Working Capital Loan Amount, thirdly the
Bridge Loan Amount, and lastly all other amounts payable under the
Loan Agreement.
Borrower ratifies and confirms all actions by Lender and Cedar prior to the
date hereof that have caused funds to be directed and applied in the
foregoing manner. Borrower agrees that provision of a copy of this
direction to Cedar shall be sufficient instruction to Cedar.
6. Lender may declare the Loan Amount, all accrued interest and fees and all
other amounts payable under the Loan Agreement immediately due and payable
on demand, in which case Lender may take whatever remedies it deems
appropriate and as are available to it under and pursuant to the provisions
of the Loan Agreement, the Security Agreement, such other security for
payment granted by Borrower to Lender and such remedies as are available to
Lender at law.
7. This agreement shall in no way be interpreted as a waiver of any provision
of the Loan Agreement.
Unless otherwise defined herein, capitalized words shall have the meaning given
to them in the Loan Agreement.
[ALTAGAS LOGO]
70
3
If you are in agreement with the foregoing, please execute and return the
enclosed duplicate copy of this letter not later than 12:00 noon on March
26, 2002. If we have not received your executed copy of this letter by
this time, this will serve as our declaration pursuant to section 6.1 of
the Loan Agreement that the Loan Amount, all accrued interest and fees and
all other amounts payable under the Loan Agreement are immediately due and
payable, following which our remedies pursuant to the Loan Documents may be
exercised.
Yours truly,
ALTAGAS SERVICES INC.
/s/ Xxxxx X. Xxxxxxxx
----------------------------
Xxxxx X. Xxxxxxxx
Executive Vice President,
Marketing, Extraction and
Transmission
Agreed and accepted this 8 day of APR, 2002.
WESTERRA 2000 INC.
Per: /s/ Xxxx Xxxxxxx
----------------------
Print Name: XXXX XXXXXXX
Print Title: PRESIDENT
[ALTAGAS LOGO]
71
SCHEDULE "N"
Additional Disclosures
72
[FOUR WEST LAND CONSULTANTS (1995) LTD. LETTERHEAD]
May 7, 2002
Assure Oil & Gas Corp
0 Xxxxxxxx Xxxxxx Xxxx
Xxxxxxx, Xxxxxxx
X0X 0X0
and
x/x Xxxxxxxx Xxxxxx XXX
0000, 000 - 0xx Xxxxxx XX
Xxxxxxx, Xxxxxxx
X0X 0X0
Attention: Xxxxx XxxXxxx
RE: Notice of Disclosure for Share Purchase of Westerra 2000 Inc.
Further to the completion of the proposed share sale dated April 1, 2002
the following disclosures are made by the shareholders.
1. Ongoing Supplier Obligations: There is a contract with Applied
TerraVision to provide production accounting software and support for
the WolfePac accounting package. A copy of the contract is attached.
2. Issues with AltaGas:
3. Lease Expires: Husky lease on Section 27-49-01-W4M. The lease was for
the Colony Zone only for Lsds 14 & 15. Husky has advised that the
lease has expired and is of no further force and effect. There was no
value assigned to these lands in the Tilikum Report. There will be an
immediate liability for both surface and well bore reclamation for the
well in Lsd 15 unless another party takes over the liability. There is
associated with the well surface equipment with salvage value as per
the surplus equipment list.
4. Over Production Issue: The 15-15 well was put on production November
13, 2001 and was allowed to produce for a clean-up period before it
was AOF tested. The AOF test and allowable was submitted the week of
Dec. 17, 2001. An application for GPP status (waiver of allowable
restriction) was submitted on Jan 8, 2002, and was approved by Feb.
15, 2002. For the period from the date of submission of allowable to
the date of approval of GPP this well was produced in excess of the
allowable by approximately 40% or 130 mcf/d. No penalty has been
issued to date by the SEM.
73
5. Incomplete DSUs: (a) Section 25-49-28-W3M. There is a railroad right
of way through this section. It has been excepted from the Certificate
of Title. Leases are in place with the current Registered Owners who
we feel are the correct beneficial owners. This is a matter for which
the working interest partners are responsible. Kanuka Xxxxxxxxx are
working on this matter at their Regina office. (b) NE-24-49-28-W3M.
There is a railroad right of way through this Quarter of approximately
5 acres. It has been excepted from the Certificate of Title. The
beneficial chain has been established through Kanuka Xxxxxxxxx at
their Regina office. Kanuka Xxxxxxxxx are working on this matter at
their Regina office. This is a matter for which the working interest
partners are responsible. FOUR WEST IS NOT ACQUIRING THIS INTEREST AND
WILL NOT BE THE LEASING PARTY.
6. There is an AMI with Cedar Energy covering the Vendor's interests. It
expires June 1, 2002. A copy is in the Closing book that is in the
possession of Xx. Xxxxx XxxXxxx.
7. The natural gas reserves are dedicated to AltaGas Services Inc. for
the life of the reserves.
8. There is a Natural Gas Purchase/Sale Confirmation agreement with ASI
which expires November 1, 2002
There may be additional disclosures made in the future.
If you have any questions in this regard please contact the writer.
FOUR WEST LAND CONSULTANTS (1995) LTD.
For Westerra 2000 Inc.
/s/ Xxxxx X. Xxxxx
----------------------------
Xxxxx X. Xxxxx - President
74
NATURAL GAS PURCHASE/SALE CONFIRMATION
Date: January 23, 2002
To: WESTERRA 2000 INC. Phone: (000)000-0000
Attn: XXXX XXXXXXX Fax: 000-0000
This Confirmation confirms the verbal agreement reached on or about
Wednesday, October 3, 2001 ("Effective Time"), between Westerra 2000 Inc.
("Customer") and AltaGas Services Inc. ("AltaGas") regarding the sale and
purchase of gas under the following terms and conditions:
CONDITIONS PRECEDENT (if any): NONE
BUYER ALTAGAS SERVICES INC.
SELLER WESTERRA 2000 INC.
DCQ: DEAL #1 - THE FIRST 750 GJ OF PRODUCTION AT THE DELIVERY
POINT.
DEAL #2 - PRODUCTION ABOVE 750 GJ PER DAY AND UP TO 3000
GJ PER DAY AT THE DELIVERY POINT.
DELIVERY POINT: LLOYDMINISTER
CONTRACT PRICE: DEAL #1 FIXED PRICE OF $2.96 PER GJ MINUS $0.14 PER GJ.
DEAL #2 - AECO MONTHLY INDEX MINUS $0.14 PER GJ. WHERE
THE AECO MONTHLY INDEX IS THE INTRA-ALBERTA WEIGHTED
AVERAGE ONE-MONTH SPOT PRICE AS PUBLISHED IN
ENERDATA'S "CANADIAN GAS PRICE REPORTER", ITEM 7A,
(C$/GJ).
TRANSACTION OBLIGATION DEAL #1 - FIRM.
(Firm or Interruptible)
DEAL #2 - FIRM, AS PRODUCED
TERM (period of delivery): STARTING 0800 HOURS ON FEBRUARY 1, 2002 THROUGH TO
0800 HOURS ON NOVEMBER 1, 2002.
TRANSPORTER(S): TRANSGAS
OTHER TERMS: NONE
This Confirmation is being provided pursuant to the Master Gas Transaction
Agreement (the "Master Agreement") between Westerra 2000 Inc. and AltaGas
Services Inc. and constitutes part of and is subject to all of the terms
and provisions of the Master Agreement.
Please confirm that the terms stated herein accurately reflect the
agreement between you and AltaGas by returning an executed copy of this
Confirmation by facsimile to AltaGas. We would appreciate it if you would
send your fax back to us within one hour after you receive this
Confirmation. In accordance with the terms of the Master Agreement, if you
do not execute and return this Confirmation to us within 2 Business Days of
your receipt, it will be deemed to be correct as sent. In addition, the
[ALTAGAS LOGO]
75
terms of this Transaction are subject to the confidentiality restrictions
as provided for in the Master Agreement. Thank you for your timely
co-operation.
Accepted and agreed effective as of the Effective Time.
ALTAGAS SERVICES INC.
/s/ Xxxxxxx Xxxxxxxx
----------------------------------
Per: XXXXXXX XXXXXXXX
Title: Director, Marketing and Extraction
Date: Jan 29/02
WESTERRA 2000 INC.
/s/ Xxxx Xxxxxxx
----------------------------------
Per: Xxxx Xxxxxxx
Title:
Date: APR 05/02
76
[APPLIED TERRAVISION LETTERHEAD]
October 3, 2001
WESTERRA 2000 INC.
Via Fax 000-0000
ATTENTION: XXXXX XXXXX
Dear Xxxxx,
Thank you for your interest in Applied Terravision's (ATS) Financial
Accounting PC based application WOLFPAC. It is my pleasure to provide you
with the following proposal with respect to the renta1 of this application.
ATS' mission is to provide our customers with the best price performance
solutions to their data processing requirements backed up by the best
service and support in the Industry. Our software is designed with current
technologies to provide users with powerful user-friendly tools to maintain
and access necessary information. We are committed to providing our
customers with the tools they need to better compete in their business.
The advantages of installing WOLFPAC on an IBM compatible personal computer
or network in your office would include the following:
1. FUNCTIONALITY - ATS applications have been developed for the oil and
gas industry and provide financial, regulatory and management
reporting as required by the end users in such firms.
2. WINDOWS COMPATIBLE - All applications run under a Windows environment
allowing switching between itself and other Windows applications.
3. COST - ATS' products are competitively priced as outlined below:
Pricing Summary
INITIAL FEES MONTHLY RENTAL
WOLFPAC Financial Accounting $1,225.00 $310.00
77
PRICING DETAIL
INITIAL FEE MONTHLY RENTAL
----------- --------------
Application Software Concurrent 1 $0.00 **$300.00
Browse 0 $0.00 $0.00
Focus Database Concurrent 1 $1,000.00 $10.00
Server 0 $0.00 $0.00
Carbon Copy $225.00 $0.00
--------- ---------
TOTAL $1,225.00 **$310.00
========= =========
** Applied to clients where Gross Revenues do not exceed $1.5 Million Annually.
None of this amount is applicable towards the purchase price of a license **
PRICES ARE SUBJECT TO 7% GST
The above prices exclude installation, data conversion and training which will
be provided at the hourly rates identified in the current ATS Price Notice. We
recommend that you budget 10-15 hours for training to ensure a strong start on
the application. Estimates for these activities are identified as follows:
WOLFPAC Training $80.00/Hour
Installation normally occurs within five (5) business days but is subject to
availability of ATS personnel.
TERMS AND CONDITIONS
1. Westerra 2000 agrees to provide to ATS with the initial fee of $1,310.75
(GST included) representing Database fees and Carbon Copy upon acceptance
of this Agreement.
2. Westerra 2000 agrees that all ATS invoices are due upon receipt. ATS must
be notified by Westerra 2000 of any disputes of fees invoiced by ATS within
thirty (30) days of the date of the invoice. Invoices that are held for a
period greater than thirty (30) days from the date of the invoices are
deemed to be approved by Westerra 2000. In the event that payment is not
made within ninety (90) days, ATS may terminate this Agreement and
subsequently remove the ATS software from all related Westerra 2000 sites.
3. Westerra 2000 agrees that this Agreement will be reviewed on an annual
basis within thirty (30) days of the anniversary date of the signing of
this Agreement.
4. The fees associated with the software rental and personnel rates are as
identified on the ATS Price Notice prevailing at the time. The current ATS
Price Notice has been attached to this document. Changes to the ATS Price
Notice will be in effect thirty (30) days after written notification of
such change by ATS to Westerra 2000.
5. Either party may terminate this Agreement upon thirty (30) days prior
written notice for whatever reason. In the event of termination, Westerra
2000 will allow access to their premises to ATS staff for the purpose of
removing the ATS application software from all locations.
6. This proposal assumes that Westerra 2000 has existing hardware that meets
the following minimum configuration. Both the configuration of the hardware
and the system resource requirements of the application running at that
point in time will affect performance.
[APPLIED TERRAVISION LOGO]
78
Personal Computer: IBM compatible, Pentium 166 with 64 Meg RAM
100 Megabytes of available hard disk space on
C: Drive Microsoft Windows 95
Printer: HP LaserJet (series IV recommended as minimum for
printing month end reports)
Dial Modem & U.S. Robotics Sportster-14.4
Phone Line
I hope this information is to your satisfaction. Should Westerra 2000 agree
to the above proposal please sign and date both copies of this Agreement in
the space provided below and return the duplicate copy along with a cheque
in the amount of $1310.75 to Applied Terravision Systems Inc. We will then
initiate the implementation upon receipt of this document as agreed to with
Westerra 2000 and ATS.
This proposal will remain in affect for a period of ten (10) business days
from the date of this proposal.
I look forward to our continued discussion on this matter and welcome
Westerra 2000 on board as a valued client. Should you have any further
questions or concerns, kindly contact myself at (000) 000-0000.
Yours truly,
APPLIED TERRAVISION SYSTEMS INC.
/s/ Xxxxxxxx Xxxx
------------------------
Xxxxxxxx Xxxx
Sales Representative
The above Rental Option acknowledged and agreed upon the 4th day of October
2001.
WESTERRA 2000 INC.
Per: /s/ Xxxxx X. Xxxxx
----------------------------------------------
Xxxxx X. Xxxxx, Vice President Land & Exploration
----------------------------------------------
Printed Name & Capacity
[APPLIED TERRAVISION LOGO]
79
SCHEDULE "O"
Tilikum Report
80
Tilikum Inc.
X.X. Xxx 0
Xxxxx Xxxxx, Xxxxxxx X0X 0X0
February 4, 2002
Westerra 2000 Inc.
000 Xxxxxxxxx Xxxxxxxx X.X.
Xxxxxxx, Xxxxxxx X0X 0X0
Attention: Xxxx Xxxxxxx
Re: 2001 RESERVE REPORT
Dear Sir:
Further to your request, Tilikum is pleased to provide you with the subject
report, evaluating Westerra's reserve to December 31, 2001. This report was
based solely on information available in the public domain and proprietary
information which you supplied as necessary to complete the work.
For the information of those to whom you may be supplying copies of this report,
I certify that both myself and Tilikum Inc. are registered with APEGGA and are
authorized to perform Petroleum Engineering. I am a 1973 graduate of the
University of Calgary in Mechanical Engineering, and have been practicing
Petroleum Engineering continuously since 1973. I verify that the work presented
in this report is my own and meets the standards set by APEGGA.
Should you require additional background or information, please call me at (403)
000-0000.
Yours truly,
/s/ Xxxxxxx X. Xxxxxxxx
-----------------------
Tilikum Inc.
Xxxxxxx X. Xxxxxxxx, P. Eng
81
WESTERRA 2000 INC.
RESERVE REPORT
PERIOD ENDING DECEMBER 31, 2001
82
1.0 SUMMARY
Reserves for Westerra 2000 Inc. have been evaluated and are shown in the
following Table. The information shown represents Westerra's 60% working
interest share of remaining recoverable gas and the discounted present
value of that gas. The after tax value is for a fully taxable company and
does not consider any tax pools which may be held by Westerra.
----------------------------------------------------------------------------------------------------------------
Before Tax Present Value After Tax Present Value
WI ------------------------------------------------------------------------
Reserve Category Reserve BT 10% BT 12% BT 15% AT 8% AT 10% AT 12%
Mmscf $000's $000's $000's $000's $000's $000's
----------------------------------------------------------------------------------------------------------------
TOTAL PROVED 4458.3 5,375.1 5019.9 4,573.3 4217.3 3908.0 3643.4
Producing 3,695.5 3,881.3 3,601.4 3,252.2 3,121.6 2,872.5 2,661.2
131/16-23-049-28W3/0 397.9 390.3 361.0 324.2 263.0 240.9 222.0
101/12-24-049-28W3/0 710.8 736.6 675.2 599.9 428.0 387.4 353.6
121/13-24-049-28W3/0 52.7 81.9 79.6 76.3 53.0 51.3 49.8
131/15-24-049-28W3/0 576.8 607.0 567.7 516.3 356.6 331.5 309.3
121/02-25-049-28W3/0 89.2 132.8 128.4 122.3 91.2 87.9 84.9
121/06-25-049-28W3/0 90.7 134.7 130.3 124.2 91.7 88.5 85.6
131/13-25-049-28W3/0 632.4 568.1 516.7 454.9 375.8 336.5 304.5
121/01-26-049-28W3/0 752.6 907.3 836.8 749.8 560.6 510.4 468.6
141/14-15-049-27W3/0 1.0 1.1 1.1 1.1 1.1 1.1 1.1
141/14-15-049-27W3/2 216.2 211.4 196.6 177.8 155.2 143.5 133.4
141/15-15-049-27W3/0 175.2 109.9 108.1 105.4 53.3 52.3 51.4
Non Producing 762.9 1,493.8 1,418.5 1,321.0 1,095.7 1035.5 982.6
1C0/06-09-050-01W4/0 271.5 755.2 738.4 714.6 558.0 545.0 532.7
1C0/08-22-050-02W4/2 491.4 738.5 680.0 606.5 534.8 487.8 447.6
----------------------------------------------------------------------------------------------------------------
TOTAL PROBABLE 414.2 504.3 453.9 393.8 384.8 341.7 306.6
Non Producing 414.2 504.3 453.9 393.8 384.8 341.7 306.6
1C0/06-09-050-01W4/0 52.4 84.4 78.9 71.4 70.6 65.9 61.6
1C0/08-22-050-02W4/2 195.9 183.8 154.7 122.5 146.5 120.7 101.0
1C0/08-22-050-02W4/W 97.8 144.9 133.1 118.2 112.7 103.0 94.7
131/02-14-050-28W3/L 68.1 91.2 87.2 81.7 43.5 41.0 38.8
----------------------------------------------------------------------------------------------------------------
TOTAL PROVED + PROBABLE 4,872.5 5,879.4 5,473.8 4,967.1 4,606.0 4,253.6 3,954.3
Producing 3,695.5 3,881.3 3,601.4 3,252.2 3,121.6 2,872.5 2,661.2
Non Producing 1,177.1 1,998.0 1,872.4 1,714.8 1,484.5 1,381.1 1,293.1
----------------------------------------------------------------------------------------------------------------
GAS STORAGE WELL F/H
Proven -165.2 -167.1 -156.8 -135.3 -132.3 -129.5
Proven + Probable -180.3 -175.8 -169.5 -148.1 -144.2 -140.6
----------------------------------------------------------------------------------------------------------------
Note: Taxes are recalculated for consolidations: after tax column totals will
not balance Other column totals may not add due to rounding differences.
83
One of Westerra's assets is a gas storage well which has some injected gas
remaining in the reservoir. One would expect that this gas would not be
subject to the payment of freehold royalty and mineral tax, and that is
the way in which this asset was evaluated. However; the last entry in the
table shows the incremental reduction in value if these royalties were to
be paid.
84
2.0 LAND SCHEDULE
Westerra owns a 60 percent working interest in the 5 sections of land
shown in green on the following land plat, and described more completely
in the land schedule shown below:
Crown or Working Lessor XXX
Description Portion Ownership Freehold Interest Royalty Burden
-----------------------------------------------------------------------------------------------------
15-49-27W3 All NG - Surface to Basement Freehold 60% 17.5%
23-49-28W3 N PNG - Surface to Basement Freehold 60% 15.0%
S PNG - Surface to Basement Crown 60% Crown
24-49-28W3 NW PNG - to Base Mannville Group Crown 60% Crown 2.25%
NE PNG - Surface to Basement Freehold(1) 60% 15.0%
25-49-28W3 All PNG - Surface to Basement Freehold 60% 12.5%
26-49-28W3 SE PNG - Surface to Basement Freehold 60% $.005/mscf
14-50-28W3 NE PNG - to Base Mannville Crown 60% Crown
27-49-01W4 NW PNG - Surface to Basement Freehold 60% 15.0%
09-50-01W4 Well 6-9(2) Sparky LPG Storage Freehold 60% 15.0%
SE PNG - Surface to Basement Crown 60% Crown
22-50-02W4 W NG - Colony Crown 60% Crown
Notes: 1. Freehold interest held by Westerra
2. Interest limited to excess injected volume.
At Westerra's request, the economic evaluation for 15-24-49-28W3 has been
run with a freehold royalty of 15%, and does not reflect Westerra's
ownership of the freehold rights.
The gas storage well in 6-9-50-1W4 has been evaluated as though there were
neither freehold royalty nor mineral tax. There is a small possibility
that royalty will be payable on production from this well, and the
difference in value is shown on the reserve Table in Section 1.0 of this
report.
85
WESTERRA 2000 INC. - LAND AND XXXXX OF INTEREST
[WESTERRA 2000 INC. - LAND AND XXXXX OF INTEREST MAP GRAPHIC]
86
3.0 PRODUCTION FORECASTS AND RESERVES
3.1 Multi Well Production Model
A spreadsheet production forecasting model was constructed to
predict the performance from multiple xxxxx producing from the same
reservoir. This model was a tank deliverability type governed by the
following parameters:
- Reservoir pressure was determined from the material balance
for each reservoir.
- The Cullender and Xxxxx single phase pressure drop formula was
used to determine flowing and static pressure drops in the
well bore tubulars.
The data was calibrated to performance by first calculating
the static (no flow) pressure drop. This was added to the
casing pressure to determine the reservoir flowing pressure.
The flowing pressure drop was then calculated and subtracted
from the flowing reservoir pressure to determine the flowing
tubing pressure. The tubing diameter was adjusted until the
calculated and measured flowing tubing pressures were the
same.
For all xxxxx the calculated tubing diameter was similar to
that installed, except for the need to have reduced tubing
diameters for xxxxx producing water. The results of this
calibration are shown on tabular reports.
- The Forscheimer back pressure equation (AOF) was used to
determine the well production rate
Q = c (Pr[to the power of 2]- Pf[to the power
of 2])[to the power of n]
The constant `c' in this equation was calibrated to data
measured on December 17, 2001. For 00-00-00-00 there was no
data to formulate a calibration, so the parameters were set to
deliver approximately 355 mscf/d. On production test, this
well delivered 530 mscf/d through large tubing.
The `c' value was then degraded at 40% per annum for xxxxx
producing water (13-24, 15-24, 2-25, 6-25) to reflect earlier
than normal loss of deliverability caused by increased
pressure drop in the tubing. The `c' value for the remaining
xxxxx was also degraded, but at a lesser rate of 6% per annum
to reflect normal loss in deliverability over time and to
reduce the calculated ultimate recovery from 90% to 80% as a
more realistic value for these reservoirs.
- Pressure drop in the surface gathering system was estimated to
be 3 psi/mile as the crow flies.
87
- Minimum suction pressure was set to 25 psi for the booster
compressor and 30 psi for the sales compressor. The minimum
reservoir pressure was set to 50 psi. Xxxxx were produced
until the rate fell below a predetermined economic limit of 12
mscf/d inflated at 0.1 percent per month. This well economic
limit was intentionally set slightly below the true economic
limit so that no reserves would be lost in the transition
between reservoir engineering and economic evaluation.
- With well 00-00-00-00 flowing through the booster compressor,
its deliverability is unaffected by production from the other
xxxxx. Accordingly, its production forecast was predicted
using the following calculation scheme as a single well with a
target rate of 550 mscf/d. Then the process was repeated for
the other xxxxx with the target production reduced by the
amount of gas produced from 15-15.
The solution for the flow rate for all xxxxx involved an iterative
calculation described in the following paragraphs.
1. Determine the Reservoir Pressure
Sum the cumulative production to date and calculate the
reservoir pressure from material balance.
2. Determine the Reservoir Flowing Pressure
Estimate the flow rate and calculate the flowing tubing
pressure as the minimum compressor suction pressure plus the
gathering system pressure drop. Use Cullender & Xxxxx to
determine the reservoir flowing pressure. Calculate the flow
rate from the AOF equation. Repeat the process until the
estimated flow rate is the same as that calculated.
3. Determine the Plant Suction Pressure
Sum the individual well production rates and compare to the
target production. If the combined well production is less
than or equal to the target rate, the estimated plant suction
pressure is correct and the month's production for each well
is determined. If not, guess a new plant suction pressure and
repeat steps 2 and 3 until the calculated and estimated plant
suction pressure are the same.
4. Record Data
Record rates and pressures, and update cumulative production.
Repeat steps 1 through 4 for each month until all xxxxx reach
their economic limit or until all reservoirs reach their
abandonment pressure.
3.2 Township 49-27W3
There are two xxxxx producing from three horizons in Section 15. The
well 14-15 is dually completed for Xxxxxxxx and Lloydminster
production and the well 15-15 produces from the Sparky. Gas from
15-15 is presently compressed in a small leased
88
booster unit located at 14-15-49-27W3. This gas is then commingled
with gas from 14-15 and flowed to the main sales compressor located
at 2-25-49-28W3. This sales compressor is owned and operated by Alta
Gas and is used on a third party processing basis. In the future,
the booster compressor may be moved to 2-25-48-28W4 where the main
sales gas compressor is located.
The original gas in place for the Lloydminster zone was calculated
volumetrically using a well bore pay interval of 6.6 feet and an
areal extent of 160 acres. While it is felt that the regional extent
of this reservoir may be greater than 160 acres, the well has
recently begun to produce a large amount of water. The evaluation
assumed the well would continue to produce for a few more months
before being suspended, making reserve calculations moot.
The Xxxxxxxx formation has produced 500 mmscf of gas to date. The
material balance is well defined and shows that the original gas in
place is 1.55 bcf.
The two xxxxx in the Sparky formation, 00-00-00-00 and 9-22-49-27,
produced until 1985 and have remained inactive since that time.
Westerra recently completed the well 15-15-49-27W3 to produce from
this same reservoir. On completion, the measured reservoir pressure
was 130 psi. Using this pressure and an estimate for the original
pressure based on regional information, the original gas in place
was estimated to be 2.2 bcf. An error in the estimated original
pressure will have a small impact on the gas in place calculation
because nearly 3/4 of the reservoir has been depleted.
The production forecast for the two horizons producing from 14-15
was forecast in conjunction with other xxxxx producing into the
sales compressor using the Production Model. Thus the impact of one
well on another was properly considered. The well 15-15 was also
forecast using the Production Model; but as a single well.
The ultimate remaining recovery from 14-15 and 15-15 was 372 mmscf
(57% recovery) and 337 mmscf (90% recovery) respectively. The lower
recovery from 14-15 is caused by low productivity.
3.3 Township 49-28W3
All xxxxx on this land produce from the Colony formation, and were
used by the previous owner to supply gas to the City of
Lloydminster. Production rates were low and very erratic, making a
forecast from previous production impossible.
Fortunately the reservoir ceased production in 1996, and pressures
have remained unchanged since 1998. Thus a material balance
calculation is accurately able to predict the original gas in place
of 17.7 bcf. This reservoir comprises approximately 4 sands which
are present but not perforated in all xxxxx. As productivity falls,
it may be possible to supplement the rates with additional
perforating. This upside has not been considered in the evaluation.
Production from eight xxxxx was forecast in the manner described in
Section 3.0 above. From this information, it was determined that the
production rate through the sales compressor could be maintained at
2.5 mmscf/d for two to three years. However;
89
Westerra wished to take a more conservative approach in estimating
the value and longer term deliverability. For this reason, the
target rate was set to decline from 2.5 mmscf/d at 10 percent per
annum until the minimum plant suction pressure was reached.
Ultimate recovery from the Colony gas is forecast to be 13.9 bcf or
78.8% of the original gas in place. Against a cumulative production
to date of 8.4 bcf, this leaves 5.5 bcf remaining.
Township 49-28 also has potential for additional reserves which will
be confirmed with future drilling and testing. Oil in the McLaren,
Sparky and General Petroleum can be seen on well logs. A recent well
in an adjacent section. 00-00-00-00 shows deep gas in the
Lloydminster and Xxxxxxxx formations. Westerra's land is
structurally higher than the 13-19 well; however, Westerra's xxxxx
were not drilled deep enough to penetrate these formations.
3.4 Township 50-28W3
Westerra has an interest in a Colony gas well which has watered out
and is no longer capable of producing in paying quantities. However;
the owner of the well 131/02-14-050-28W3 is in the process of
completing its well for Lloydminster production. This transaction
will leave Westerra with 60% of a pooled 25% interest in the
production.
The terms of the pooling have been negotiated. Westerra and its
partner will pay $6000 to equalize into the well bore. The well
owner will pay for the recompletions, tie-in and compression and
will recover its cost through a processing and gathering fee. It is
estimated that this fee will be equivalent in value to that being
charged by Alta Gas for xxxxx it operates on behalf of Westerra.
The Lloydminster has 5 feet of net pay with 31% porosity. It is
found in xxxxx 15-11 and 3-11, demonstrating some areal extent. For
the purpose of this evaluation, the drainage area has been assumed
to be 320 acres with 70% recovery. It is believed that time will
prove the reserves to be in excess of the 460 mmscf calculated
volumetrically.
3.5 Township 49-01W4
No reserves have been assigned to Section 27.
3.6 Township 50-01W4
Westerra has no interest in the mineral rights in this Township,
however, it does have the right to produce gas from the well
C0/06-09-050-01W4 providing the cumulative production does not
exceed the cumulative injection. This means that some 800 mmscf
could be produced from this well if it were to have sufficient
deliverability.
90
The original gas in place was determined based on pressure
measurements taken in the 1950's prior to use of the well for gas
storage. The pressures show a uniform depletion with no sign of an
active aquifer or pressure support from other hydrocarbons. At this
time the original gas in place appeared to be 1.65 bcf.
In more recent years, there appears to be a loss of injected gas, as
evidenced by a reduction in the reservoir pressure for a given net
gas production. This data has not been shown on the material balance
plot because it is confusing, but two data points are shown for 1
year and 6 years following the well's suspension. To predict future
recovery from this reservoir, it is assumed that the P/Z plot is
entered at today's pressure and the reservoir depleted to 20 psi to
yield 480 mmscf of remaining proven reserve.
To estimate the proven plus probable recovery, one looks to the
difference between the cumulative net injection of 0.81 bcf and the
reservoir volume of 1.65 bcf to yield a potential 2.4 bcf of gas in
place. This assumption would imply that the lost gas displaced some
other product, say oil, and remains in the reservoir or was produced
from high GOR oil xxxxx. It is assumed that some of this lost gas
remains in the reservoir, but its recharge rate will be low. Thus
proven plus probable reserves are estimated to be 600 mmscf, and the
decline will switch from exponential used to asses proven reserves
to hyperbolic (n=0.5) for the proven plus probable assessment.
In 1994, NUL conducted a deliverability study for 6-9 based on
performance. It concluded that the well could deliver 6400 mscf/d
against a 178 psi flow line pressure. At that time the reservoir
pressure was 263 psi. Adjusting this information to the current
reservoir pressure, 6-8 has a deliverability of 3800 mscf/d against
a flow line pressure of 25 psi. The production forecast assumes the
well will be produced at only 1000 mscf/d for 8 or 9 months and then
declined to capture the remaining reserve.
3.7 Township 50-02W4
The well C0/08-22-050-28W4/2 is completed for Colony gas production
but has not produced since 1986. Pressures for this well have been
increasing over time, but the reserves estimate is based on those
measured pressures with the longest shut in time. These are shown as
purple diamonds on the P/Z plot. The proven remaining reserve
estimate of 825 mmscf is based on an average between the pressures.
The proved plus probable remaining reserve estimate uses the most
recent and highest pressure point to predict remaining reserves of
1.165 bcf.
The Colony zone was flow tested in 1994 and produced 2225 mscf/d at
a well head flowing pressure of 152 psi. It is anticipated that
initially this well will produce at 500 mscf/d.
The well also has 4 feet of Waseca gas pay which would result in
reserves of 668 mmscf based on 70% recovery from 640 acres. These
reserves will commence production in October 2002 when the Waseca
will be completed and the well equipped for dual zone production. It
is forecast that the Waseca formation in 8-22 will commence
production at 400 mscf/d. These reserves are considered probable
according to strict application of the rules, the quality of the
reserve is high because of
91
good cross over on the well logs and demonstrated production from a
well in close proximity.
This same zone is present and structurally lower in adjacent xxxxx
16-16, 10-22 and 11-23. The 16-16 well is operated by CNRL and
recently commenced production at operating day rates in excess of
400 mscf/d.
92
4.0 ECONOMIC EVALUATION
4.1 General Information
The economics were evaluated using Energy Navigator software. This
software has been created in co-operation with XxXxxxxx'x and
Associates and uses XxXxxxxx'x economic evaluation model.
4.2 Price
The base price forecast is that of the Alberta Treasury Branch,
dated October 1, 2001. From this price schedule, the AECO C Hub Spot
price less $0.24/mscf transportation was used for xxxxx producing in
Alberta. The Saskatchewan Energy Plant Gate price less $0.14/mscf
transportation was used for xxxxx producing in Saskatchewan. Beyond
2020 ATB recommends prices be increased by 2 percent per year.
Exceptions to the pricing occur in 2002, when the base price
forecast was reduced to $3.00/mscf to reflect a fixed price contract
to which Westerra has committed. For the gas storage well 6-9-50-1,
there is no transportation allowance against the base price.
Natural Gas Price, $/mscf
Year Alberta Saskatchewan Year Alberta Saskatchewan
-------------------------------------------------------------
2001 $5.30 $5.00 2011 $4.10 $4.05
2002 $3.00 $3.00 2012 $4.20 $4.10
2003 $4.00 $4.00 2013 $4.30 $4.15
2004 $4.00 $4.00 2014 $4.40 $4.20
2005 $4.00 $4.00 2015 $4.50 $4.25
2006 $4.00 $4.00 2016 $4.60 $4.30
2007 $4.00 $4.00 2017 $4.70 $4.35
2008 $4.00 $4.00 2018 $4.80 $4.40
2009 $4.00 $4.00 2019 $4.90 $4.45
2010 $4.00 $4.00 2020 $5.00 $4.50
4.3 Operating Cost
The ATB price model operates under a capital and operating inflation
rate of 3 percent annually. Because the operating cost is inflated
at a greater rate than the price, there is a real price erosion.
In Alberta, the gas cost allowance for third party processing is
equal to the third party processing fee. For xxxxx producing to the
Alta Gas main sales compressor, this amounts to $0.62/mscf for
compression and gathering. For the 8-22-50-2 well, this is
$0.30/mscf for compression and gathering. In Saskatchewan, gas cost
allowance is calculated as a flat $0.28/mscf.
93
Operating cost for all xxxxx is shown in the Table below.
Cost Type Amount CGA Description
Fixed $450/month No Alta Gas contract operating, dual completion 1/2 per zone
$300/month No Other costs including lease rentals, taxes, repairs, etc.
$3500/month No Compressor rental (xxxxx 00-00-00-00, 6-9-50-1)
5% shrinkage for fuel
Variable $0.40/mscf Yes Compression charge from Alta Gas
$0.15/mscf Yes Gathering charge from Alta Gas
$0.07/mscf Yes Electricity charge from Alta Gas, 1% shrinkage
Variable $0.20/mscf Yes Compression (well 8-22-50-2)
$0.10/mscf yes Gathering (well 8-22-50-2)
4.4 Capital Cost
Capital cost for developing reserves is shown in the following Table
Well Date Amount Description
1C0/06-09-050-01W4/0 Jun 2002 $80,000 Meter run, miscellaneous piping
1C0/08-22-050-02W4/2 Oct 2002 $40,000 Flow line, shared 50% with Waseca completion
1C0/08-22-050-02W4/W Oct 2002 $40,000 Flow line, shared 50% with Colony completion
Oct 2002 $40,000 Complete Waseca for production (pooled 25%)
131/02-14-050-28W3/L Apr 2002 $24,000 Equalize into well bore (pooled 25%)
94
ECONOMIC EVALUATION REPORTS
SUMMARY OF PROVED RESERVES
95
TABLE 2
PAGE 1
WESTERRA 2000
ESCALATING PRICES AS OF JANUARY 1, 2002
TOTAL PROVED RESERVES
WESTERRA 2000
COMPANY GROSS INTEREST RESERVES NET PRESENT VALUE (M$)
------------------------------- ---------------------------
COMPANY RES. GAS OIL NGL SULPHUR
AREA AND PROPERTY INTEREST % ZONES CAT MMCF MBBL MBBL MLT @ 10.0% @ 12.0% @ 15.0%
---------------------------------------------------------------------------------------------------------------------------------
COLONY GAS POOL
131/16-23-049-28W3/0 W=60.000 Colony P-DP 397.9 - - - 390.3 361.0 324.2
101/12-24-049-28W3/0 W=60.000 Colony P-DP 710.8 - - - 736.6 675.2 599.9
121/13-24-049-28W3/0 W=60.000 Colony P-DP 52.7 - - - 81.9 79.6 76.3
131/15-24-049-28W3/0 W=60.000 Colony P-DP 576.8 - - - 607.0 567.7 516.3
121/02-25-049-28W3/0 W=60.000 Colony P-DP 89.2 - - - 132.8 128.4 122.3
121/06-25-049-28W3/0 W=60.000 Colony P-DP 90.7 - - - 134.7 130.3 124.2
131/13-25-049-28W3/0 W=60.000 Colony P-DP 632.4 - - - 568.1 516.7 454.9
121/01-26-049-28W3/0 W=60.000 Colony P-DP 752.6 - - - 907.3 836.8 749.8
SUBTOTAL COLONY GAS POOL 3,303.0 - - - 3,558.9 3,295.6 2,967.9
SINGLE WELL POOLS
1C0/06-09-050-01W4/0 W=60.000 Sparky Gas P-NP 271.5 - - - 755.2 738.4 714.6
1C0/08-22-050-02W4/2 W=60.000 Colony P-NP 491.4 - - - 738.5 680.0 606.5
141/14-15-049-27W3/0 W=60.000 Lloydminster P-DP 1.0 - - - 1.1 1.1 1.1
141/14-15-049-27W3/2 W=60.000 Xxxxxxxx P-DP 216.2 - - - 211.4 196.6 177.8
141/15-15-049-27W3/3 W=60.000 Sparky P-DP 175.2 - - - 109.9 108.1 105.4
SUBTOTAL SINGLE WELL POOLS 1,155.4 - - - 1,816.2 1,724.2 1,605.4
---------------------------------------------------------------------------------------------------------------------------------
TOTAL 4,458.3 - - - 5,375.1 5,019.9 4,573.3
RESERVE CATEGORY ABBREVIATIONS
---------------------------------------------------------------------------------------------------------------------------
TP Total Proved P-DP Proved Producing P-NP Proved Non Producing
TPP Total Proved and Probable P+P-DP Proved + Prob. Producing P+P-NP Proved + Prob. Non Producing
TPPP Total Proved + Prob. + Poss. PPP-DP Proved + Prob. + Poss. Producing PPP-NP Proved + Prob. + Poss. Non Producin
TPA Total Probable Additional PA-DP Prob. Additional Producing PA-NP Prob. Additional Non Producing
PSA Total Possible Additional PS-XX Xxxx. Additional Producing PS-XX Xxxx. Additional Non Producing
NRA No Reserves Assigned
P-UD Proved Undeveloped
P+P-UD Proved + Prob. Undeveloped
PPP-UD Proved + Prob. + Poss. Undeveloped
PA-UD Prob. Additional Undeveloped
PS-UD Poss. Additional Undeveloped
96
SUMMARY
Westerra 2000 [BAR CHART]
Westerra 2000
Total Proved
As Of Date January 1, 2002
Prediction Date
Alberta
UWI
Net No. Xxxxx 6.00
Average WI 60%
Average Royalty 13%
Price Schedule ATB 2001 Q4
Price File Base
Econ. Limit Enabled
GCA Applied No
BOE Ratio 10:1
COMPANY WI SHARE NET PRESENT WORTH VALUE BEFORE TAX (M$) PRICE
------------------ --------------------------------------------------- ------
REMAINING GROSS NET 8.0% 10.0% 12.0% 15.0% 20.0% YEAR 1
--------- ----- --- ---- ----- ----- ----- ----- ------
Oil (mbbl) - - - - - - - - -
Gas(mmcf) (10:1) 7,430.5 4,458.3 3,863.0 5,789.7 5,375.1 5,019.9 4,573.3 3,994.3 2.86
NGL(mbbl) (1:1) - - - - - - - - -
C2 (mbbl) (1:1) - - - - - - - - -
C3 (mbbl) (1:1) - - - - - - - - -
C4 (mbbl) (1:1) - - - - - - - - -
C5+ (mbbl) (1:1) - - - - - - - - -
Sulphur (mlt) (1:1) - - - - - - - - -
TOTALS (MBOE) 743.1 445.8 386.3 5,789.7 5,375.1 5,019.9 4,573.3 3,994.3
AFTER TAX 4,217.3 3,908.0 3,643.8 3,312.6 2,885.0
CAPITAL COSTS (M$) CASH FLOW (M$) ECONOMIC INDICATORS
--------------------------------------------------------------------------------------------------------------------------
GROSS NET GROSS NET BEFORE TAX AFTER TAX
----- --- ----- --- ---------- ---------
CEE - - Revenue 27,886.5 16,731.9 Rate of Return (%) - -
CDE 82.4 49.4 Royalties 5,308.5 3,185.1 Payout (yrs) 0.0 0.0
CCA 41.2 24.7 Op. Costs 7,487.9 4,492.8 P/I - 0.0% Discount 114.3 84.2
COGPE - - Capital 123.6 74.2 P/I - 12.0% Discount 71.6 -
Abandonment - - ARTC - - Op. Cost ($/boe) 6.0 -
Cap. Cost ($/boe) 0.1 -
-----------------------------------------------------------------------
Total 123.6 74.2 Before Tax 14,966.4 8,979.9
ANNUAL CASH FLOW
GROSS ROYALTY OPERATING CAPITAL BTAX NET BTAX TAX ATAX NET ATAX
WELL RATE PRICE REVENUE & TAXES COST COST ARTC REVENUE NET CUM PAID REVENUE NET CUM
YEAR COUNT MCF/D $/MCF M$ M$ M$ M$ M$ M$ M$ M$ M$ M$
----------------------------------------------------------------------------------------------------------------------------
2002 6.45 1,761.5 2.88 1,851.3 404.5 438.7 74.2 -- 880.8 880.8 264.3 616.5 616.5
2003 7.20 1,874.4 3.81 2,603.9 537.0 454.9 -- -- 1,549.1 2,429.9 433.6 1,115.5 1,732.0
2004 7.20 1,390.6 3.76 1,915.0 458.9 433.7 -- -- 965.7 3,395.6 267.4 698.3 2,430.3
2005 6.10 1,114.6 3.83 1,559.2 389.7 327.7 -- -- 793.1 4,188.6 219.6 573.4 3,003.8
2006 5.85 919.5 3.83 1,284.5 308.5 282.2 -- -- 653.7 4,842.4 178.5 475.2 3,479.0
2007 5.20 765.0 3.82 1,067.2 242.8 244.8 -- -- 546.4 5,388.8 146.3 400.1 3,879.1
2008 4.20 636.7 3.82 889.3 187.6 208.3 -- -- 465.7 5,854.5 121.4 344.3 4,223.4
2009 4.20 538.3 3.81 748.8 140.3 187.9 -- -- 397.2 6,251.7 99.9 297.3 4,520.7
2010 4.20 451.6 3.81 627.3 100.1 169.8 -- -- 337.8 6,589.5 81.6 256.2 4,776.9
2011 4.20 378.7 3.86 533.0 72.8 154.3 -- -- 289.4 6,878.8 67.8 221.6 4,998.5
REM. 2.56 107.8 4.22 3,652.4 342.9 1,590.6 -- -- 1,600.7 8,479.6 356.9 1,243.9 6,242.4
----------------------------------------------------------------------------------------------------------------------------
TOTAL 381.3 3.75 16,731.9 3,185.1 4,492.8 74.2 -- 8,479.6 2,237.2 6,242.4
97
Table B
Page 1
WESTERRA 2000
ESCALATING PRICES AS OF JANUARY 1, 2002
TOTAL PROVED RESERVES
WESTERRA 2000
PRODUCTION RESOURCE ADJUSTED RESOURCE RESOURCE RESOURCE COGPE, CDE,
SALES ROYALTY NPI OPERATING CCA RESOURCE ALLOWANCE ROYALTY ROYALTY CEE, FEDE
REVENUE PAID PAYMENTS EXPENSE EXPENSE PROFITS AT 25% INCOME EXPENSE EXPENSE
YEAR M$ M$ M$ M$ M$ M$ M$ M$ M$ M$
-----------------------------------------------------------------------------------------------------------------
2002 1,851.3 - - 438.7 3.1 1,409.5 352.4 - 144.0 11.8
2003 2,603.9 - - 454.9 5.2 2,143.8 535.9 - 161.3 10.6
2004 1,915.0 - - 433.7 3.9 1,477.4 369.3 - 139.2 7.6
2005 1,559.2 - - 327.7 3.0 1,228.5 307.1 - 114.6 5.5
2006 1,284.5 - - 282.2 2.4 999.9 250.0 - 95.3 4.2
2007 1,067.2 - - 244.8 1.8 820.6 205.2 - 79.9 2.9
2008 889.3 - - 208.3 1.3 679.7 169.9 - 66.0 2.0
2009 748.8 - - 187.9 1.0 559.9 140.0 - 55.0 1.4
2010 627.3 - - 169.8 0.8 456.7 114.2 - 45.0 1.0
2011 533.0 - - 154.3 0.6 378.2 94.6 - 37.0 0.7
2012 458.4 - - 142.3 0.4 315.7 78.9 - 30.8 0.5
2013 397.9 - - 132.9 0.3 264.7 66.2 - 26.1 0.3
2014 348.9 - - 124.3 0.2 224.3 56.1 - 22.4 0.2
2015 304.1 - - 110.8 0.2 193.2 48.3 - 18.8 0.2
2016 277.0 - - 107.6 0.1 169.2 42.3 - 17.3 0.1
Rem. 1,866.1 - - 972.7 0.4 893.1 223.3 - 121.5 0.3
TOTAL 16,731.9 - - 4,492.8 24.7 12,214.4 3,053.6 - 1,174.2 49.4
-----------------------------------------------------------------------------------------------------------------
LOAN TAX LOSS TAXABLE
TOTAL OTHER TOTAL OTHER INTEREST CARRY RESOURCE
REVENUES EXPENSES PAID FORWARD INCOME
YEAR M$ M$ M$ M$ M$
-------------------------------------------------------------
2002 - - - - 901.3
2003 - - - - 1,435.9
2004 - - - - 961.2
2005 - - - - 801.4
2006 - - - - 650.5
2007 - - - - 532.7
2008 - - - - 441.7
2009 - - - - 363.5
2010 - - - - 296.6
2011 - - - - 246.0
2012 - - - - 205.5
2013 - - - - 172.1
2014 - - - - 145.6
2015 - - - - 125.9
2016 - - - - 109.5
Rem. - - - - 548.1
TOTAL - - - - 7,937.2
-------------------------------------------------------------
CAPITAL COST ALLOWANCE CANADIAN OIL & GAS PROPERTY EXPENSE CANADIAN DEVELOPMENT EXPENSE
--------------------------- ----------------------------------- -----------------------------------
INITIAL EXPENSE INITIAL DEPN. EXPENSE INITIAL DEPN. EXPENSE
BALANCE ADDITIONS CLAIM BALANCE ADDITIONS RATE CLAIM BALANCE ADDITIONS RATE CLAIM
YEAR M$ M$ M$ M$ M$ % M$ M$ M$ % M$
-------------------------------------------------------------------------------------------------------------
2002 6.0 24.7 3.1 - - 30.0 - 11.4 49.4 90.0 11.8
2003 42.0 - 5.2 - - 30.0 - 72.4 - 90.0 10.6
2004 32.0 - 3.9 - - 30.0 - 51.9 - 90.0 7.6
2005 24.4 - 3.0 - - 30.0 - 37.2 - 90.0 5.5
2006 9.6 - 2.4 - - 20.0 - 13.9 - 60.0 4.2
2007 7.2 - 1.8 - - 20.0 - 9.7 - 60.0 2.9
2008 5.4 - 1.3 - - 20.0 - 6.8 - 60.0 2.0
2009 4.0 - 1.0 - - 20.0 - 4.8 - 60.0 1.4
2010 3.0 - 0.8 - - 20.0 - 3.3 - 60.0 1.0
2011 2.3 - 0.6 - - 20.0 - 2.3 - 60.0 0.7
2012 1.7 - 0.4 - - 20.0 - 1.6 - 60.0 0.5
2013 1.3 - 0.3 - - 20.0 - 1.1 - 60.0 0.3
2014 1.0 - 0.2 - - 20.0 - 0.8 - 60.0 0.2
2015 0.7 - 0.2 - - 20.0 - 0.6 - 60.0 0.2
2016 0.5 - 0.1 - - 20.0 - 0.4 - 60.0 0.1
Rem. 1.5 - 0.4 - - 15.3 - 0.9 - 45.9 0.3
TOTAL 142.5 24.7 24.7 - - 18.8 - 219.0 49.4 56.3 49.4
-------------------------------------------------------------------------------------------------------------
FOREIGN EXPL & DEV EXPENSE CEE
--------------------------- -------
INITIAL ALLOWABLE EXPENSE EXPENSE TOTAL
BALANCE DEPN RT CLAIM CLAIM CLAIMS
YEAR M$ % M$ M$ M$
-----------------------------------------------------
2002 - 300.0 - - 14.9
2003 - 300.0 - - 15.8
2004 - 300.0 - - 11.6
2005 - 300.0 - - 8.5
2006 - 200.0 - - 6.5
2007 - 200.0 - - 4.7
2008 - 200.0 - - 3.4
2009 - 200.0 - - 2.4
2010 - 200.0 - - 1.8
2011 - 200.0 - - 1.3
2012 - 200.0 - - 0.9
2013 - 200.0 - - 0.7
2014 - 200.0 - - 0.5
2015 - 200.0 - - 0.3
2016 - 200.0 - - 0.3
Rem. - 152.9 - - 0.6
TOTAL - 187.5 - - 74.1
-----------------------------------------------------
FEDERAL PROVINCIAL
----------------------------- ---------------------------------------
ROYALTY REVENUES TOTAL SASK.
TAX CR. XXX. & TAX TAXABLE TAX BEFORE INCOME TAX CAPITAL
TAX RATE PAYABLE MIN. TAX DEDUCTIONS NET INCOME TAX RATE PAYABLE INC. TAX PAID SURCHARGE
YEAR % M$ M$ M$ M$ % M$ M$ M$ M$
------------------------------------------------------------------------------------------------------------------
2002 52.24 235.4 260.5 - 250.8 11.50 28.8 880.8 264.3 -
2003 52.24 375.0 375.7 - 585.8 10.00 58.6 1,549.1 433.6 -
2004 52.24 251.1 319.8 - 203.8 8.00 16.3 965.7 267.4 -
2005 52.24 209.3 275.2 - 129.1 8.00 10.3 793.1 219.6 -
2006 52.24 169.9 213.2 - 107.6 8.00 8.6 653.7 178.5 -
2007 52.24 139.1 162.8 - 89.8 8.00 7.2 546.4 146.3 -
2008 52.24 115.4 121.6 - 74.7 8.00 6.0 465.7 121.4 -
2009 52.24 94.9 85.3 - 62.1 8.00 5.0 397.2 99.9 -
2010 52.24 77.5 55.1 - 51.4 8.00 4.1 337.8 81.6 -
2011 52.24 64.2 35.8 - 43.8 8.00 3.5 289.4 67.8 -
2012 52.24 53.7 25.8 - 37.2 8.00 3.0 245.2 56.6 -
2013 52.24 44.9 18.7 - 31.4 8.00 2.5 207.7 47.5 -
2014 52.24 38.0 13.5 - 26.5 8.00 2.1 177.7 40.2 -
2015 52.24 32.9 10.1 - 22.1 8.00 1.8 154.8 34.7 -
2016 52.24 28.6 8.2 - 18.4 8.00 1.5 135.0 30.1 -
Rem. 38.41 142.9 29.6 - 62.4 8.00 5.0 680.3 147.9 -
TOTAL 44.89 2,072.9 2,010.9 - 1,796.8 9.14 164.2 8,479.6 2,237.2 -
------------------------------------------------------------------------------------------------------------------
LOAN CASH FLOW AFTER TAXES
------------------- -------------------------
PRINCIPAL INTEREST NPV @
PAYMENTS PAID ANNUAL CUM 12.0%
YEAR M$ M$ M$ M$ M$
-------------------------------------------------------
2002 - - 616.5 616.5 582.6
2003 - - 1,115.5 1,732.0 941.1
2004 - - 698.3 2,430.3 526.0
2005 - - 573.4 3,003.8 385.7
2006 - - 475.2 3,479.0 285.4
2007 - - 400.1 3,879.1 214.5
2008 - - 344.3 4,223.4 164.8
2009 - - 297.3 4,520.7 127.1
2010 - - 256.2 4,776.9 97.8
2011 - - 221.6 4,998.5 75.5
2012 - - 188.5 5,187.1 57.4
2013 - - 160.3 5,347.3 43.5
2014 - - 137.5 5,484.9 33.4
2015 - - 120.2 5,605.0 26.0
2016 - - 105.0 5,710.0 20.3
Rem. - - 532.4 6,242.4 62.7
TOTAL - - 6,242.4 6,242.4 3,643.8
-------------------------------------------------------
PRESENT WORTH VALUES - M$
---------------------------------------------------
8.0% 10.0% 12.0% 15.0% 20.0%
-------------------------------------------------------------------------------
Before Income Taxes 5,789.7 5,375.1 5,019.9 4,573.3 3,994.3
After Income Taxes 4,217.3 3,908.0 3,643.8 3,312.6 2,885.0
98
PAGE 1
WESTERRA 2000
ESCALATING PRICES AS OF JANUARY 1, 2002
TOTAL PROVED RESERVES
WESTERRA 2000
PRICE FILE: BASE
COLONY GAS POOL
-----------------------------------------------------------------------------------------------------------------------------------
Jan 2002 Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Oil Volume mbbl - - - - - - - - - - - -
Gas Volume mmcf 33.2 29.7 33.1 31.5 32.4 31.4 32.9 33.2 32.3 33.6 32.6 33.8
NGL Volume mbbl - - - - - - - - - - - -
Oil Rev M$ - - - - - - - - - - - -
Gas Rev M$ 94.9 84.8 94.7 90.0 92.6 89.7 94.2 95.0 92.5 96.1 93.3 96.7
NGL Rev M$ - - - - - - - - - - - -
ARTC M$ - - - - - - - - - - - -
Total Rev M$ 94.9 84.8 94.7 90.0 92.6 89.7 94.2 95.0 92.5 96.1 93.3 96.7
Crown Xxx M$ 6.8 5.8 5.1 4.8 5.0 4.8 5.1 5.1 4.9 5.2 5.0 5.3
XX Xxx M$ 5.8 5.2 7.5 7.1 7.3 7.1 7.5 7.5 7.3 7.6 7.4 7.6
Indian Xxx M$ - - - - - - - - - - - -
Override M$ 0.6 0.5 0.5 0.5 0.5 0.4 0.5 0.5 0.5 0.5 0.5 0.5
Mineral Tax M$ 11.4 9.4 11.2 10.4 10.7 10.2 11.1 11.2 10.8 11.5 11.0 11.6
Net Profit M$ - - - - - - - - - - - -
Op. Costs M$ 24.4 22.2 24.8 23.8 24.4 23.7 24.7 24.9 24.4 25.2 24.5 25.3
Total Exp M$ 49.0 43.0 49.1 46.7 47.9 46.2 48.9 49.3 47.9 50.0 48.4 50.3
Op. Income M$ 45.8 41.8 45.6 43.3 44.7 43.4 45.4 45.7 44.6 46.1 45.0 46.4
CEE M$ - - - - - - - - - - - -
CDE M$ - - - - - - - - - - - -
CCA M$ - - - - - - - - - - - -
COGPE M$ - - - - - - - - - - - -
Abandon M$ - - - - - - - - - - - -
Total Capital M$ - - - - - - - - - - - -
COLONY GAS POOL
----------------------------------------------------------------------------------------------------------------------------------
Jan 2003 Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Oil Volume mbbl - - - - - - - - - - - -
Gas Volume mmcf 33.9 30.6 33.9 32.8 33.8 32.7 33.7 33.6 32.4 33.3 32.1 33.0
NGL Volume mbbl - - - - - - - - - - - -
Oil Rev M$ - - - - - - - - - - - -
Gas Rev M$ 127.1 114.9 127.2 123.1 127.0 122.7 126.5 126.1 121.6 125.2 120.6 124.1
NGL Rev M$ - - - - - - - - - - - -
ARTC M$ - - - - - - - - - - - -
Total Rev M$ 127.1 114.9 127.2 123.1 127.0 122.7 126.5 126.1 121.6 125.2 120.6 124.1
Crown Xxx M$ 7.4 6.4 7.4 7.1 7.4 7.1 7.3 7.3 7.0 7.3 7.0 7.2
XX Xxx M$ 10.0 9.1 10.0 9.7 10.0 9.7 10.0 9.9 9.6 9.9 9.5 9.8
Indian Xxx M$ - - - - - - - - - - - -
Override M$ 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6
Mineral Tax M$ 17.0 14.3 16.9 16.3 16.9 16.0 16.9 16.8 15.9 16.7 15.7 16.5
Net Profit M$ - - - - - - - - - - - -
Op. Costs M$ 26.1 23.9 26.1 25.4 26.1 25.3 26.0 25.9 25.1 25.7 24.9 25.6
Total Exp M$ 61.2 54.3 61.0 59.0 61.0 58.7 60.8 60.6 58.2 60.2 57.7 59.7
Op. Income M$ 66.0 60.6 66.2 64.0 66.0 64.0 65.7 65.5 63.4 65.0 62.9 64.4
CEE M$ - - - - - - - - - - - -
CDE M$ - - - - - - - - - - - -
CCA M$ - - - - - - - - - - - -
COGPE M$ - - - - - - - - - - - -
Abandon M$ - - - - - - - - - - - -
Total Capital M$ - - - - - - - - - - - -
COLONY GAS POOL
---------------------------------------------
Rem. Total
Oil Volume mbbl - -
Gas Volume mmcf 2,517.7 3,303.0
NGL Volume mbbl - -
Oil Rev M$ - -
Gas Rev M$ 9,914.9 12,515.3
NGL Rev M$ - -
ARTC M$ - -
Total Rev M$ 9,914.9 12,515.3
Crown Xxx M$ 458.9 607.6
XX Xxx M$ 738.8 940.9
Indian Xxx M$ - -
Override M$ 51.7 64.8
Mineral Tax M$ 740.7 1,067.2
Net Profit M$ - -
Op. Costs M$ 2,995.3 3,593.7
Total Exp M$ 4,985.4 6,274.3
Op. Income M$ 4,929.5 6,241.0
CEE M$ - -
CDE M$ - -
CCA M$ - -
COGPE M$ - -
Abandon M$ - -
Total Capital M$ - -
SINGLE WELL POOLS
-----------------------------------------------------------------------------------------------------------------------
Jan 2002 Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Oil Volume mbbl - - - - - - - - - - - -
Gas Volume mmcf 12.9 11.6 12.1 11.7 12.1 11.0 28.4 27.8 26.3 34.1 32.4 32.9
NGL Volume mbbl - - - - - - - - - - - -
Oil Rev M$ - - - - - - - - - - - -
Gas Rev M$ 36.7 33.0 34.7 33.5 34.6 31.6 83.7 81.8 77.6 99.3 94.4 96.0
NGL Rev M$ - - - - - - - - - - - -
ARTC M$ - - - - - - - - - - - -
Total Rev M$ 36.7 33.0 34.7 33.5 34.6 31.6 83.7 81.8 77.6 99.3 94.4 96.0
Crown Xxx M$ - - - - - - - - - 6.0 5.6 5.8
XX Xxx M$ 6.4 5.8 6.1 5.9 6.0 5.5 5.4 5.0 4.6 4.5 4.1 4.0
Indian Xxx M$ - - - - - - - - - - - -
Override M$ - - - - - - - - - - - -
Mineral Tax M$ 6.6 5.6 6.4 6.2 6.3 5.6 5.3 4.9 4.2 4.0 3.5 3.4
Net Profit M$ - - - - - - - - - - - -
Op. Costs M$ 11.9 11.1 11.2 11.0 11.2 10.5 13.0 12.6 12.0 14.4 13.8 13.7
Total Exp M$ 24.9 22.5 23.7 23.0 23.6 21.6 23.7 22.5 20.8 28.9 27.0 26.8
Op. Income M$ 11.8 10.5 11.0 10.5 11.0 9.9 60.0 59.4 56.8 70.4 67.4 69.1
CEE M$ - - - - - - - - - - - -
CDE M$ - - - - - 49.4 - - - - - -
CCA M$ - - - - - - - - - 24.7 - -
COGPE M$ - - - - - - - - - - - -
Abandon M$ - - - - - - - - - - - -
Total Capital M$ - - - - - 49.4 - - - 24.7 - -
SINGLE WELL POOLS
-----------------------------------------------------------------------------------------------------------------------------
Jan 2003 Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Oil Volume mbbl - - - - - - - - - - - -
Gas Volume mmcf 32.4 28.8 31.5 30.0 28.0 24.6 23.2 21.2 18.9 18.0 16.2 15.6
NGL Volume mbbl - - - - - - - - - - - -
Oil Rev M$ - - - - - - - - - - - -
Gas Rev M$ 126.0 112.1 122.5 116.9 108.9 95.4 89.7 81.9 72.8 69.4 62.3 59.9
NGL Rev M$ - - - - - - - - - - - -
ARTC M$ - - - - - - - - - - - -
Total Rev M$ 126.0 112.1 122.5 116.9 108.9 95.4 89.7 81.9 72.8 69.4 62.3 59.9
Crown Xxx M$ 7.8 6.6 7.5 7.0 7.2 6.7 6.9 6.7 6.3 6.4 6.0 6.1
XX Xxx M$ 5.0 4.3 4.5 4.1 4.1 3.8 3.7 3.5 3.3 3.3 3.0 3.0
Indian Xxx M$ - - - - - - - - - - - -
Override M$ - - - - - - - - - - - -
Mineral Tax M$ 4.5 3.4 3.7 3.1 3.0 2.5 2.4 2.2 1.8 1.7 1.4 1.3
Net Profit M$ - - - - - - - - - - - -
Op. Costs M$ 13.8 12.8 13.3 12.8 12.8 12.3 12.3 12.1 11.8 11.8 11.5 11.5
Total Exp M$ 31.0 27.0 28.9 27.0 27.0 25.3 25.3 24.6 23.1 23.2 21.9 22.0
Op. Income M$ 95.0 85.1 93.6 89.8 81.9 70.1 64.4 57.3 49.7 46.2 40.4 37.9
CEE M$ - - - - - - - - - - - -
CDE M$ - - - - - - - - - - - -
CCA M$ - - - - - - - - - - - -
COGPE M$ - - - - - - - - - - - -
Abandon M$ - - - - - - - - - - - -
Total Capital M$ - - - - - - - - - - - -
SINGLE WELL POOLS
-------------------------------------------
Rem. Total
Oil Volume mbbl - -
Gas Volume mmcf 611.5 1,153.4
NGL Volume mbbl - -
Oil Rev M$ - -
Gas Rev M$ 2,361.9 4,216.6
NGL Rev M$ - -
ARTC M$ - -
Total Rev M$ 2,361.9 4,216.6
Crown Xxx M$ 260.6 359.0
XX Xxx M$ 132.8 241.7
Indian Xxx M$ - -
Override M$ - -
Mineral Tax M$ 7.3 100.3
Net Profit M$ - -
Op. Costs M$ 603.9 899.0
Total Exp M$ 1,004.7 1,600.0
Op. Income M$ 1,357.2 2,616.6
CEE M$ - -
CDE M$ - 49.4
CCA M$ - 24.7
COGPE M$ - -
Abandon M$ - -
Total Capital M$ - 74.2
99
PAGE 2
WESTERRA 2000
ESCALATING PRICES AS OF JANUARY 1, 2002
TOTAL PROVED RESERVES
WESTERRA 2000
PRICE FILE: BASE
WESTERRA 2000 TOTAL
-----------------------------------------------------------------------------------------------------------------------------------
Jan 2002 Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Oil Volume mbbl - - - - - - - - - - - -
Gas Volume mmcf 46.0 41.2 45.2 43.2 44.4 42.4 61.3 61.0 58.6 67.7 65.1 66.7
NGL Volume mbbl - - - - - - - - - - - -
Oil Rev. M$ - - - - - - - - - - - -
Gas Rev. M$ 131.6 117.8 129.4 123.5 127.1 121.3 177.9 176.8 170.1 195.4 187.7 192.6
NGL Rev. M$ - - - - - - - - - - - -
ART C M$ - - - - - - - - - - - -
Total Rev. M$ 131.6 117.8 129.4 123.5 127.1 121.3 177.9 176.8 170.1 195.4 187.7 192.6
Crown Xxx. M$ 6.8 5.8 5.1 4.8 5.0 4.8 5.1 5.1 4.9 11.2 10.6 11.0
XX Xxx. M$ 12.2 10.9 13.6 13.0 13.4 12.6 12.9 12.5 11.9 12.1 11.5 11.6
Indian Xxx. M$ - - - - - - - - - - - -
Override M$ 0.6 0.5 0.5 0.5 0.5 0.4 0.5 0.5 0.5 0.5 0.5 0.5
Mineral Tax M$ 18.0 15.0 17.5 16.6 17.1 15.8 16.5 16.1 15.0 15.6 14.5 15.0
Net Profit M$ - - - - - - - - - - - -
Op. Costs M$ 36.4 33.3 36.1 34.8 35.6 34.3 37.7 37.5 36.3 39.6 38.3 39.0
Total Exp M$ 74.0 65.5 72.7 69.6 71.5 67.9 72.6 71.8 68.7 78.9 75.4 77.1
Op. Income M$ 57.6 52.3 56.6 53.8 55.7 53.4 105.4 105.1 101.4 116.5 112.4 115.5
CEE M$ - - - - - - - - - - - -
CDE M$ - - - - - 49.4 - - - - - -
CCA M$ - - - - - - - - - 24.7 - -
COG PE M$ - - - - - - - - - - - -
Abandon M$ - - - - - - - - - - - -
Total Capital M$ - - - - - 49.4 - - - 24.7 - -
WESTERRA 2000 TOTAL
-----------------------------------------------------------------------------------------------------------------------------------
Jan 2003 Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Oil Volume mbbl - - - - - - - - - - - -
Gas Volume mmcf 66.3 59.4 65.3 62.8 61.8 57.3 56.9 54.8 51.3 51.4 48.3 48.7
NGL Volume mbbl - - - - - - - - - - - -
Oil Rev. M$ - - - - - - - - - - - -
Gas Rev. M$ 253.2 227.0 249.7 239.9 235.9 218.1 216.2 208.0 194.4 194.6 182.8 184.0
NGL Rev. M$ - - - - - - - - - - - -
ART C M$ - - - - - - - - - - - -
Total Rev. M$ 253.2 227.0 249.7 239.9 235.9 218.1 216.2 208.0 194.4 194.6 182.8 184.0
Crown Xxx. M$ 15.2 13.0 14.8 14.1 14.5 13.7 14.2 14.0 13.3 13.7 13.0 13.4
XX Xxx. M$ 15.0 13.3 14.5 13.8 14.1 13.4 13.7 13.5 12.9 13.1 12.5 12.8
Indian Xxx. M$ - - - - - - - - - - - -
Override M$ 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6
Mineral Tax M$ 21.5 17.7 20.6 19.4 19.9 18.5 19.3 19.0 17.7 18.4 17.1 17.9
Net Profit M$ - - - - - - - - - - - -
Op. Costs M$ 39.9 36.8 39.4 38.2 38.8 37.7 38.3 38.0 36.9 37.5 36.4 37.0
Total Exp M$ 92.2 81.3 89.9 86.1 88.0 84.0 86.1 85.1 81.3 83.4 79.6 81.7
Op. Income M$ 161.0 145.7 159.8 153.9 148.0 134.2 130.1 122.9 113.1 111.2 103.2 102.3
CEE M$ - - - - - - - - - - - -
CDE M$ - - - - - - - - - - - -
CCA M$ - - - - - - - - - - - -
COG PE M$ - - - - - - - - - - - -
Abandon M$ - - - - - - - - - - - -
Total Capital M$ - - - - - - - - - - - -
WESTERRA 2000 TOTAL
---------------------------------------------
Rem. Total
Oil Volume mbbl - -
Gas Volume mmcf 3,129.2 4,456.3
NGL Volume mbbl - -
Oil Rev. M$ - -
Gas Rev. M$ 12,276.8 16,731.9
NGL Rev. M$ - -
ART C M$ - -
Total Rev. M$ 12,276.8 16,731.9
Crown Xxx. M$ 719.5 966.7
XX Xxx. M$ 871.7 1,182.5
Indian Xxx. M$ - -
Override M$ 51.7 64.8
Mineral Tax M$ 748.0 1,167.5
Net Profit M$ - -
Op. Costs M$ 3,599.2 4,492.8
Total Exp M$ 5,990.1 7,874.3
Op. Income M$ 6,286.7 8,857.6
CEE M$ - -
CDE M$ - 49.4
CCA M$ - 24.7
COG PE M$ - -
Abandon M$ - -
Total Capital M$ - 74.2
100
ECONOMIC EVALUATION REPORTS
SUMMARY OF PROBABLE RESERVES
101
TABLE 2
PAGE 1
WESTERRA 2000
ESCALATING PRICES AS OF JANUARY 1, 2002
TOTAL PROBABLE ADDITIONAL RESERVES
WESTERRA 2000
COMPANY GROSS INTEREST RESERVES NET PRESENT VALUE (M$)
------------------------------- ---------------------------
COMPANY RES. GAS OIL NGL SULPHUR
AREA AND PROPERTY INTEREST % ZONES CAT MMCF MBBL MBBL MLT @ 10.0% @ 12.0% @ 15.0%
----------------------------------------------------------------------------------------------------------------------------------
COLONY GAS POOL
131/16-23-049-28W3/0 Colony NRA - - - - - - -
101/12-24-049-28W3/0 Colony NRA - - - - - - -
121/13-24-049-28W3/0 Colony NRA - - - - - - -
131/15-24-049-28W3/0 Colony NRA - - - - - - -
121/02-25-049-28W3/0 Colony NRA - - - - - - -
121/06-25-049-28W3/0 Colony NRA - - - - - - -
131/13-25-049-28W3/0 Colony NRA - - - - - - -
121/01-26-049-28W3/0 Colony NRA - - - - - - -
SUBTOTAL COLONY GAS POOL - - - - - - -
SINGLE WELL POOLS
1C0/06-09-050-01W4/0 W=60.000 Sparky Gas TPA 52.4 - - - 84.4 78.9 71.4
1C0/08-22-050-02W4/2 W=60.000 Colony TPA 195.9 - - - 183.8 154.7 122.5
1C0/08-22-050-02W4/w W=15.000 Waseca TPP 97.8 - - - 144.9 133.1 118.2
141/14-15-049-27W3/0 Lloydminster NRA - - - - - - -
141/14-15-049-27W3/2 Xxxxxxxx NRA - - - - - - -
141/15-15-049-27W3/3 Sparky NRA - - - - - - -
131/02-14-050-28W3/X X=15.000 Lloydminster P+P-NP 68.1 - - - 91.2 87.2 81.7
SUBTOTAL SINGLE WELL POOLS 414.2 - - - 504.3 453.9 393.8
----------------------------------------------------------------------------------------------------------------------------------
TOTAL 414.2 - - - 504.3 453.9 393.8
RESERVE CATEGORY ABBREVIATIONS
------------------------------------------------------------------------------------------------------------------------
TP Total Proved P-DP Proved Producing P-NP Proved Non Producing
TPP Total Proved and Probable P+P-DP Proved + Prob. Producing P+P-NP Proved + Prob. Non Producing
TPPP Total Proved + Prob. + Poss. PPP-DP Proved + Prob. + Poss. Producing PPP-NP Proved + Prob. + Poss. Non Producin
TPA Total Probable Additional PA-DP Prob. Additional Producing PA-NP Prob. Additional Non Producing
PSA Total Possible Additional PS-XX Xxxx. Additional Producing PS-XX Xxxx. Additional Non Producing
NRA No Reserves Assigned
RESERVE CATEGORY ABBREVIATIONS
--------------------------------------------------------------------------------
TP Total Proved P-UD Proved Undeveloped
TPP Total Proved and Probable P+P-UD Proved + Prob. Undeveloped
TPPP Total Proved + Prob. + Poss. PPP-UD Proved + Prob. + Poss. Undeveloped
TPA Total Probable Additional PA-UD Prob. Additional Undeveloped
PSA Total Possible Additional PS-UD Poss. Additional Undeveloped
NRA No Reserves Assigned
102
SUMMARY
Westerra 2000 [BAR GRAPH]
Westerra 2000
Total Probable Additional
As Of Date January 1, 2002
Prediction Date
Alberta
UWI
Net No. Xxxxx 0.00
Average WI 27%
Average Royalty 17%
Price Schedule ATB 2001 Q4
Price File Base
Econ. Limit Enabled
GCA Applied No
BOE Ratio 10:1
COMPANY WI SHARE NET PRESENT WORTH VALUE BEFORE TAX (M$) PRICE
---------------- ----------------------------------------- ------
REMAINING GROSS NET 8.0% 10.0% 12.0% 15.0% 20.0% YEAR 1
--------- ----- --- ---- ----- ----- ----- ----- ------
Oil (mbbl) - - - - - - - - -
Gas(mmcf) (10:1) 1,519.9 414.2 341.8 566.1 504.3 453.9 393.8 321.0 -
NGL(mbbl) (1:1) - - - - - - - - -
C2 (mbbl) (1:1) - - - - - - - - -
C3 (mbbl) (1:1) - - - - - - - - -
C4 (mbbl) (1:1) - - - - - - - - -
C5+ (mbbl) (1:1) - - - - - - - - -
Sulphur (mlt) (1:1) - - - - - - - - -
-------------------------------------------------------------------------------------------------------------
TOTALS (MBOE) 152.0 41.4 34.2 566.1 504.3 453.9 393.8 321.0
AFTER TAX 384.8 341.7 306.6 264.9 214.4
CAPITAL COSTS (M$) CASH FLOW (M$) ECONOMIC INDICATORS
-------------------------------------- ---------------------------------- -------------------------------------------------
GROSS NET GROSS NET BEFORE TAX AFTER TAX
----- --- ----- --- ---------- ---------
CEE - - Revenue 6,031.5 1,643.7 Rate of Return (%) - -
CDE 36.3 9.9 Royalties 910.9 248.2 Payout (yrs) 0.5 1.0
CCA 22.7 6.2 Op. Costs 1,186.0 323.2 P/I - 0.0% Discount 65.2 45.0
COGPE - - Capital 59.0 16.1 P/I - 12.0% Discount 29.9 -
Abandonment - - ARTC - - Op. Cost ($/boe) 2.1 -
Cap. Cost ($/boe) 0.1 -
----------------------------------------------------------------------------
Total 59.0 16.1 Before Tax 3,875.7 1,056.2
ANNUAL CASH FLOW
GROSS ROYALTY OPERATING CAPITAL BTAX NET BTAX ATAX NET ATAX
WELL RATE PRICE REVENUE & TAXES COST COST ARTC REVENUE NET CUM TAX PAID REVENUE NET CUM
YEAR COUNT MCF/D $/MCF M$ M$ M$ M$ M$ M$ M$ M$ M$ M$
-------------------------------------------------------------------------------------------------------------------------
2002 0.14 56.3 2.84 58.3 15.3 12.9 16.1 - 12.4 12.4 - - -
2003 0.30 71.5 3.66 95.6 35.2 19.8 - - 38.3 50.7 15.1 23.2 23.2
2004 0.30 140.3 3.85 197.6 28.6 16.8 - - 150.6 201.3 43.3 107.3 130.5
2005 0.85 133.4 3.87 188.5 23.7 43.7 - - 120.0 321.3 35.0 85.0 215.5
2006 0.90 102.8 3.84 144.2 19.7 45.8 - - 77.9 399.3 23.8 54.1 269.7
2007 0.75 79.0 3.80 109.6 16.9 37.1 - - 55.0 454.3 17.6 37.4 307.1
2008 0.30 54.6 3.73 74.4 14.7 10.8 - - 48.6 502.9 15.6 33.0 340.1
2009 0.30 50.0 3.72 67.8 12.7 10.2 - - 44.7 547.5 14.3 30.4 370.5
2010 0.30 45.7 3.70 61.8 10.9 9.6 - - 41.2 588.7 13.0 28.1 398.7
2011 0.30 41.9 3.79 57.9 9.6 9.2 - - 39.0 627.7 12.2 26.8 425.5
REM. 0.25 16.3 4.50 587.9 61.0 107.2 - - 419.7 1,047.4 122.8 296.9 722.3
-------------------------------------------------------------------------------------------------------------------------
TOTAL 35.4 3.97 1,643.7 248.2 323.2 16.1 - 1,047.4 312.7 722.3
103
Table B
Page 1
WESTERRA 2000
ESCALATING PRICES AS OF JANUARY 1, 2002
TOTAL PROBABLE ADDITIONAL RESERVES
WESTERRA 2000
PRODUCTION RESOURCE ADJUSTED RESOURCE RESOURCE RESOURCE COGPE, CDE,
SALES ROYALTY NPI OPERATING CCA RESOURCE ALLOWANCE ROYALTY ROYALTY CEE, FEDE TOTAL OTHER
REVENUE PAID PAYMENTS EXPENSE EXPENSE PROFITS AT 25% INCOME EXPENSE EXPENSE REVENUES
YEAR M$ M$ M$ M$ M$ M$ M$ M$ M$ M$ M$
------------------------------------------------------------------------------------------------------------------------------
2002 - - - - - - - - - - -
2003 95.6 - - 19.8 1.3 74.5 18.6 - - 2.1 -
2004 197.6 - - 16.8 1.0 179.8 44.9 - - 1.5 -
2005 188.5 - - 43.7 0.7 144.1 36.0 - - 1.1 -
2006 144.2 - - 45.8 0.6 97.8 24.5 - - 0.8 -
2007 109.6 - - 37.1 0.4 72.0 18.0 - - 0.6 -
2008 74.4 - - 10.8 0.3 63.3 15.8 - - 0.4 -
2009 67.8 - - 10.2 0.3 57.3 14.3 - - 0.3 -
2010 61.8 - - 9.6 0.2 52.0 13.0 - - 0.2 -
2011 57.9 - - 9.2 0.1 48.6 12.1 - - 0.1 -
2012 52.6 - - 6.9 0.1 45.6 11.4 - - 0.1 -
2013 49.3 - - 6.3 0.1 42.9 10.7 - - 0.1 -
2014 46.3 - - 6.0 0.1 40.3 10.1 - - 0.0 -
2015 43.4 - - 5.8 0.0 37.6 9.4 - - 0.0 -
2016 40.4 - - 5.5 0.0 34.9 8.7 - - 0.0 -
Rem. 355.9 - - 76.7 0.1 279.0 69.8 - - 0.1 -
TOTAL 1,585.4 - - 310.3 5.4 1,269.7 317.4 - - 7.5 -
------------------------------------------------------------------------------------------------------------------------------
LOAN TAX LOSS TAXABLE
TOTAL OTHER INTEREST CARRY RESOURCE
EXPENSES PAID FORWARD INCOME
YEAR M$ M$ M$ M$
---------------------------------------------------
2002 - - - -
2003 - - - 53.7
2004 - - - 133.3
2005 - - - 107.0
2006 - - - 72.5
2007 - - - 53.4
2008 - - - 47.1
2009 - - - 42.7
2010 - - - 38.8
2011 - - - 36.3
2012 - - - 34.1
2013 - - - 32.1
2014 - - - 30.1
2015 - - - 28.1
2016 - - - 26.1
Rem. - - - 209.2
TOTAL - - - 944.7
---------------------------------------------------
CAPITAL COST ALLOWANCE CANADIAN OIL & GAS PROPERTY EXPENSE CANADIAN DEVELOPMENT EXPENSE
--------------------------- ----------------------------------- -----------------------------------
INITIAL EXPENSE INITIAL DEPN. EXPENSE INITIAL DEPN. EXPENSE
BALANCE ADDITIONS CLAIM BALANCE ADDITIONS RATE CLAIM BALANCE ADDITIONS RATE CLAIM
YEAR M$ M$ M$ M$ M$ % M$ M$ M$ % M$
---------------------------------------------------------------------------------------------------------------
2002 - - - - - - - - - - -
2003 10.5 - 1.3 - - - - 14.5 - - 2.1
2004 8.0 - 1.0 - - - - 10.4 - - 1.5
2005 6.1 - 0.7 - - - - 7.4 - - 1.1
2006 2.4 - 0.6 - - - - 2.8 - - 0.8
2007 1.8 - 0.4 - - - - 1.9 - - 0.6
2008 1.3 - 0.3 - - - - 1.4 - - 0.4
2009 1.0 - 0.3 - - - - 1.0 - - 0.3
2010 0.8 - 0.2 - - - - 0.7 - - 0.2
2011 0.6 - 0.1 - - - - 0.5 - - 0.1
2012 0.4 - 0.1 - - - - 0.3 - - 0.1
2013 0.3 - 0.1 - - - - 0.2 - - 0.1
2014 0.2 - 0.1 - - - - 0.2 - - 0.0
2015 0.2 - 0.0 - - - - 0.1 - - 0.0
2016 0.1 - 0.0 - - - - 0.1 - - 0.0
Rem. 0.5 - 0.1 - - 4.1 - 0.2 - 12.4 0.1
TOTAL 34.3 - 5.4 - - 2.2 - 41.6 - 6.6 7.5
---------------------------------------------------------------------------------------------------------------
FOREIGN EXPL & DEV EXPENSE CEE
--------------------------- -------
INITIAL ALLOWABLE EXPENSE EXPENSE TOTAL
BALANCE DEPN RT CLAIM CLAIM CLAIMS
YEAR M$ % M$ M$ M$
-------------------------------------------------------
2002 - - - - -
2003 - - - - 3.4
2004 - - - - 2.5
2005 - - - - 1.8
2006 - - - - 1.4
2007 - - - - 1.0
2008 - - - - 0.7
2009 - - - - 0.5
2010 - - - - 0.4
2011 - - - - 0.3
2012 - - - - 0.2
2013 - - - - 0.1
2014 - - - - 0.1
2015 - - - - 0.1
2016 - - - - 0.1
Rem. - 41.2 - - 0.2
TOTAL - 21.9 - - 13.0
-------------------------------------------------------
FEDERAL PROVINCIAL
----------------------------- ---------------------------------------
ROYALTY REVENUES TOTAL SASK.
TAX CR. XXX. & TAX TAXABLE TAX BEFORE INCOME TAX CAPITAL
TAX RATE PAYABLE MIN. TAX DEDUCTIONS NET INCOME TAX RATE PAYABLE INC. TAX PAID SURCHARGE
YEAR % M$ M$ M$ M$ % M$ M$ M$ M$
------------------------------------------------------------------------------------------------------------------
2002 - - - - - - - - - -
2003 - 14.0 35.2 - 10.2 10.00 1.0 38.3 15.1 -
2004 - 34.8 28.6 - 105.8 8.00 8.5 150.6 43.3 -
2005 - 27.9 23.7 - 88.7 8.00 7.1 120.0 35.0 -
2006 - 18.9 19.7 - 60.7 8.00 4.9 77.9 23.8 -
2007 - 14.0 16.9 - 45.5 8.00 3.6 55.0 17.6 -
2008 - 12.3 14.7 - 41.1 8.00 3.3 48.6 15.6 -
2009 - 11.2 12.7 - 38.7 8.00 3.1 44.7 14.3 -
2010 - 10.1 10.9 - 36.1 8.00 2.9 41.2 13.0 -
2011 - 9.5 9.6 - 34.5 8.00 2.8 39.0 12.2 -
2012 - 8.9 8.4 - 33.8 8.00 2.7 37.3 11.6 -
2013 - 8.4 7.3 - 32.1 8.00 2.6 35.7 11.0 -
2014 - 7.9 6.3 - 30.1 8.00 2.4 34.0 10.3 -
2015 - 7.3 5.5 - 28.1 8.00 2.3 32.1 9.6 -
2016 - 6.8 4.7 - 26.1 8.00 2.1 30.2 8.9 -
Rem. 10.76 54.7 28.8 - 209.4 8.00 16.8 250.4 71.5 -
TOTAL 5.71 246.8 233.0 - 821.2 8.02 65.9 1,035.0 312.7 -
LOAN CASH FLOW AFTER TAXES
------------------- ----------------------
PRINCIPAL INTEREST NPV @
PAYMENTS PAID ANNUAL CUM 12.0%
YEAR M$ M$ M$ M$ M$
----------------------------------------------------
2002 - - - - -
2003 - - 23.2 23.2 19.6
2004 - - 107.3 130.5 80.8
2005 - - 85.0 215.5 57.2
2006 - - 54.1 269.7 32.5
2007 - - 37.4 307.1 20.1
2008 - - 33.0 340.1 15.8
2009 - - 30.4 370.5 13.0
2010 - - 28.1 398.7 10.7
2011 - - 26.8 425.5 9.1
2012 - - 25.7 451.1 7.8
2013 - - 24.8 475.9 6.7
2014 - - 23.7 499.6 5.7
2015 - - 22.5 522.1 4.9
2016 - - 21.3 543.4 4.1
Rem. - - 179.0 722.3 18.5
TOTAL - - 722.3 722.3 306.6
PRESENT WORTH VALUES - M$
-----------------------------------------
8.0% 10.0% 12.0% 15.0% 20.0%
--------------------------------------------------------------------------------
Before Income Taxes 566.1 504.3 453.9 393.8 321.0
After Income Taxes 384.8 341.7 306.6 264.9 214.4
104
PAGE 1
WESTERRA 2000
ESCALATING PRICES AS OF JANUARY 1, 2002
TOTAL PROBABLE ADDITIONAL RESERVES
WESTERRA 2000
PRICE FILE: BASE
COLONY GAS POOL
--------------------------------------------------------------------------------------------------
Jan 2002 Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Oil Volume mbbl - - - - - - - - - - - -
Gas Volume mmcf - - - - - - - - - - - -
NGL Volume mbbl - - - - - - - - - - - -
Oil Rev. M$ - - - - - - - - - - - -
Gas Rev. M$ - - - - - - - - - - - -
NGL Rev. M$ - - - - - - - - - - - -
ARTC M$ - - - - - - - - - - - -
Total Rev. M$ - - - - - - - - - - - -
Crown Xxx. M$ - - - - - - - - - - - -
XX Xxx. M$ - - - - - - - - - - - -
Indian Xxx. M$ - - - - - - - - - - - -
Override M$ - - - - - - - - - - - -
Mineral Tax M$ - - - - - - - - - - - -
Net Profit M$ - - - - - - - - - - - -
Op. Costs M$ - - - - - - - - - - - -
Total Exp. M$ - - - - - - - - - - - -
Op. Income M$ - - - - - - - - - - - -
CEE M$ - - - - - - - - - - - -
CDE M$ - - - - - - - - - - - -
CCA M$ - - - - - - - - - - - -
COGPE M$ - - - - - - - - - - - -
Abandon M$ - - - - - - - - - - - -
Total Capital M$ - - - - - - - - - - - -
COLONY GAS POOL
-----------------------------------------------------------------------------------------------------------------
Jan 2003 Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Rem. Total
Oil Volume mbbl - - - - - - - - - - - - - -
Gas Volume mmcf - - - - - - - - - - - - - -
NGL Volume mbbl - - - - - - - - - - - - - -
Oil Rev. M$ - - - - - - - - - - - - - -
Gas Rev. M$ - - - - - - - - - - - - - -
NGL Rev. M$ - - - - - - - - - - - - - -
ARTC M$ - - - - - - - - - - - - - -
Total Rev. M$ - - - - - - - - - - - - - -
Crown Xxx. M$ - - - - - - - - - - - - - -
XX Xxx. M$ - - - - - - - - - - - - - -
Indian Xxx. M$ - - - - - - - - - - - - - -
Override M$ - - - - - - - - - - - - - -
Mineral Tax M$ - - - - - - - - - - - - - -
Net Profit M$ - - - - - - - - - - - - - -
Op. Costs M$ - - - - - - - - - - - - - -
Total Exp. M$ - - - - - - - - - - - - - -
Op. Income M$ - - - - - - - - - - - - - -
CEE M$ - - - - - - - - - - - - - -
CDE M$ - - - - - - - - - - - - - -
CCA M$ - - - - - - - - - - - - - -
COGPE M$ - - - - - - - - - - - - - -
Abandon M$ - - - - - - - - - - - - - -
Total Capital M$ - - - - - - - - - - - - - -
SINGLE WELL POOLS
-------------------------------------------------------------------------------------------------------------
Jan 2002 Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Oil Volume mbbl - - - - - - - - - - - -
Gas Volume mmcf - - - - 2.3 2.1 2.1 2.1 1.9 3.4 3.3 3.3
NGL Volume mbbl - - - - - - - - - - - -
Oil Rev. M$ - - - - - - - - - - - -
Gas Rev. M$ - - - - 6.5 6.1 6.1 5.9 5.5 9.7 9.2 9.4
NGL Rev. M$ - - - - - - - - - - - -
ARTC M$ - - - - - - - - - - - -
Total Rev. M$ - - - - 6.5 6.1 6.1 5.9 5.5 9.7 9.2 9.4
Crown Xxx. M$ - - - - 2.0 1.8 1.8 1.8 1.6 2.7 2.6 2.6
XX Xxx. M$ - - - - - - - - - - - -
Indian Xxx. M$ - - - - - - - - - - - -
Override M$ - - - - - - - - - - - -
Mineral Tax M$ - - - - - - - - - - - -
Net Profit M$ - - - - - - - - - - - -
Op. Costs M$ - - - - 1.6 1.5 1.5 1.5 1.4 1.9 1.8 1.8
Total Exp. M$ - - - - 3.5 3.3 3.3 3.2 3.0 4.6 4.4 4.5
Op. Income M$ - - - - 2.9 2.8 2.7 2.6 2.5 5.0 4.8 4.9
CEE M$ - - - - - - - - - - - -
CDE M$ - - - 3.7 - - - - - 6.2 - -
CCA M$ - - - - - - - - - 6.2 - -
COGPE M$ - - - - - - - - - - - -
Abandon M$ - - - - - - - - - - - -
Total Capital M$ - - - 3.7 - - - - - 12.4 - -
SINGLE WELL POOLS
---------------------------------------------------------------------------------------------------------------------------------
Jan 2003 Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Rem. Total
Oil Volume mbbl - - - - - - - - - - - - - -
Gas Volume mmcf 3.3 2.9 1.6 -0.5 0.3 1.1 1.8 2.4 2.7 3.2 3.5 3.8 367.3 414.0
NGL Volume mbbl - - - - - - - - - - - - - -
Oil Rev. M$ - - - - - - - - - - - - - -
Gas Rev. M$ 12.3 11.0 5.5 -2.8 0.6 3.5 6.4 8.7 10.3 12.3 13.1 14.6 1,489.8 1,643.7
NGL Rev. M$ - - - - - - - - - - - - - -
ARTC M$ - - - - - - - - - - - - - -
Total Rev. M$ 12.3 11.0 5.5 -2.8 0.6 3.5 6.4 8.7 10.3 12.3 13.1 14.6 1,489.8 1,643.7
Crown Xxx. M$ 3.6 3.1 3.5 3.3 3.4 3.2 3.2 3.2 3.0 3.1 2.9 3.0 219.5 274.9
XX Xxx. M$ - - - - - - - - - - - - - -
Indian Xxx. M$ - - - - - - - - - - - - - -
Override M$ - - - - - - - - - - - - - -
Mineral Tax M$ - - - - - - - - - - - - - -
Net Profit M$ - - - - - - - - - - - - - -
Op. Costs M$ 1.8 1.7 1.8 1.7 1.7 1.6 1.7 1.6 1.6 1.6 1.5 1.5 290.5 323.2
Total Exp. M$ 5.5 4.7 5.3 5.0 5.1 4.8 4.9 4.8 4.6 4.7 4.4 4.5 510.0 598.1
Op. Income M$ 6.9 6.3 0.3 -7.7 -4.5 -1.2 1.5 3.9 5.7 7.6 8.7 10.1 979.8 1,045.6
CEE M$ - - - - - - - - - - - - - -
CDE M$ - - - - - - - - - - - - - 9.9
CCA M$ - - - - - - - - - - - - - 6.2
COGPE M$ - - - - - - - - - - - - - -
Abandon M$ - - - - - - - - - - - - - -
Total Capital M$ - - - - - - - - - - - - - 16.1
105
PAGE 2
WESTERRA 2000
ESCALATING PRICES AS OF JANUARY 1, 2002
TOTAL PROBABLE ADDITIONAL RESERVES
WESTERRA 2000
PRICE FILE: BASE
WESTERRA 2000 TOTAL
-------------------------------------------------------------------------------------------------------------
Jan 2002 Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Oil Volume mbbl - - - - - - - - - - - -
Gas Volume mmcf - - - - 2.3 2.1 2.1 2.1 1.9 3.4 3.3 3.3
NGL Volume mbbl - - - - - - - - - - - -
Oil Rev. M$ - - - - - - - - - - - -
Gas Rev. M$ - - - - 6.5 6.1 6.1 5.9 5.5 9.7 9.2 9.4
NGL Rev. M$ - - - - - - - - - - - -
ARTC M$ - - - - - - - - - - - -
Total Rev. M$ - - - - 6.5 6.1 6.1 5.9 5.5 9.7 9.2 9.4
Crown Xxx. M$ - - - - 2.0 1.8 1.8 1.8 1.6 2.7 2.6 2.6
XX Xxx. M$ - - - - - - - - - - - -
Indian Xxx. M$ - - - - - - - - - - - -
Override M$ - - - - - - - - - - - -
Mineral Tax M$ - - - - - - - - - - - -
Net Profit M$ - - - - - - - - - - - -
Op. Costs M$ - - - - 1.6 1.5 1.5 1.5 1.4 1.9 1.8 1.8
Total Exp. M$ - - - - 3.5 3.3 3.3 3.2 3.0 4.6 4.4 4.5
Op. Income M$ - - - - 2.9 2.8 2.7 2.6 2.5 5.0 4.8 4.9
CEE M$ - - - - - - - - - - - -
CDE M$ - - - 3.7 - - - - - 6.2 - -
CCA M$ - - - - - - - - - 6.2 - -
COGPE M$ - - - - - - - - - - - -
Abandon M$ - - - - - - - - - - - -
Total Capital M$ - - - 3.7 - - - - - 12.4 - -
WESTERRA 2000 TOTAL
---------------------------------------------------------------------------------------------------------------------------------
Jan 2003 Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Rem. Total
Oil Volume mbbl - - - - - - - - - - - - - -
Gas Volume mmcf 3.3 2.9 1.6 -0.5 0.3 1.1 1.8 2.4 2.7 3.2 3.5 3.8 367.3 414.0
NGL Volume mbbl - - - - - - - - - - - - - -
Oil Rev. M$ - - - - - - - - - - - - - -
Gas Rev. M$ 12.3 11.0 5.5 -2.8 0.6 3.5 6.4 8.7 10.3 12.3 13.1 14.6 1,489.8 1,643.7
NGL Rev. M$ - - - - - - - - - - - - - -
ARTC M$ - - - - - - - - - - - - - -
Total Rev. M$ 12.3 11.0 5.5 -2.8 0.6 3.5 6.4 8.7 10.3 12.3 13.1 14.6 1,489.8 1,643.7
Crown Xxx. M$ 3.6 3.1 3.5 3.3 3.4 3.2 3.2 3.2 3.0 3.1 2.9 3.0 219.5 274.9
XX Xxx. M$ - - - - - - - - - - - - - -
Indian Xxx. M$ - - - - - - - - - - - - - -
Override M$ - - - - - - - - - - - - - -
Mineral Tax M$ - - - - - - - - - - - - - -
Net Profit M$ - - - - - - - - - - - - - -
Op. Costs M$ 1.8 1.7 1.8 1.7 1.7 1.6 1.7 1.6 1.6 1.6 1.5 1.5 290.5 323.2
Total Exp. M$ 5.5 4.7 5.3 5.0 5.1 4.8 4.9 4.8 4.6 4.7 4.4 4.5 510.0 598.1
Op. Income M$ 6.9 6.3 0.3 -7.7 -4.5 -1.2 1.5 3.9 5.7 7.6 8.7 10.1 979.8 1,045.6
CEE M$ - - - - - - - - - - - - - -
CDE M$ - - - - - - - - - - - - - 9.9
CCA M$ - - - - - - - - - - - - - 6.2
COGPE M$ - - - - - - - - - - - - - -
Abandon M$ - - - - - - - - - - - - - -
Total Capital M$ - - - - - - - - - - - - - 16.1
106
ECONOMIC EVALUATION REPORTS
SUMMARY OF PROVED PLUS PROBABLE RESERVES
107
TABLE 2
PAGE 1
WESTERRA 2000
ESCALATING PRICES AS OF JANUARY 1, 2002
TOTAL PROVED AND PROBABLE RESERVES
WESTERRA 2000
COMPANY GROSS INTEREST RESERVES NET PRESENT VALUE (M$)
------------------------------------- ----------------------------
COMPANY RES. GAS OIL NGL SULPHUR
AREA AND PROPERTY INTEREST % ZONES CAT MMCF MBBL MBBL MLT @ 10.0% @ 12.0% @ 15.0%
------------------------------------------------------------------------------------------------------------------------------------
COLONY GAS POOL
131/16-23-049-28W3/0 W=60.000 Colony TPP 397.9 -- -- -- 390.3 361.0 324.2
101/12-24-049-28W3/0 W=60.000 Colony TPP 710.8 -- -- -- 736.6 675.2 599.9
121/13-24-049-28W3/0 W=60.000 Colony TPP 52.7 -- -- -- 81.9 79.6 76.3
131/15-24-049-28W3/0 W=60.000 Colony TPP 576.8 -- -- -- 607.0 567.7 516.3
121/02-25-049-28W3/0 W=60.000 Colony TPP 89.2 -- -- -- 132.8 128.4 122.3
121/06-25-049-28W3/0 W=60.000 Colony TPP 90.7 -- -- -- 134.7 130.3 124.2
131/13-25-049-28W3/0 W=60.000 Colony TPP 632.4 -- -- -- 568.1 516.7 454.9
121/01-26-049-28W3/0 W=60.000 Colony TPP 752.6 -- -- -- 907.3 836.8 749.8
SUBTOTAL COLONY GAS POOL 3,303.0 -- -- -- 3,558.9 3,295.6 2,967.9
SINGLE WELL POOLS
1C0/06-09-050-01W4/0 W=60.000 Sparky Gas P+P-NP 323.9 -- -- -- 839.6 817.3 786.0
1C0/08-22-050-02W4/2 W=60.000 Colony P+P-NP 687.2 -- -- -- 922.3 834.8 728.9
1C0/08-22-050-02W4/w W=15.000 Waseca TPP 97.8 -- -- -- 144.9 133.1 118.2
141/14-15-049-27W3/0 W=60.000 Lloydminster TPP 1.0 -- -- -- 1.1 1.1 1.1
141/14-15-049-27W3/2 W=60.000 Xxxxxxxx TPP 216.2 -- -- -- 211.4 196.6 177.8
141/15-15-049-27W3/3 W=60.000 Sparky TPP 175.2 -- -- -- 109.9 108.1 105.4
131/02-14-050-28W3/X X=15.000 Lloydminster P+P-NP 68.1 -- -- -- 91.2 87.2 81.7
SUBTOTAL SINGLE WELL POOLS 1,569.6 -- -- -- 2,320.5 2,178.1 1,999.2
------------------------------------------------------------------------------------------------------------------------------------
TOTAL 4,872.5 -- -- -- 5,879.4 5,473.8 4,967.1
RESERVE CATEGORY ABBREVIATIONS
------------------------------------------------------------------------------------------------------------------------------------
TP Total Proved P-DP Proved Producing P-NP Proved Non Producing P-UD Proved Undeveloped
TPP Total Proved and P+P-DP Proved + Prob. Producing P+P-NP Proved + Prob. Non P+P-UD Proved + Prob. Undeveloped
Probable Producing
TPPP Total Proved + Prob. + PPP-DP Proved + Prob. + Poss. PPP-NP Proved + Prob. + Poss. PPP-UD Proved + Prob. + Poss.
Poss. Producing Non Producin Undeveloped
TPA Total Probable PA-DP Prob. Additional PA-NP Prob. Additional Non PA-UD Prob. Additional Undeveloped
Additional Producing Producing
PSA Total Possible PS-XX Xxxx. Additional PS-XX Xxxx. Additional Non PS-UD Poss. Additional Undeveloped
Additional Producing Producing
NRA No Reserves Assigned
108
SUMMARY
Westerra 2000
Westerra 2000
TOTAL PROVED AND PROBABLE
As Of Date January 1, 2002
Prediction Date
Alberta
UWI
Net No. Xxxxx 6.00
Average WI 54%
Average Royalty 14%
Price Schedule ATB 2001 Q4
Price File Base
Econ. Limit Enabled
GCA Applied No
BOE Ratio 10:1
[BAR CHART]
COMPANY WI SHARE NET PRESENT WORTH VALUE BEFORE TAX (M$) PRICE
----------------- ------------------------------------------------- ------
REMAINING GROSS NET 8.0% 10.0% 12.0% 15.0% 20.0% YEAR 1
--------- ----- --- ---- ----- ----- ----- ----- ------
Oil (mbbl) -- -- -- -- -- -- -- -- --
Gas (mmcf) (10:1) 8,950.5 4,872.5 4,204.8 6,355.8 5,879.4 5,473.8 4,967.1 4,315.3 2.86
NGL (mbbl) (1:1) -- -- -- -- -- -- -- -- --
C2 (mbbl) (1:1) -- -- -- -- -- -- -- -- --
C3 (mbbl) (1:1) -- -- -- -- -- -- -- -- --
C4 (mbbl) (1:1) -- -- -- -- -- -- -- -- --
C5+ (mbbl) (1:1) -- -- -- -- -- -- -- -- --
Sulphur (mlt) (1:1) -- -- -- -- -- -- -- -- --
----------------------------------------------------------------------------------------------------------------------------------
TOTALS (mboe) 895.0 487.3 420.5 6,355.8 5,879.4 5,473.8 4,967.1 4,315.3
AFTER TAX 4,606.0 4,253.6 3,954.3 3,581.3 3,103.2
CAPITAL COSTS (M$)
GROSS NET
----- ---
CEE -- --
CDE 109.0 59.3
CCA 56.8 30.9
COGPE -- --
Abandonment -- --
------------------------------------------
Total 165.7 90.2
CASH FLOW (M$)
GROSS NET
----- ---
Revenue 33,754.5 18,375.6
Royalties 6,306.8 3,433.3
Op. Costs 8,846.6 4,816.0
Capital 165.7 90.2
ARTC -- --
------------------------------------------
Before Tax 18,435.5 10,036.0
ECONOMIC INDICATORS
BEFORE TAX AFTER TAX
---------- ---------
Rate of Return (%) -- --
Payout (yrs) 0.0 0.0
P/I - 0.0% Discount 105.6 77.2
P/I - 12.0% Discount 64.2 --
Op. Cost ($/boe) 5.4 --
Cap. Cost ($/boe) 0.1 --
ANNUAL CASH FLOW
GROSS ROYALTY OPERATING CAPITAL BTAX NET BTAX ATAX NET ATAX
WELL RATE PRICE REVENUE & TAXES COST COST ARTC REVENUE NET CUM TAX PAID REVENUE NET CUM
YEAR COUNT MCF/D $/MCF M$ M$ M$ M$ M$ M$ M$ M$ M$ M$
-------------------------------------------------------------------------------------------------------------------------
2002 6.59 1,817.8 2.88 1,909.6 419.7 451.6 90.2 -- 893.2 893.2 272.5 620.7 620.7
2003 7.50 1,945.9 3.80 2,699.5 572.2 474.7 -- -- 1,587.4 2,480.6 448.7 1,138.7 1,759.4
2004 7.50 1,530.9 3.77 2,112.6 487.6 450.5 -- -- 1,116.3 3,596.8 310.7 805.6 2,565.0
2005 6.95 1,248.0 3.84 1,747.7 413.4 371.4 -- -- 913.1 4,510.0 254.7 658.4 3,223.4
2006 6.75 1,022.4 3.83 1,428.7 328.2 327.9 -- -- 731.7 5,241.6 202.3 529.4 3,752.8
2007 5.95 844.0 3.82 1,176.8 259.7 281.9 -- -- 601.4 5,843.1 163.9 437.5 4,190.3
2008 4.50 691.2 3.81 963.8 202.3 219.1 -- -- 514.3 6,357.4 136.9 377.3 4,567.6
2009 4.50 588.3 3.80 816.6 153.0 198.1 -- -- 441.9 6,799.2 114.2 327.7 4,895.4
2010 4.50 497.3 3.80 689.1 111.0 179.4 -- -- 378.9 7,178.2 94.6 284.3 5,179.7
2011 4.50 420.6 3.85 591.0 82.3 163.5 -- -- 328.4 7,506.6 80.0 248.4 5,428.1
REM. 2.81 124.0 4.25 4,240.3 404.0 1,697.7 -- -- 2,020.4 9,527.0 479.7 1,540.7 6,968.9
-------------------------------------------------------------------------------------------------------------------------
TOTAL 416.7 3.77 18,375.6 3,433.3 4,816.0 90.2 -- 9,527.0 2,558.2 6,968.9
000
Xxxxx X
Page 1
WESTERRA 2000
ESCALATING PRICES AS OF JANUARY 1, 2002
TOTAL PROVED AND PROBABLE RESERVES
WESTERRA 2000
PRODUCTION RESOURCE ADJUSTED RESOURCE RESOURCE
SALES ROYALTY NPI OPERATING CCA RESOURCE ALLOWANCE ROYALTY
REVENUE PAID PAYMENTS EXPENSE EXPENSE PROFITS AT 25% INCOME
YEAR M$ M$ M$ M$ M$ M$ M$ M$
------------------------------------------------------------------------------------------
2002 1,909.6 -- -- 451.6 3.8 1,454.1 363.5 --
2003 2,699.5 -- -- 474.7 6.5 2,218.3 554.6 --
2004 2,112.6 -- -- 450.5 4.9 1,657.2 414.3 --
2005 1,747.7 -- -- 371.4 3.7 1,372.6 343.2 --
2006 1,428.7 -- -- 327.9 3.0 1,097.7 274.4 --
2007 1,176.8 -- -- 281.9 2.2 892.7 223.2 --
2008 963.8 -- -- 219.1 1.7 743.0 185.7 --
2009 816.6 -- -- 198.1 1.3 617.2 154.3 --
2010 689.1 -- -- 179.4 0.9 508.7 127.2 --
2011 591.0 -- -- 163.5 0.7 426.8 106.7 --
2012 511.0 -- -- 149.2 0.5 361.2 90.3 --
2013 447.2 -- -- 139.2 0.4 307.6 76.9 --
2014 395.2 -- -- 130.3 0.3 264.6 66.1 --
2015 347.5 -- -- 116.5 0.2 230.7 57.7 --
2016 317.4 -- -- 113.1 0.2 204.1 51.0 --
Rem 2,222.0 -- -- 1,049.3 0.5 1,172.2 293.0 --
TOTAL 18,375.6 -- -- 4,816.0 30.9 13,528.7 3,382.2 --
------------------------------------------------------------------------------------------
RESOURCE COGPE, CDE, TOTAL TOTAL LOAN TAX LOSS TAXABLE
ROYALTY CEE, FEDE OTHER OTHER INTEREST CARRY RESOURCE
EXPENSE EXPENSE REVENUES EXPENSES PAID FORWARD INCOME
YEAR M$ M$ M$ M$ M$ M$ M$
------------------------------------------------------------------------------
2002 144.0 14.2 -- -- -- -- 932.4
2003 161.3 12.8 -- -- -- -- 1,489.6
2004 139.2 9.2 -- -- -- -- 1,094.5
2005 114.6 6.6 -- -- -- -- 908.3
2006 95.3 5.0 -- -- -- -- 723.0
2007 79.9 3.5 -- -- -- -- 586.1
2008 66.0 2.4 -- -- -- -- 488.8
2009 55.0 1.7 -- -- -- -- 406.2
2010 45.0 1.2 -- -- -- -- 335.3
2011 37.0 0.8 -- -- -- -- 282.3
2012 30.8 0.6 -- -- -- -- 239.5
2013 26.1 0.4 -- -- -- -- 204.2
2014 22.4 0.3 -- -- -- -- 175.8
2015 18.8 0.2 -- -- -- -- 154.0
2016 17.3 0.1 -- -- -- -- 135.6
Rem 121.5 0.3 -- -- -- -- 757.3
TOTAL 1,174.2 59.3 -- -- -- -- 8,913.0
------------------------------------------------------------------------------
CAPITAL COST ALLOWANCE CANADIAN OIL & GAS PROPERTY EXPENSE CANADIAN DEVELOPMENT EXPENSE
----------------------------- --------------------------------------- -----------------------------------------
INITIAL EXPENSE INITIAL DEPN. EXPENSE INITIAL DEPN. EXPENSE
BALANCE ADDITIONS CLAIM BALANCE ADDITIONS RATE CLAIM BALANCE ADDITIONS RATE CLAIM
YEAR M$ M$ M$ M$ M$ % M$ M$ M$ % M$
-------------------------------------------------------------------------------------------------------------------------------
2002 7.5 30.9 3.8 -- -- 30.0 -- 13.7 59.3 90.0 14.2
2003 52.5 -- 6.5 -- -- 30.0 -- 86.9 -- 90.0 12.8
2004 40.0 -- 4.9 -- -- 30.0 -- 62.3 -- 90.0 9.2
2005 30.4 -- 3.7 -- -- 30.0 -- 44.6 -- 90.0 6.6
2006 12.0 -- 3.0 -- -- 20.0 -- 16.6 -- 60.0 5.0
2007 9.0 -- 2.2 -- -- 20.0 -- 11.6 -- 60.0 3.5
2008 6.7 -- 1.7 -- -- 20.0 -- 8.1 -- 60.0 2.4
2009 5.0 -- 1.3 -- -- 20.0 -- 5.7 -- 60.0 1.7
2010 3.8 -- 0.9 -- -- 20.0 -- 4.0 -- 60.0 1.2
2011 2.8 -- 0.7 -- -- 20.0 -- 2.8 -- 60.0 0.8
2012 2.1 -- 0.5 -- -- 20.0 -- 2.0 -- 60.0 0.6
2013 1.6 -- 0.4 -- -- 20.0 -- 1.4 -- 60.0 0.4
2014 1.2 -- 0.3 -- -- 20.0 -- 1.0 -- 60.0 0.3
2015 0.9 -- 0.2 -- -- 20.0 -- 0.7 -- 60.0 0.2
2016 0.7 -- 0.2 -- -- 20.0 -- 0.5 -- 60.0 0.1
Rem 2.0 -- 0.5 -- -- 19.4 -- 1.1 -- 58.2 0.3
TOTAL 178.2 30.9 30.9 -- -- 20.9 -- 262.9 59.3 62.8 59.3
-------------------------------------------------------------------------------------------------------------------------------
FOREIGN EXPL & DEV EXPENSE CEE
------------------------------ -------
INITIAL ALLOWABLE EXPENSE EXPENSE TOTAL
BALANCE DEPN RT CLAIM CLAIM CLAIMS
YEAR M$ % M$ M$ M$
---------------------------------------------------------------
2002 -- 300.0 -- -- 18.0
2003 -- 300.0 -- -- 19.2
2004 -- 300.0 -- -- 14.1
2005 -- 300.0 -- -- 10.3
2006 -- 200.0 -- -- 8.0
2007 -- 200.0 -- -- 5.7
2008 -- 200.0 -- -- 4.1
2009 -- 200.0 -- -- 3.0
2010 -- 200.0 -- -- 2.1
2011 -- 200.0 -- -- 1.5
2012 -- 200.0 -- -- 1.1
2013 -- 200.0 -- -- 0.8
2014 -- 200.0 -- -- 0.6
2015 -- 200.0 -- -- 0.4
2016 -- 200.0 -- -- 0.3
Rem -- 194.1 -- -- 0.8
TOTAL -- 209.4 -- -- 90.2
---------------------------------------------------------------
FEDERAL PROVINCIAL
--------------------------------- ---------------------------------------------
ROYALTY REVENUES
TAX CR. XXX. & TAX TAXABLE TAX BEFORE
TAX RATE PAYABLE MIN. TAX DEDUCTIONS NET INCOME TAX RATE PAYABLE INC. TAX
YEAR % M$ M$ M$ M$ % M$ M$
---------------------------------------------------------------------------------------------------------
2002 52.24 243.5 275.7 -- 252.1 11.50 29.0 893.2
2003 52.24 389.1 410.8 -- 596.0 10.00 59.6 1,587.4
2004 52.24 285.9 348.4 -- 309.6 8.00 24.8 1,116.3
2005 52.24 237.3 298.9 -- 217.9 8.00 17.4 913.1
2006 52.24 188.8 232.9 -- 168.3 8.00 13.5 731.7
2007 52.24 153.1 179.8 -- 135.3 8.00 10.8 601.4
2008 52.24 127.7 136.3 -- 115.9 8.00 9.3 514.3
2009 52.24 106.1 98.0 -- 100.8 8.00 8.1 441.9
2010 52.24 87.6 66.0 -- 87.5 8.00 7.0 378.9
2011 52.24 73.7 45.4 -- 78.2 8.00 6.3 328.4
2012 52.24 62.6 34.2 -- 71.0 8.00 5.7 282.5
2013 52.24 53.3 26.0 -- 63.6 8.00 5.1 243.4
2014 52.24 45.9 19.9 -- 56.6 8.00 4.5 211.6
2015 52.24 40.2 15.6 -- 50.3 8.00 4.0 186.9
2016 52.24 35.4 12.9 -- 44.6 8.00 3.6 165.2
Rem. 49.17 197.6 58.3 -- 271.8 8.00 21.7 930.7
TOTAL 50.61 2,327.9 2,259.1 -- 2,619.4 8.79 230.3 9,527.0
---------------------------------------------------------------------------------------------------------
LOAN CASH FLOW AFTER TAXES
-------------------- ----------------------------
TOTAL SASK.
INCOME TAX CAPITAL PRINCIPAL INTEREST NPV @
PAID SURCHARGE PAYMENTS PAID ANNUAL CUM 12.0%
YEAR M$ M$ M$ M$ M$ M$ M$
-----------------------------------------------------------------------------------------
2002 272.5 -- -- -- 620.7 620.7 586.5
2003 448.7 -- -- -- 1,138.7 1,759.4 960.7
2004 310.7 -- -- -- 805.6 2,565.0 606.8
2005 254.7 -- -- -- 658.4 3,223.4 442.8
2006 202.3 -- -- -- 529.4 3,752.8 317.9
2007 163.9 -- -- -- 437.5 4,190.3 234.6
2008 136.9 -- -- -- 377.3 4,567.6 180.6
2009 114.2 -- -- -- 327.7 4,895.4 140.1
2010 94.6 -- -- -- 284.3 5,179.7 108.5
2011 80.0 -- -- -- 248.4 5,428.1 84.6
2012 68.3 -- -- -- 214.2 5,642.3 65.2
2013 58.4 -- -- -- 185.0 5,827.4 50.3
2014 50.4 -- -- -- 161.2 5,988.6 39.1
2015 44.3 -- -- -- 142.7 6,131.3 30.9
2016 39.0 -- -- -- 126.2 6,257.5 24.4
Rem. 219.3 -- -- -- 711.4 6,968.9 81.2
TOTAL 2,558.2 -- -- -- 6,968.9 6,968.9 3,954.3
-----------------------------------------------------------------------------------------
PRESENT WORTH VALUES - M$
------------------------------------------------------------------
8.0% 10.0% 12.0% 15.0% 20.0%
----------------------------------------------------------------------------------------
Before Income Taxes 6,355.8 5,879.4 5,473.8 4,967.1 4,315.3
After Income Taxes 4,606.0 4,253.6 3,954.3 3,581.3 3,103.2
110
PAGE 1
WESTERRA 2000
ESCALATING PRICES AS OF JANUARY 1, 2002
TOTAL PROVED AND PROBABLE RESERVES
WESTERRA 2000
PRICE FILE: BASE
COLONY GAS POOL
Jan 2002 Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
-----------------------------------------------------------------------------------------------------
Oil Volume mbbl -- -- -- -- -- -- -- -- -- -- -- --
Gas Volume mmcf 33.2 29.7 33.1 31.5 32.4 31.4 32.9 33.2 32.3 33.6 32.6 33.8
NGL Volume mbbl -- -- -- -- -- -- -- -- -- -- -- --
Oil Rev M$ -- -- -- -- -- -- -- -- -- -- -- --
Gas Rev M$ 94.9 84.8 94.7 90.0 92.6 89.7 94.2 95.0 92.5 96.1 93.3 96.7
NGL Rev M$ -- -- -- -- -- -- -- -- -- -- -- --
ARTC M$ -- -- -- -- -- -- -- -- -- -- -- --
Total Rev M$ 94.9 84.8 94.7 90.0 92.6 89.7 94.2 95.0 92.5 96.1 93.3 96.7
Crown Xxx M$ 6.8 5.8 5.1 4.8 5.0 4.8 5.1 5.1 4.9 5.2 5.0 5.3
XX Xxx M$ 5.8 5.2 7.5 7.1 7.3 7.1 7.5 7.5 7.3 7.6 7.4 7.6
Indian Xxx M$ -- -- -- -- -- -- -- -- -- -- -- --
Override M$ 0.6 0.5 0.5 0.5 0.5 0.4 0.5 0.5 0.5 0.5 0.5 0.5
Mineral Tax M$ 11.4 9.4 11.2 10.4 10.7 10.2 11.1 11.2 10.8 11.5 11.0 11.6
Net Profit M$ -- -- -- -- -- -- -- -- -- -- -- --
Op. Costs M$ 24.4 22.2 24.8 23.8 24.4 23.7 24.7 24.9 24.4 25.2 24.5 25.3
Total Exp M$ 49.0 43.0 49.1 46.7 47.9 46.2 48.9 49.3 47.9 50.0 48.4 50.3
Op. Income M$ 45.8 41.8 45.6 43.3 44.7 43.4 45.4 45.7 44.6 46.1 45.0 46.4
CEE M$ -- -- -- -- -- -- -- -- -- -- -- --
CDE M$ -- -- -- -- -- -- -- -- -- -- -- --
CCA M$ -- -- -- -- -- -- -- -- -- -- -- --
COGPE M$ -- -- -- -- -- -- -- -- -- -- -- --
Abandon M$ -- -- -- -- -- -- -- -- -- -- -- --
Total Capital M$ -- -- -- -- -- -- -- -- -- -- -- --
Jan 2003 Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Rem. Total
-------------------------------------------------------------------------------------------------------------------------------
Oil Volume mbbl -- -- -- -- -- -- -- -- -- -- -- -- -- --
Gas Volume mmcf 33.9 30.6 33.9 32.8 33.8 32.7 33.7 33.6 32.4 33.3 32.1 33.0 2,517.7 3,303.0
NGL Volume mbbl -- -- -- -- -- -- -- -- -- -- -- -- -- --
Oil Rev M$ -- -- -- -- -- -- -- -- -- -- -- -- -- --
Gas Rev M$ 127.1 114.9 127.2 123.1 127.0 122.7 126.5 126.1 121.6 125.2 120.6 124.1 9,914.9 12,515.3
NGL Rev M$ -- -- -- -- -- -- -- -- -- -- -- -- -- --
ARTC M$ -- -- -- -- -- -- -- -- -- -- -- -- -- --
Total Rev M$ 127.1 114.9 127.2 123.1 127.0 122.7 126.5 126.1 121.6 125.2 120.6 124.1 9,914.9 12,515.3
Crown Xxx M$ 7.4 6.4 7.4 7.1 7.4 7.1 7.3 7.3 7.0 7.3 7.0 7.2 458.9 607.6
XX Xxx M$ 10.0 9.1 10.0 9.7 10.0 9.7 10.0 9.9 9.6 9.9 9.5 9.8 738.8 940.9
Indian Xxx M$ -- -- -- -- -- -- -- -- -- -- -- -- -- --
Override M$ 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 51.7 64.8
Mineral Tax M$ 17.0 14.3 16.9 16.3 16.9 16.0 16.9 16.8 15.9 16.7 15.7 16.5 740.7 1,067.2
Net Profit M$ -- -- -- -- -- -- -- -- -- -- -- -- -- --
Op. Costs M$ 26.1 23.9 26.1 25.4 26.1 25.3 26.0 25.9 25.1 25.7 24.9 25.6 2,995.3 3,593.7
Total Exp M$ 61.2 54.3 61.0 59.0 61.0 58.7 60.8 60.6 58.2 60.2 57.7 59.7 4,985.4 6,274.3
Op. Income M$ 66.0 60.6 66.2 64.0 66.0 64.0 65.7 65.5 63.4 65.0 62.9 64.4 4,929.5 6,241.0
CEE M$ -- -- -- -- -- -- -- -- -- -- -- -- -- --
CDE M$ -- -- -- -- -- -- -- -- -- -- -- -- -- --
CCA M$ -- -- -- -- -- -- -- -- -- -- -- -- -- --
COGPE M$ -- -- -- -- -- -- -- -- -- -- -- -- -- --
Abandon M$ -- -- -- -- -- -- -- -- -- -- -- -- -- --
Total Capital M$ -- -- -- -- -- -- -- -- -- -- -- -- -- --
SINGLE WELL POOLS
Jan 2002 Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
-----------------------------------------------------------------------------------------------------
Oil Volume mbbl -- -- -- -- -- -- -- -- -- -- -- --
Gas Volume mmcf 12.9 11.6 12.1 11.7 14.4 13.2 30.5 29.8 28.2 37.6 35.7 36.3
NGL Volume mbbl -- -- -- -- -- -- -- -- -- -- -- --
Oil Rev M$ -- -- -- -- -- -- -- -- -- -- -- --
Gas Rev M$ 36.7 33.0 34.7 33.5 41.0 37.7 89.8 87.7 83.1 109.0 103.6 105.4
NGL Rev M$ -- -- -- -- -- -- -- -- -- -- -- --
ARTC M$ -- -- -- -- -- -- -- -- -- -- -- --
Total Rev M$ 36.7 33.0 34.7 33.5 41.0 37.7 89.8 87.7 83.1 109.0 103.6 105.4
Crown Xxx M$ -- -- -- -- 2.0 1.8 1.8 1.8 1.6 8.8 8.2 8.4
XX Xxx M$ 6.4 5.8 6.1 5.9 6.0 5.5 5.4 5.0 4.6 4.5 4.1 4.0
Indian Xxx M$ -- -- -- -- -- -- -- -- -- -- -- --
Override M$ -- -- -- -- -- -- -- -- -- -- -- --
Mineral Tax M$ 6.6 5.6 6.4 6.2 6.3 5.6 5.3 4.9 4.2 4.0 3.5 3.4
Net Profit M$ -- -- -- -- -- -- -- -- -- -- -- --
Op. Costs M$ 11.9 11.1 11.2 11.0 12.8 12.0 14.5 14.0 13.4 16.3 15.6 15.5
Total Exp M$ 24.9 22.5 23.7 23.0 27.1 25.0 27.0 25.7 23.8 33.6 31.4 31.3
Op. Income M$ 11.8 10.5 11.0 10.5 13.9 12.7 62.7 62.0 59.2 75.4 72.3 74.1
CEE M$ -- -- -- -- -- -- -- -- -- -- -- --
CDE M$ -- -- -- 3.7 -- 49.4 -- -- -- 6.2 -- --
CCA M$ -- -- -- -- -- -- -- -- -- 30.9 -- --
COGPE M$ -- -- -- -- -- -- -- -- -- -- -- --
Abandon M$ -- -- -- -- -- -- -- -- -- -- -- --
Total Capital M$ -- -- -- 3.7 -- 49.4 -- -- -- 37.1 -- --
Jan 2003 Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Rem. Total
------------------------------------------------------------------------------------------------------------------------------
Oil Volume mbbl -- -- -- -- -- -- -- -- -- -- -- -- -- --
Gas Volume mmcf 35.7 31.7 33.0 29.5 28.4 25.7 25.0 23.6 21.6 21.3 19.7 19.5 978.9 1,567.4
NGL Volume mbbl -- -- -- -- -- -- -- -- -- -- -- -- -- --
Oil Rev M$ -- -- -- -- -- -- -- -- -- -- -- -- -- --
Gas Rev M$ 138.3 123.1 128.0 114.1 109.5 99.0 96.1 90.6 83.1 81.7 75.4 74.5 3,851.7 5,860.3
NGL Rev M$ -- -- -- -- -- -- -- -- -- -- -- -- -- --
ARTC M$ -- -- -- -- -- -- -- -- -- -- -- -- -- --
Total Rev M$ 138.3 123.1 128.0 114.1 109.5 99.0 96.1 90.6 83.1 81.7 75.4 74.5 3,851.7 5,860.3
Crown Xxx M$ 11.4 9.7 10.9 10.3 10.5 9.8 10.1 9.9 9.2 9.5 8.9 9.1 480.2 633.9
XX Xxx M$ 5.0 4.3 4.5 4.1 4.1 3.8 3.7 3.5 3.3 3.3 3.0 3.0 132.8 241.7
Indian Xxx M$ -- -- -- -- -- -- -- -- -- -- -- -- -- --
Override M$ -- -- -- -- -- -- -- -- -- -- -- -- -- --
Mineral Tax M$ 4.5 3.4 3.7 3.1 3.0 2.5 2.4 2.2 1.8 1.7 1.4 1.3 7.3 100.3
Net Profit M$ -- -- -- -- -- -- -- -- -- -- -- -- -- --
Op. Costs M$ 15.6 14.5 15.0 14.5 14.5 14.0 14.0 13.8 13.4 13.4 13.0 13.0 894.4 1,222.2
Total Exp M$ 36.5 31.8 34.1 32.0 32.1 30.1 30.2 29.4 27.7 27.9 26.3 26.5 1,514.7 2,198.1
Op. Income M$ 101.9 91.3 93.9 82.1 77.4 68.9 65.9 61.2 55.4 53.8 49.1 48.1 2,337.0 3,662.3
CEE M$ -- -- -- -- -- -- -- -- -- -- -- -- -- --
CDE M$ -- -- -- -- -- -- -- -- -- -- -- -- -- 59.3
CCA M$ -- -- -- -- -- -- -- -- -- -- -- -- -- 30.9
COGPE M$ -- -- -- -- -- -- -- -- -- -- -- -- -- --
Abandon M$ -- -- -- -- -- -- -- -- -- -- -- -- -- --
Total Capital M$ -- -- -- -- -- -- -- -- -- -- -- -- -- 90.2
111
Page 2
WESTERRA 2000
ESCALATING PRICES AS OF JANUARY 1, 2002
TOTAL PROVED AND PROBABLE RESERVES
WESTERRA 2000
PRICE FILE: BASE
WESTERRA 2000 TOTAL
Jan 2002 Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
------------------------------------------------------------------------------------------------------------------------------------
Oil Volume mbbl -- -- -- -- -- -- -- -- -- -- -- --
Gas Volume mmcf 46.0 41.2 45.2 43.2 46.7 44.5 63.5 63.0 60.6 71.2 68.3 70.1
NGL Volume mbbl -- -- -- -- -- -- -- -- -- -- -- --
Oil Rev. M$ -- -- -- -- -- -- -- -- -- -- -- --
Gas Rev. M$ 131.6 117.8 129.4 123.5 133.6 127.3 184.0 182.7 175.6 205.1 197.0 202.0
NGL Rev. M$ -- -- -- -- -- -- -- -- -- -- -- --
ART C M$ -- -- -- -- -- -- -- -- -- -- -- --
Total Rev. M$ 131.6 117.8 129.4 123.5 133.6 127.3 184.0 182.7 175.6 205.1 197.0 202.0
Crown Xxx. M$ 6.8 5.8 5.1 4.8 6.9 6.6 6.9 6.9 6.6 14.0 13.2 13.7
XX Xxx. M$ 12.2 10.9 13.6 13.0 13.4 12.6 12.9 12.5 11.9 12.1 11.5 11.6
Indian Xxx. M$ -- -- -- -- -- -- -- -- -- -- -- --
Override M$ 0.6 0.5 0.5 0.5 0.5 0.4 0.5 0.5 0.5 0.5 0.5 0.5
Mineral Tax M$ 18.0 15.0 17.5 16.6 17.1 15.8 16.5 16.1 15.0 15.6 14.5 15.0
Net Profit M$ -- -- -- -- -- -- -- -- -- -- -- --
Op. Costs M$ 36.4 33.3 36.1 34.8 37.1 35.7 39.2 38.9 37.7 41.5 40.1 40.8
Total Exp. M$ 74.0 65.5 72.7 69.6 75.0 71.2 75.9 75.0 71.7 83.5 79.8 81.6
Op. Income M$ 57.6 52.3 56.6 53.8 58.6 56.1 108.1 107.7 103.9 121.6 117.2 120.4
CEE M$ -- -- -- -- -- -- -- -- -- -- -- --
CDE M$ -- -- -- 3.7 -- 49.4 -- -- -- 6.2 -- --
CCA M$ -- -- -- -- -- -- -- -- -- 30.9 -- --
COGPE M$ -- -- -- -- -- -- -- -- -- -- -- --
Abandon M$ -- -- -- -- -- -- -- -- -- -- -- --
Total Capital M$ -- -- -- 3.7 -- 49.4 -- -- -- 37.1 -- --
Jan 2003 Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
------------------------------------------------------------------------------------------------------------------------------------
Oil Volume mbbl -- -- -- -- -- -- -- -- -- -- -- --
Gas Volume mmcf 69.5 62.3 66.9 62.3 62.2 58.3 58.6 57.1 54.0 54.6 51.8 52.5
NGL Volume mbbl -- -- -- -- -- -- -- -- -- -- -- --
Oil Rev. M$ -- -- -- -- -- -- -- -- -- -- -- --
Gas Rev. M$ 265.5 238.0 255.2 237.2 236.5 221.7 222.5 216.7 204.7 206.9 196.0 198.7
NGL Rev. M$ -- -- -- -- -- -- -- -- -- -- -- --
ART C M$ -- -- -- -- -- -- -- -- -- -- -- --
Total Rev. M$ 265.5 238.0 255.2 237.2 236.5 221.7 222.5 216.7 204.7 206.9 196.0 198.7
Crown Xxx. M$ 18.8 16.1 18.3 17.3 17.9 16.9 17.4 17.2 16.3 16.8 15.8 16.3
XX Xxx. M$ 15.0 13.3 14.5 13.8 14.1 13.4 13.7 13.5 12.9 13.1 12.5 12.8
Indian Xxx. M$ -- -- -- -- -- -- -- -- -- -- -- --
Override M$ 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6
Mineral Tax M$ 21.5 17.7 20.6 19.4 19.9 18.5 19.3 19.0 17.7 18.4 17.1 17.9
Net Profit M$ -- -- -- -- -- -- -- -- -- -- -- --
Op. Costs M$ 41.7 38.4 41.1 39.9 40.5 39.3 40.0 39.7 38.5 39.1 37.9 38.6
Total Exp. M$ 97.7 86.1 95.2 91.1 93.0 88.7 91.0 89.9 85.9 88.0 84.0 86.2
Op. Income M$ 167.8 151.9 160.1 146.1 143.5 132.9 131.5 126.7 118.8 118.8 112.0 112.5
CEE M$ -- -- -- -- -- -- -- -- -- -- -- --
CDE M$ -- -- -- -- -- -- -- -- -- -- -- --
CCA M$ -- -- -- -- -- -- -- -- -- -- -- --
COGPE M$ -- -- -- -- -- -- -- -- -- -- -- --
Abandon M$ -- -- -- -- -- -- -- -- -- -- -- --
Total Capital M$ -- -- -- -- -- -- -- -- -- -- -- --
Rem. Total
-----------------------------------------------
Oil Volume mbbl -- --
Gas Volume mmcf 3,496.5 4,870.3
NGL Volume mbbl -- --
Oil Rev. M$ -- --
Gas Rev. M$ 13,766.6 18,375.6
NGL Rev. M$ -- --
ART C M$ -- --
Total Rev. M$ 13,766.6 18,375.6
Crown Xxx. M$ 939.0 1,241.5
XX Xxx. M$ 871.7 1,182.5
Indian Xxx. M$ -- --
Override M$ 51.7 64.8
Mineral Tax M$ 748.0 1,167.5
Net Profit M$ -- --
Op. Costs M$ 3,889.6 4,816.0
Total Exp. M$ 6,500.1 8,472.4
Op. Income M$ 7,266.5 9,903.2
CEE M$ -- --
CDE M$ -- 59.3
CCA M$ -- 30.9
COGPE M$ -- --
Abandon M$ -- --
Total Capital M$ -- 90.2
112
INDIVIDUAL WELL
PRODUCTION PLOTS & ECONOMICS
113
CEDAR LLOYDMINSTER C16-23-49-28 (131/16-23-049-28W3/0) PROVED PRODUCING - RAW
STATUS Producer: Active gas well ON TIME 97%
FIELD N/A RIG RELEASE Sep 1935
POOL Colony WI 0%
UNIT N/A RLI 0.0
OPERATOR N/A TYPE P-DP
LICENSEE Xxxxxx Oil Company Ltd. Raw
RESERVES (JAN 1, 2002)
ULTIMATE CUMULATIVE REMAINING REMAINING
P-DP RESERVES PRODUCTION GROSS NET
-----------------------------------------------------------------
Oil (mbbl) 0.0 0.0 0.0 0.0
Gas (mmcf) 1,395.2 725.4 669.8 0.0
Water (mbbl) 0.0 0.0 0.0 0.0
DECLINES
DECLINE SEGMENT DATE QI DI NI TYPE
-----------------------------------------------------------------
NO DECLINES.
PRODUCTION (6 MO. HISTORY / 6 MO. FORECAST)
DATE WELL CDOR CDGR CDWR LGR
COUNT (BBL/D) (MCF/D) (BBL/D) (BBL/MMCF)
-----------------------------------------------------------------
Mar 1989 1.0 0 184 0 0
Oct 1989 1.0 0 172 0 0
Sep 2001 1.0 0 128 0 0
Oct 2001 1.0 0 255 0 0
Nov 2001 1.0 0 227 0 0
Dec 2001 1.0 0 207 0 0
-----------------------------------------------------------------
Jan 2002 1.0 0 231 0 0
Feb 2002 1.0 0 230 0 0
Mar 2002 1.0 0 185 0 0
Apr 2002 1.0 0 182 0 0
May 2002 1.0 0 182 0 0
Jun 2002 1.0 0 182 0 0
[LINE GRAPH]
[LINE GRAPH]
114
SUMMARY
Westerra 2000
131/16-23-049-28W3/0
Cedar Lloydminster C16-23-49-28
Lloydminster Colony
Proved Producing
As Of Date January 1, 2002
Prediction Date January 31, 2002
Saskatchewan
UWI 131/16-23-049-28W3/0
Net No. Xxxxx 0.60
Average WI 60%
Average Royalty 15%
Price Schedule ATB 2001 Q4
Price File Saskatchewan
Econ. Limit Enabled
GCA Applied Yes
BOE Ratio 10:1
[BAR CHART]
COMPANY WI SHARE NET PRESENT WORTH VALUE BEFORE TAX (M$) PRICE
----------------- -------------------------------------------------------- ------
REMAINING GROSS NET 8.0% 10.0% 12.0% 15.0% 20.0% YEAR 1
--------- ----- --- ---- ----- ----- ----- ----- ------
Oil (mbbl) (1:10) -- -- -- -- -- -- -- -- --
Gas (mmcf) 663.1 397.9 338.2 424.5 390.3 361.0 324.2 276.8 2.86
NGL (mbbl) (1:1) -- -- -- -- -- -- -- -- --
C2 (mbbl) (1:1) -- -- -- -- -- -- -- -- --
C3 (mbbl) (1:1) -- -- -- -- -- -- -- -- --
C4 (mbbl) (1:1) -- -- -- -- -- -- -- -- --
C5+ (mbbl) (1:1) -- -- -- -- -- -- -- -- --
Sulphur (mlt) (1:1) -- -- -- -- -- -- -- -- --
----------------------------------------------------------------------------------------------------------------------------------
TOTALS (mboe) 66.3 39.8 33.8 424.5 390.3 361.0 324.2 276.8
AFTER TAX 263.0 240.9 222.0 198.4 168.2
CAPITAL COSTS (M$)
GROSS NET
----- ---
CEE -- --
CDE -- --
CCA -- --
COGPE -- --
Abandonment -- --
----------------------------------------
Total -- --
CASH FLOW (M$)
GROSS NET
----- ---
Revenue 2,518.1 1,510.9
Royalties 530.1 318.1
Op. Costs 831.4 498.8
Capital -- --
ARTC -- --
----------------------------------------
Before Tax 1,156.6 694.0
ECONOMIC INDICATORS
BEFORE TAX AFTER TAX
---------- ---------
Rate of Return (%) -- --
Payout (yrs) -- --
P/I - 0.0% Discount -- --
P/I - 12.0% Discount -- --
Op. Cost ($/boe) 7.5 --
Cap. Cost ($/boe) -- --
ANNUAL CASH FLOW
GROSS ROYALTY OPERATING CAPITAL BTAX NET BTAX TAX ATAX NET ATAX
WELL RATE PRICE REVENUE & TAXES COST COST ARTC REVENUE NET CUM PAID REVENUE NET CUM
YEAR COUNT mcf/d $/mcf M$ M$ M$ M$ M$ M$ M$ M$ M$ M$
------------------------------------------------------------------------------------------------------------------------------------
2002 0.60 115.5 2.86 120.6 32.5 32.5 -- -- 51.2 51.2 21.2 30.0 30.0
2003 0.60 117.2 3.76 160.6 46.2 33.9 -- -- 74.8 126.1 31.1 43.7 73.7
2004 0.60 114.8 3.75 157.7 44.9 34.4 -- -- 72.7 198.8 30.2 42.5 116.2
2005 0.60 104.2 3.85 146.3 39.7 32.6 -- -- 68.7 267.5 27.8 40.9 157.1
2006 0.60 87.0 3.84 122.0 29.5 29.1 -- -- 59.0 326.5 22.6 36.4 193.6
2007 0.60 73.3 3.84 102.6 21.5 26.2 -- -- 51.1 377.7 18.4 32.7 226.3
2008 0.60 62.3 3.83 87.4 16.0 24.0 -- -- 44.2 421.8 15.2 29.0 255.3
2009 0.60 53.5 3.83 74.7 12.0 22.2 -- -- 37.8 459.6 12.4 25.4 280.7
2010 0.60 46.3 3.82 64.5 9.3 20.7 -- -- 32.2 491.9 10.3 22.0 302.6
2011 0.60 40.4 3.87 57.0 8.0 19.5 -- -- 27.4 519.3 8.7 18.8 321.4
REM 0.60 19.6 4.16 417.3 58.3 223.7 -- -- 120.3 639.6 37.5 82.8 404.2
------------------------------------------------------------------------------------------------------------------------------------
TOTAL 45.4 3.80 1,510.9 318.1 498.8 -- -- 639.6 235.4 404.2
115
CEDAR LLOYDMINSTER 00-00-00-00 (101/12-24-049-28W3/0) PROVED PRODUCING - RAW
STATUS Producer: Active gas well ON TIME 95%
FIELD N/A RIG RELEASE Dec 1944
POOL Colony WI 0%
UNIT N/A RLI 0.0
OPERATOR N/A TYPE P-DP
LICENSEE Xxxxxx Oil Company Ltd. Raw
RESERVES (JAN 1, 2002)
ULTIMATE CUMULATIVE REMAINING REMAINING
P-DP RESERVES PRODUCTION GROSS NET
-----------------------------------------------------------------
Oil (mbbl) 0.0 0.0 0.0 0.0
Gas (mmcf) 1,995.7 799.2 1,196.6 0.0
Water (mbbl) 0.0 0.0 0.0 0.0
DECLINES
DECLINE SEGMENT DATE QI DI NI TYPE
-----------------------------------------------------------------
NO DECLINES.
PRODUCTION (6 MO. HISTORY / 6 MO. FORECAST)
DATE WELL CDOR CDGR CDWR LGR
COUNT (BBL/D) (MCF/D) (BBL/D) (BBL/MMCF)
-----------------------------------------------------------------
Feb 1986 1.0 0 80 0 0
Mar 1986 1.0 0 25 0 0
Sep 2001 1.0 0 139 1 6
Oct 2001 1.0 0 331 0 0
Nov 2001 1.0 0 384 0 0
Dec 2001 1.0 0 382 0 0
-----------------------------------------------------------------
Jan 2002 1.0 0 381 0 0
Feb 2002 1.0 0 378 0 0
Mar 2002 1.0 0 311 0 0
Apr 2002 1.0 0 308 0 0
May 2002 1.0 0 307 0 0
Jun 2002 1.0 0 309 0 0
[LINE GRAPH]
[LINE GRAPH]
116
SUMMARY
Westerra 2000
101/12-24-049-28W3/0
Cedar Lloydminster 00-00-00-00
Lloydminster Colony
Proved Producing
As Of Date January 1, 2002
Prediction Date January 31, 2002
Saskatchewan
UWI 101/12-24-049-28W3/0
Net No. Xxxxx 0.60
Average WI 60%
Average Royalty 25%
Price Schedule ATB 2001 Q4
Price File Saskatchewan
Econ. Limit Enabled
GCA Applied Yes
BOE Ratio 10:1
[BAR CHART]
COMPANY WI SHARE NET PRESENT WORTH VALUE BEFORE TAX (M$) PRICE
------------------ --------------------------------------------------- ------
REMAINING GROSS NET 8.0% 10.0% 12.0% 15.0% 20.0% YEAR 1
--------- ----- --- ---- ----- ----- ----- ----- ------
Oil (mbbl) (1:10) -- -- -- -- -- -- -- -- --
Gas (mmcf) 1,184.6 710.8 535.3 809.9 736.6 675.2 599.9 505.9 2.86
NGL (mbbl) (1:1) -- -- -- -- -- -- -- -- --
C2 (mbbl) (1:1) -- -- -- -- -- -- -- -- --
C3 (mbbl) (1:1) -- -- -- -- -- -- -- -- --
C4 (mbbl) (1:1) -- -- -- -- -- -- -- -- --
C5+ (mbbl) (1:1) -- -- -- -- -- -- -- -- --
Sulphur (mlt) (1:1) -- -- -- -- -- -- -- -- --
--------------------------------------------------------------------------------------------------------------------------
TOTALS (MBOE) 118.5 71.1 53.5 809.9 736.6 675.2 599.9 505.9
AFTER TAX 428.0 387.4 353.6 312.5 261.8
CAPITAL COSTS (M$)
GROSS NET
----- ---
CEE -- --
CDE -- --
CCA -- --
COGPE -- --
Abandonment -- --
-------------------------------------
Total -- --
CASH FLOW (M$)
GROSS NET
----- ---
Revenue 4,501.0 2,700.6
Royalties 938.9 563.4
Op. Costs 1,214.7 728.8
Capital -- --
ARTC -- --
----------------------------------------
Before Tax 2,347.5 1,408.5
ECONOMIC INDICATORS
BEFORE TAX AFTER TAX
---------- ---------
Rate of Return (%) -- --
Payout (yrs) -- --
P/I - 0.0% Discount -- --
P/I - 12.0% Discount -- --
Op. Cost ($/boe) 6.2 --
Cap. Cost ($/boe) -- --
ANNUAL CASH FLOW
GROSS ROYALTY OPERATING CAPITAL BTAX NET BTAX ATAX NET ATAX
WELL RATE PRICE REVENUE & TAXES COST COST ARTC REVENUE NET CUM TAX PAID REVENUE NET CUM
YEAR COUNT MCF/D $/MCF M$ M$ M$ M$ M$ M$ M$ M$ M$ M$
-----------------------------------------------------------------------------------------------------------------------------------
2002 0.60 194.0 2.86 202.5 51.6 50.8 -- -- 92.8 92.8 45.6 47.2 47.2
2003 0.60 197.8 3.76 271.2 76.3 53.2 -- -- 131.9 224.8 65.3 66.7 113.8
2004 0.60 195.3 3.75 268.1 74.9 54.3 -- -- 129.3 354.0 64.0 65.3 179.1
2005 0.60 179.9 3.85 252.6 69.2 51.9 -- -- 122.4 476.4 60.3 62.1 241.2
2006 0.60 153.9 3.84 215.9 56.2 46.6 -- -- 105.3 581.7 51.2 54.1 295.4
2007 0.60 132.4 3.84 185.4 45.4 42.2 -- -- 91.1 672.9 43.7 47.5 342.8
2008 0.60 114.6 3.83 160.7 36.7 38.6 -- -- 79.6 752.5 37.6 42.1 384.9
2009 0.60 99.9 3.83 139.6 29.3 35.5 -- -- 69.8 822.3 32.3 37.4 422.4
2010 0.60 87.8 3.82 122.4 23.3 33.0 -- -- 61.7 884.0 27.8 33.9 456.3
2011 0.60 77.6 3.87 109.5 18.8 30.9 -- -- 56.0 940.0 24.4 31.5 487.8
REM. 0.60 41.6 4.12 772.5 81.6 291.8 -- -- 371.3 1,311.2 146.5 224.7 712.5
-----------------------------------------------------------------------------------------------------------------------------------
TOTAL 87.1 3.80 2,700.6 563.4 728.8 -- -- 1,311.2 598.7 712.5
117
CEDAR LLOYDMINSTER B13-24-49-28 (121/13-24-049-28W3/0) PROVED PRODUCING - RAW
STATUS Producer: Active gas well ON TIME 99%
FIELD N/A RIG RELEASE Aug 1946
POOL Colony WI 0%
UNIT N/A RLI 0.0
OPERATOR N/A TYPE P-DP
LICENSEE Xxxxxx Oil Company Ltd. Raw
RESERVES (JAN 1, 2002)
ULTIMATE CUMULATIVE REMAINING REMAINING
P-DP RESERVES PRODUCTION GROSS NET
-------------------------------------------------------------------
Oil (mbbl) 0.0 0.0 0.0 0.0
Gas (mmcf) 1,064.1 975.5 88.6 0.0
Water (mbbl) 0.1 0.1 0.0 0.0
DECLINES
DECLINE SEGMENT DATE QI DI NI TYPE
-------------------------------------------------------------------
NO DECLINES.
PRODUCTION (6 MO. HISTORY / 6 MO. FORECAST)
DATE WELL CDOR CDGR CDWR LGR
COUNT (BBL/D) (MCF/D) (BBL/D) (BBL/MMCF)
----------------------------------------------------------------
Mar 1996 1.0 0 89 0 0
Apr 1996 1.0 0 11 0 0
Sep 2001 1.0 0 112 5 41
Oct 2001 1.0 0 313 0 0
Nov 2001 1.0 0 297 0 0
Dec 2001 1.0 0 118 0 0
----------------------------------------------------------------
Jan 2002 1.0 0 113 0 0
Feb 2002 1.0 0 111 0 0
Mar 2002 1.0 0 90 0 0
Apr 2002 1.0 0 87 0 0
May 2002 1.0 0 85 0 0
Jun 2002 1.0 0 84 0 0
[LINE GRAPH]
[LINE GRAPH]
118
SUMMARY
Westerra 2000
121/13-24-049-28W3/0
Cedar Lloydminster B13-24-49-28
Lloydminster Colony
Proved Producing
As Of Date January 1, 2002
Prediction Date January 31, 2002
Saskatchewan
UWI 121/13-24-049-28W3/0
Net No. Xxxxx 0.60
Average WI 60%
Average Royalty 10%
Price Schedule ATB 2001 Q4
Price File Saskatchewan
Econ. Limit Enabled
GCA Applied Yes
BOE Ratio 10:1
[BAR CHART]
COMPANY WI SHARE NET PRESENT WORTH VALUE BEFORE TAX (M$) PRICE
----------------- ----------------------------------------------------- ------
REMAINING GROSS NET 8.0% 10.0% 12.0% 15.0% 20.0% YEAR 1
--------- ----- --- ---- ----- ----- ----- ----- ------
Oil (mbbl) (1:10) -- -- -- -- -- -- -- -- --
Gas (mmcf) 87.8 52.7 47.2 84.5 81.9 79.6 76.3 71.3 2.86
NGL (mbbl) (1:1) -- -- -- -- -- -- -- -- --
C2 (mbbl) (1:1) -- -- -- -- -- -- -- -- --
C3 (mbbl) (1:1) -- -- -- -- -- -- -- -- --
C4 (mbbl) (1:1) -- -- -- -- -- -- -- -- --
C5+ (mbbl) (1:1) -- -- -- -- -- -- -- -- --
Sulphur (mlt) (1:1) -- -- -- -- -- -- -- -- --
-------------------------------------------------------------------------------------------------------------------------------
TOTALS (MBOE) 8.8 5.3 4.7 84.5 81.9 79.6 76.3 71.3
AFTER TAX 53.0 51.3 49.8 47.6 44.5
CAPITAL COSTS (M$)
GROSS NET
----- ---
CEE -- --
CDE -- --
CCA -- --
COGPE -- --
Abandonment -- --
----------------------------------------
Total -- --
CASH FLOW (M$)
GROSS NET
----- ---
Revenue 302.5 181.5
Royalties 26.3 15.8
Op. Costs 104.7 62.8
Capital -- --
ARTC -- --
------------------------------------
Before Tax 171.4 102.8
ECONOMIC INDICATORS
BEFORE TAX AFTER TAX
---------- ---------
Rate of Return (%) -- --
Payout (yrs) -- --
P/I - 0.0% Discount -- --
P/I - 12.0% Discount -- --
Op. Cost ($/boe) 7.2 --
Cap. Cost ($/boe) -- --
ANNUAL CASH FLOW
GROSS ROYALTY OPERATING CAPITAL BTAX NET BTAX ATAX NET ATAX
WELL RATE PRICE REVENUE & TAXES COST COST ARTC REVENUE NET CUM TAX PAID REVENUE NET CUM
YEAR COUNT MCF/D $/MCF M$ M$ M$ M$ M$ M$ M$ M$ M$ M$
------------------------------------------------------------------------------------------------------------------------------------
2002 0.60 52.1 2.86 54.4 6.2 17.7 -- -- 28.5 28.5 11.4 17.2 17.2
2003 0.60 40.0 3.76 54.9 5.4 15.3 -- -- 32.2 60.7 12.3 19.9 37.1
2004 0.60 27.8 3.75 38.2 2.7 12.8 -- -- 21.2 82.0 7.9 13.4 50.5
2005 0.60 16.9 3.85 23.8 1.2 10.4 -- -- 11.4 93.4 4.1 7.3 57.7
2006 0.60 9.8 3.84 10.3 0.3 6.6 -- -- 3.0 96.3 -- 3.0 60.7
------------------------------------------------------------------------------------------------------------------------------------
TOTAL 30.4 3.45 181.5 15.8 62.8 -- -- 96.3 35.6 60.7
119
CEDAR LLOYDMINSTER C15-24-49-28 (131/15-24-049-28W3/0) PROVED PRODUCING - RAW
STATUS Producer: Inactive gas ON TIME 100%
well
FIELD N/A RIG RELEASE Mar 1945
POOL Colony WI 0%
UNIT N/A RLI 0.0
OPERATOR N/A TYPE P-DP
LICENSEE Xxxxxx Oil Company Ltd. Raw
RESERVES (JAN 1, 2002)
ULTIMATE CUMULATIVE REMAINING REMAINING
P-DP RESERVES PRODUCTION GROSS NET
-----------------------------------------------------------------
Oil (mbbl) 0.0 0.0 0.0 0.0
Gas (mmcf) 1,470.2 499.2 971.0 0.0
Water (mbbl) 0.0 0.0 0.0 0.0
DECLINES
DECLINE SEGMENT DATE QI DI NI TYPE
-----------------------------------------------------------------
No Declines.
PRODUCTION (6 MO. HISTORY / 6 MO. FORECAST)
DATE WELL CDOR CDGR CDWR LGR
COUNT (BBL/D) (MCF/D) (BBL/D) (BBL/MMCF)
----------------------------------------------------------------
Mar 1981 1.0 0 35 0 0
Nov 1982 1.0 0 3 0 0
Dec 1982 1.0 0 16 0 0
Jan 1983 1.0 0 58 0 0
Feb 1983 1.0 0 15 0 0
Aug 1983 1.0 0 3 0 0
----------------------------------------------------------------
Mar 2002 1.0 0 349 0 0
Apr 2002 1.0 0 345 0 0
May 2002 1.0 0 346 0 0
Jun 2002 1.0 0 346 0 0
Jul 2002 1.0 0 355 0 0
Aug 2002 1.0 0 353 0 0
[LINE GRAPH]
[LINE GRAPH]
120
SUMMARY
Westerra 2000
131/15-24-049-28W3/0
Cedar Lloydminster C15-24-49-28
Lloydminster Colony
PROVED PRODUCING
As Of Date January 1, 2002
Prediction Date Xxxxx 00, 0000
Xxxxxxxxxxxx
UWI 131/15-24-049-28W3/0
Net No. Xxxxx 0.60
Average WI 60%
Average Royalty 15%
Price Schedule ATB 2001 Q4
Price File Saskatchewan
Econ. Limit Enabled
GCA Applied Yes
BOE Ratio 10:1
[BAR GRAPH]
COMPANY WI SHARE NET PRESENT WORTH VALUE BEFORE TAX (M$) PRICE
------------------ --------------------------------------------------------- ------
REMAINING GROSS NET 8.0% 10.0% 12.0% 15.0% 20.0% YEAR 1
--------- ----- --- ---- ----- ----- ----- ----- ------
Oil (mbbl) (1:10) -- -- -- -- -- -- -- -- --
Gas (mmcf) 961.3 576.8 490.2 651.3 607.0 567.7 516.3 446.9 2.86
NGL (mbbl) (1:1) -- -- -- -- -- -- -- -- --
C2 (mbbl) (1:1) -- -- -- -- -- -- -- -- --
C3 (mbbl) (1:1) -- -- -- -- -- -- -- -- --
C4 (mbbl) (1:1) -- -- -- -- -- -- -- -- --
C5+ (mbbl) (1:1) -- -- -- -- -- -- -- -- --
Sulphur (mlt) (1:1) -- -- -- -- -- -- -- -- --
------------------------------------------------------------------------------------------------------------------------------------
TOTALS (MBOE) 96.1 57.7 49.0 651.3 607.0 567.7 516.3 446.9
AFTER TAX 356.6 331.5 309.3 280.4 241.6
CAPITAL COSTS (M$)
GROSS NET
----- ---
CEE -- --
CDE -- --
CCA -- --
COGPE -- --
Abandonment -- --
------------------------------
Total -- --
CASH FLOW (M$)
GROSS NET
----- ---
Revenue 3,566.0 2,139.6
Royalties 1,113.5 668.1
Op. Costs 829.5 497.7
Capital -- --
ARTC -- --
----------------------------------------
Before Tax 1,622.9 973.7
ECONOMIC INDICATORS
BEFORE TAX AFTER TAX
---------- ---------
Rate of Return (%) -- --
Payout (yrs) -- --
P/I - 0.0% Discount -- --
P/I - 12.0% Discount -- --
Op. Cost ($/boe) 5.2 --
Cap. Cost ($/boe) -- --
ANNUAL CASH FLOW
GROSS ROYALTY OPERATING CAPITAL BTAX NET BTAX ATAX NET ATAX
WELL RATE PRICE REVENUE & TAXES COST COST ARTC REVENUE NET CUM TAX PAID REVENUE NET CUM
YEAR COUNT MCF/D $/MCF M$ M$ M$ M$ M$ M$ M$ M$ M$ M$
-----------------------------------------------------------------------------------------------------------------------------------
2002 0.60 210.5 2.86 184.2 60.2 45.8 -- -- 71.6 71 .6 -- -- --
2003 0.60 219.6 3.76 301.0 105.1 58.4 -- -- 126.7 198.3 59.7 67.0 67.0
2004 0.60 219.5 3.75 301.4 105.1 60.3 -- -- 125.0 323.3 59.1 65.9 132.9
2005 0.60 207.1 3.85 290.8 100.5 58.8 -- -- 121.0 444.3 57.0 64.0 196.9
2006 0.60 183.7 3.84 257.6 86.5 54.5 -- -- 107.4 551.7 49.9 57.4 254.3
2007 0.60 159.5 3.84 223.5 72.1 49.6 -- -- 93.8 645.4 42.6 51.2 305.5
2008 0.60 132.7 3.83 186.2 56.4 43.7 -- -- 79.4 724.8 34.7 44.6 350.1
2009 0.60 103.4 3.83 144.4 38.9 36.5 -- -- 63.9 788.7 26.1 37.7 387.9
2010 0.60 73.6 3.82 102.7 21.7 28.8 -- -- 48.5 837.2 17.7 30.9 418.7
2011 0.60 48.0 3.87 67.8 10.3 21.9 -- -- 33.1 870.4 10.7 22.4 441.1
REM. 0.60 19.6 3.94 80.0 11.2 39.5 -- -- 26.4 896.7 7.9 18.4 459.5
-----------------------------------------------------------------------------------------------------------------------------------
TOTAL 124.6 3.71 2,139.6 668.1 497.7 -- -- 896.7 365.6 459.5
121
CEDAR LLOYDMINSTER B2-25-49-28 (121/02-25-049-28W3/0) PROVED PRODUCING - RAW
STATUS Producer: Active gas well ON TIME 100%
FIELD N/A RIG RELEASE Jun 1948
POOL Colony WI 0%
UNIT N/A RLI 0.0
OPERATOR N/A TYPE P-DP
LICENSEE Xxxxxx Oil Company Ltd. Raw
RESERVES (JAN 1, 2002)
ULTIMATE CUMULATIVE REMAINING REMAINING
P-DP RESERVES PRODUCTION GROSS NET
--------------------------------------------------------------------------------
Oil (mbbl) 0.0 0.0 0.0 0.0
Gas (mmcf) 659.6 509.4 150.2 0.0
Water (mbbl) 0.1 0.1 0.0 0.0
DECLINES
DECLINE SEGMENT DATE QI DI NI TYPE
--------------------------------------------------------------------------------
NO DECLINES.
PRODUCTION (6 MO. HISTORY / 6 MO. FORECAST)
DATE WELL CDOR CDGR CDWR LGR
COUNT (BBL/D) (MCF/D) (BBL/D) (BBL/MMCF)
--------------------------------------------------------------------------------
Feb 1977 1.0 0 0 0 0
Nov 1980 1.0 0 45 0 0
Sep 2001 1.0 0 85 3 35
Oct 2001 1.0 0 252 0 0
Nov 2001 1.0 0 228 0 0
Dec 2001 1.0 0 168 0 0
Jan 2002 1.0 0 151 0 0
Feb 2002 1.0 0 149 0 0
Mar 2002 1.0 0 125 0 0
Apr 2002 1.0 0 123 0 0
May 2002 1.0 0 121 0 0
Jun 2002 1.0 0 121 0 0
[LINE GRAPH]
[LINE GRAPH]
122
SUMMARY
Westerra 2000
121/02-25-049-28W3/0
Cedar Lloydminster B2-25-49-28
Lloydminster Colony
Proved Producing
As Of Date January 1, 2002
Prediction Date January 31, 2002
Saskatchewan
UWI 121/02-25-049-28W3/0
Net No. Xxxxx 0.60
Average WI 60%
Average Royalty 13%
Price Schedule ATB 2001 Q4
Price File Saskatchewan
Econ. Limit Enabled
GCA Applied Yes
BOE Ratio 10:1
[BAR CHART]
COMPANY WI SHARE NET PRESENT WORTH VALUE BEFORE TAX (M$) PRICE
---------------- --------------------------------------------- ------
REMAINING GROSS NET 8.0% 10.0% 12.0% 15.0% 20.0% YEAR 1
--------- ----- --- ---- ----- ----- ----- ----- ------
Oil (mbbl) (1:10) - - - - - - - - -
Gas (mmcf) 148.7 89.2 78.1 137.6 132.8 128.4 122.3 113.2 2.86
NGL (mbbl) (1:1) - - - - - - - - -
C2 (mbbl) (1:1) - - - - - - - - -
C3 (mbbl) (1:1) - - - - - - - - -
C4 (mbbl) (1:1) - - - - - - - - -
C5+ (mbbl) (1:1) - - - - - - - - -
Sulphur (mlt) (1:1) - - - - - - - - -
------- ----- ---- ----- ----- ----- ----- ----- ------
TOTALS (mboe) 14.9 8.9 7.8 137.6 132.8 128.4 122.3 113.2
AFTER TAX 91.2 87.9 84.9 80.8 74.7
CAPITAL COSTS (M$) CASH FLOW (M$) ECONOMIC INDICATORS
------------------------------------- ----------------------------------- ----------------------------------------------
GROSS NET GROSS NET BEFORE TAX AFTER TAX
----- --- ----- --- ---------- ---------
CEE - - Revenue 521.1 312.6 Rate of Return (%) - -
CDE - - Royalties 76.8 46.1 Payout (yrs) - -
CCA - - Op. Costs 158.5 95.1 P/I - 0.0% Discount - -
COGPE - - Capital - - P/I - 12.0% Discount - -
Abandonment - - ARTC - - Op. Cost ($/boe) 6.4 -
---- --- ----------- ----- ----- Cap. Cost ($/boe) - -
Total - - Before Tax 285.8 171.5
ANNUAL CASH FLOW
GROSS ROYALTY OPERATING CAPITAL BTAX NET BTAX ATAX NET ATAX
WELL RATE PRICE REVENUE & TAXES COST COST ARTC REVENUE NET CUM TAX PAID REVENUE NET CUM
YEAR COUNT MCF/D $/MCF M$ M$ M$ M$ M$ M$ M$ M$ M$ M$
--------------------------------------------------------------------------------------------------------------------------------
2002 0.60 74.2 2.86 77.5 13.8 22.9 - - 38.1 38.1 13.8 24.3 24.3
2003 0.60 63.2 3.76 86.6 14.0 20.9 - - 48.5 86.6 16.8 31.7 56.0
2004 0.60 48.3 3.75 66.3 8.5 17.9 - - 37.5 124.2 12.3 25.3 81.3
2005 0.60 31.6 3.85 44.4 5.3 14.1 - - 23.4 147.6 7.5 15.9 97.2
2006 0.60 17.8 3.84 25.0 3.0 10.9 - - 10.2 157.8 3.3 6.9 104.1
2007 0.60 10.0 3.84 12.8 1.5 8.4 - - 2.5 160.2 - 2.5 106.6
--------------------------------------------------------------------------------------------------------------------------------
TOTAL 41.3 3.50 312.6 46.1 95.1 - - 160.2 53.7 106.6
123
CEDAR LLOYDMINSTER B6-25-49-28 (121/06-25-049-28W3/0) PROVED PRODUCING - RAW
STATUS Producer: Active gas well ON TIME 100%
FIELD N/A RIG RELEASE Oct 1947
POOL Colony WI 0%
UNIT N/A RLI 0.0
OPERATOR N/A TYPE P-DP
LICENSEE Xxxxxx Oil Company Ltd. Raw
RESERVES (JAN 1, 2002)
ULTIMATE CUMULATIVE REMAINING REMAINING
P-DP RESERVES PRODUCTION GROSS NET
--------------------------------------------------------------------------------
Oil (mbbl) 0.0 0.0 0.0 0.0
Gas (mmcf) 995.8 843.1 152.7 0.0
Water (mbbl) 0.2 0.2 0.0 0.0
DECLINES
DECLINE SEGMENT DATE QI DI NI TYPE
--------------------------------------------------------------------------------
NO DECLINES.
PRODUCTION (6 MO. HISTORY / 6 MO. FORECAST)
DATE WELL CDOR CDGR CDWR LGR
COUNT (BBL/D) (MCF/D) (BBL/D) (BBL/MMCF)
--------------------------------------------------------------------------------
Nov 1995 1.0 0 4 0 0
Dec 1995 1.0 0 4 0 0
Sep 2001 1.0 0 112 1 7
Oct 2001 1.0 0 283 0 0
Nov 2001 1.0 0 257 0 0
Dec 2001 1.0 0 184 0 0
--------------------------------------------------------------------------------
Jan 2002 1.0 0 165 0 0
Feb 2002 1.0 0 161 0 0
Mar 2002 1.0 0 135 0 0
Apr 2002 1.0 0 132 0 0
May 2002 1.0 0 130 0 0
Jun 2002 1.0 0 128 0 0
[LINE GRAPH]
[LINE GRAPH]
124
SUMMARY
Westerra 2000
121/06-25-049-28W3/0
Cedar Lloydminster B6-25-49-28
Lloydminster Colony
Proved Producing
As Of Date January 1, 2002
Prediction Date January 31, 2002
Saskatchewan
UWI 121/06-25-049-28W3/0
Net No. Xxxxx 0.60
Average WI 60%
Average Royalty 13%
Price Schedule ATB 2001 Q4
Price File Saskatchewan
Econ. Limit Enabled
GCA Applied Yes
BOE Ratio 10:1
[BAR GRAPH]
COMPANY WI SHARE NET PRESENT WORTH VALUE BEFORE TAX (M$) PRICE
---------------- ----------------------------------------- ------
REMAINING GROSS NET 8.0% 10.0% 12.0% 15.0% 20.0% YEAR 1
--------- ----- --- ---- ----- ----- ----- ----- ------
Oil (mbbl) (1:10) - - - - - - - - -
Gas (mmcf) 151.2 90.7 79.4 139.4 134.7 130.3 124.2 115.3 2.86
NGL (mbbl) (1:1) - - - - - - - - -
C2 (mbbl) (1:1) - - - - - - - - -
C3 (mbbl) (1:1) - - - - - - - - -
C4 (mbbl) (1:1) - - - - - - - - -
C5+ (mbbl) (1:1) - - - - - - - - -
Sulphur (mlt) (1:1) - - - - - - - - -
-----------------------------------------------------------------------------------------------------------------------------
TOTALS (MBOE) 15.1 9.1 7.9 139.4 134.7 130.3 124.2 115.3
AFTER TAX 91.7 88.5 85.6 81.5 75.5
CAPITAL COSTS (M$) CASH FLOW (M$) ECONOMIC INDICATORS
------------------------------------- ------------------------------- -----------------------------------------------
GROSS NET GROSS NET BEFORE TAX AFTER TAX
----- --- ----- --- ---------- ---------
CEE - - Revenue 527.3 316.4 Rate of Return (%) - -
CDE - - Royalties 80.8 48.5 Payout (yrs) - -
CCA - - Op. Costs 158.1 94.9 P/I - 0.0% Discount - -
COGPE - - Capital - - P/I - 12.0% Discount - -
Abandonment - - ARTC - - Op. Cost ($/boe) 6.3 -
------------------------------------------------------------------------- Cap. Cost ($/boe) - -
Total - - Before Tax 288.4 173.0
ANNUAL CASH FLOW
GROSS ROYALTY OPERATING CAPITAL BTAX NET BTAX ATAX NET ATAX
WELL RATE PRICE REVENUE & TAXES COST COST ARTC REVENUE NET CUM TAX PAID REVENUE NET CUM
YEAR COUNT MCF/D $/MCF M$ M$ M$ M$ M$ M$ M$ M$ M$ M$
---------------------------------------------------------------------------------------------------------------------------
2002 0.60 79.5 2.86 83.0 15.7 24.1 - - 40.2 40.2 14.9 25.3 25.3
2003 0.60 65.4 3.76 89.7 15.0 21.4 - - 50.0 90.2 17.5 32.5 57.8
2004 0.60 48.3 3.75 66.4 8.6 17.9 - - 37.5 127.7 12.3 25.2 83.1
2005 0.60 30.7 3.85 43.2 5.1 13.9 - - 22.6 150.3 7.3 15.3 98.4
2006 0.60 17.0 3.84 23.8 2.8 10.7 - - 9.4 159.7 3.0 6.4 104.8
2007 0.60 9.9 3.84 10.4 1.2 6.8 - - 1.9 161.7 - 1.9 106.7
---------------------------------------------------------------------------------------------------------------------------
TOTAL 43.2 3.49 316.4 48.5 94.9 - - 161.7 54.9 106.7
125
CEDAR LLOYDMINSTER C13-25-49-28 (131/13-25-049-28W3/0) PROVED PRODUCING - RAW
STATUS Producer: Active gas well ON TIME 99%
FIELD N/A RIG RELEASE Jul 1935
POOL Colony WI 0%
UNIT N/A RLI 0.0
OPERATOR N/A TYPE P-DP
LICENSEE Xxxxxx Oil Company Ltd. Raw
RESERVES (JAN 1, 2002)
ULTIMATE CUMULATIVE REMAINING REMAINING
P-DP RESERVES PRODUCTION GROSS NET
--------------------------------------------------------------------------------
Oil (mbbl) 0.0 0.0 0.0 0.0
Gas (mmcf) 2,299.3 1,234.8 1,064.6 0.0
Water (mbbl) 0.0 0.0 0.0 0.0
DECLINES
DECLINE SEGMENT DATE QI DI NI TYPE
--------------------------------------------------------------------------------
No Declines.
PRODUCTION (6 MO. HISTORY / 6 MO. FORECAST)
DATE WELL CDOR CDGR CDWR LGR
COUNT (BBL/D) (MCF/D) (BBL/D) (BBL/MMCF)
--------------------------------------------------------------------------------
Feb 1989 1.0 0 44 0 0
Mar 1989 1.0 0 39 0 0
Sep 2001 1.0 0 83 0 0
Oct 2001 1.0 0 237 0 0
Nov 2001 1.0 0 255 0 0
Dec 2001 1.0 0 313 0 0
--------------------------------------------------------------------------------
Jan 2002 1.0 0 278 0 0
Feb 2002 1.0 0 276 0 0
Mar 2002 1.0 0 232 0 0
Apr 2002 1.0 0 228 0 0
May 2002 1.0 0 228 0 0
Jun 2002 1.0 0 228 0 0
[BAR GRAPH]
[BAR GRAPH]
126
SUMMARY
Westerra 2000
131/13-25-049-28W3/0
Cedar Xxxxxxxxxxxx X00-00-00-00
X/X Xxxxxxxxxxxx Xxxxxx
X/X
Proved Producing
As Of Date January 1, 2002
Prediction Date January 31, 2002
Saskatchewan
UWI 131/13-25-049-28W3/0
Net No. Xxxxx 0.60
Average WI 60%
Average Royalty 13%
Price Schedule ATB 2001 Q4
Price File Saskatchewan
Econ. Limit Enabled
GCA Applied Yes
BOE Ratio 10:1
[BAR GRAPH]
COMPANY WI SHARE NET PRESENT WORTH VALUE BEFORE TAX (M$) PRICE
----------------------- --------------------------------------------------------- --------
REMAINING GROSS NET 8.0% 10.0% 12.0% 15.0% 20.0% YEAR 1
--------- ----- --- ---- ----- ----- ----- ----- ------
Oil (mbbl) (1:10) -- -- -- -- -- -- -- -- --
Gas (mmcf) 1,053.9 632.4 553.3 630.6 568.1 516.7 454.9 379.4 2.86
NGL (mbbl) (1:1) -- -- -- -- -- -- -- -- --
C2 (mbbl) (1:1) -- -- -- -- -- -- -- -- --
C3 (mbbl) (1:1) -- -- -- -- -- -- -- -- --
C4 (mbbl) (1:1) -- -- -- -- -- -- -- -- --
C5+ (mbbl) (1:1) -- -- -- -- -- -- -- -- --
Sulphur (mlt) (1:1) -- -- -- -- -- -- -- -- --
-------------------------------------------------------------------------------------------------------------------------------
TOTALS (MBOE) 105.4 63.2 55.3 630.6 568.1 516.7 454.9 379.4
AFTER TAX 375.8 336.5 304.5 266.2 220.1
CAPITAL COSTS (M$) CASH FLOW (M$) ECONOMIC INDICATORS
----------------------------------------- --------------------------------- --------------------------------------------
GROSS NET GROSS NET BEFORE TAX AFTER TAX
----- --- ----- --- ---------- ---------
CEE -- -- Revenue 4,132.1 2,479.3 Rate of Return (%) -- --
CDE -- -- Royalties 842.7 505.6 Payout (yrs) -- --
CCA -- -- Op. Costs 1,308.9 785.3 P/I - 0.0% Discount -- --
COGPE -- -- Capital -- -- P/I - 12.0% Discount -- --
Abandonment -- -- ARTC -- -- Op. Cost ($/boe) 7.5 --
Cap. Cost ($/boe) -- --
----------------------------------------- ---------------------------------
Total -- -- Before Tax 1,980.5 1,188.3
ANNUAL CASH FLOW
-------------------------------------------------
GROSS ROYALTY OPERATING CAPITAL
WELL RATE PRICE REVENUE & TAXES COST COST ARTC
YEAR COUNT MCF/D $/MCF M$ M$ M$ M$ M$
----------------------------------------------------------------------------------------------------------------------------
2002 0. 60 143.6 2.86 149.9 40.6 39.0 -- --
2003 0. 60 147.7 3.76 202.5 58.9 41.2 -- --
2004 0. 60 147.9 3.75 203.1 59.1 42.6 -- --
2005 0. 60 138.4 3.85 194.4 55.4 41.3 -- --
2006 0. 60 121.3 3.84 170.1 45.7 38.1 -- --
2007 0. 60 106.3 3.84 148.9 37.3 35.2 -- --
2008 0. 60 93.8 3.83 131.6 30.4 32.8 -- --
2009 0. 60 83.3 3.83 116.3 24.4 30.7 -- --
2010 0. 60 74.4 3.82 103.8 19.5 29.0 -- --
2011 0. 60 66.7 3.87 94.1 16.0 27.5 -- --
REM. 0. 60 27.6 4.34 964.5 118.3 42 7.9 -- --
----------------------------------------------------------------------------------------------------------------------------
TOTAL 54.1 3.92 2,479.3 505.6 785.3 -- --
BTAX NET BTAX ATAX NET ATAX
REVENUE NET CUM TAX PAID REVENUE NET CUM
YEAR M$ M$ M$ M$ M$
----------------------------------------------------------------------------
2002 64.8 64.8 28.3 36.5 36.5
2003 95.1 159.9 41.8 53.3 89.8
2004 94.1 254.0 41.5 52.5 142.4
2005 90.7 344.7 39.6 51.1 193.5
2006 80.2 424.9 34.0 46.2 239.7
2007 71.1 496.0 29.2 41.9 281.6
2008 63.6 559.6 25.3 38.4 319.9
2009 57.1 616.7 21.8 35.3 355.2
2010 51.5 668.2 18.9 32.6 387.8
2011 47.2 715.5 16.8 30.5 418.3
REM. 383.6 1,099.1 125.1 258.5 676.8
----------------------------------------------------------------------------
TOTAL 1,099.1 422.3 676.8
127
CEDAR LLOYDMINSTER B1-26-49-28 (121/01-26-049-28W3/0) PROVED PRODUCING - RAW
STATUS Producer: Active gas well ON TIME 100%
FIELD N/A RIG RELEASE Aug 1938
POOL Colony WI 0%
UNIT N/A RLI 0.0
OPERATOR N/A TYPE P-DP
LICENSEE Xxxxxx Oil Company Ltd. Raw
RESERVES (JAN 1, 2002)
ULTIMATE CUMULATIVE REMAINING REMAINING
P-DP RESERVES PRODUCTION GROSS NET
--------------------------------------------------------------------------------
Oil (mbbl) 0.0 0.0 0.0 0.0
Gas (mmcf) 2,504.5 1,237.4 1,267.1 0.0
Water (mbbl) 0.0 0.0 0.0 0.0
DECLINES
DECLINE SEGMENT DATE QI DI NI TYPE
--------------------------------------------------------------------------------
NO DECLINES.
PRODUCTION (6 MO. HISTORY / 6 MO. FORECAST)
DATE WELL CDOR CDGR CDWR LGR
COUNT (BBL/D) (MCF/D) (BBL/D) (BBL/MMCF)
--------------------------------------------------------------------------------
Feb 1986 1.0 0 35 0 0
Mar 1986 1.0 0 12 0 0
Sep 2001 1.0 0 164 0 0
Oct 2001 1.0 0 338 0 0
Nov 2001 1.0 0 329 0 0
Dec 2001 1.0 0 370 0 0
--------------------------------------------------------------------------------
Jan 2002 1.0 0 483 0 0
Feb 2002 1.0 0 478 0 0
Mar 2002 1.0 0 370 0 0
Apr 2002 1.0 0 362 0 0
May 2002 1.0 0 360 0 0
Jun 2002 1.0 0 362 0 0
[BAR/LINE GRAPH]
[LINE GRAPH]
128
SUMMARY
Westerra 2000
121/01-26-049-28W3/0
Cedar Xxxxxxxxxxxx X0-00-00-00
X/X Xxxxxxxxxxxx Xxxxxx
X/X
Proved Producing
As Of Date January 1, 2002
Prediction Date January 31, 2002
Saskatchewan
UWI 121/01-26-049-28W3/0
Net No. Xxxxx 0.60
Average WI 60%
Average Royalty 0%
Price Schedule ATB 2001 Q4
Price File Saskatchewan
Econ. Limit Enabled
GCA Applied Yes
BOE Ratio 10:1
[BAR CHART]
COMPANY WI SHARE NET PRESENT WORTH VALUE BEFORE TAX (M$) PRICE
----------------------- -------------------------------------------------------- ---------
REMAINING GROSS NET 8.0% 10.0% 12.0% 15.0% 20.0% YEAR 1
--------- ----- --- ---- ----- ----- ----- ----- ------
Oil (mbbl) (1:10) -- -- -- -- -- -- -- -- --
Gas (mmcf) 1,254.4 752.6 751.4 991.3 907.3 836.8 749.8 640.2 2.86
NGL (mbbl) (1:1) -- -- -- -- -- -- -- -- --
C2 (mbbl) (1:1) -- -- -- -- -- -- -- -- --
C3 (mbbl) (1:1) -- -- -- -- -- -- -- -- --
C4 (mbbl) (1:1) -- -- -- -- -- -- -- -- --
C5+ (mbbl) (1:1) -- -- -- -- -- -- -- -- --
Sulphur (mlt) (1:1) -- -- -- -- -- -- -- -- --
-------------------------------------------------------------------------------------------------------------------------------
TOTALS (MBOE) 125.4 75.3 75.1 991.3 907.3 836.8 749.8 640.2
AFTER TAX 560.6 510.4 468.6 417.4 353.7
CAPITAL COSTS (M$) CASH FLOW (M$) ECONOMIC INDICATORS
----------------------------------------- ---------------------------------- --------------------------------------------
GROSS NET GROSS NET BEFORE TAX AFTER TAX
----- --- ----- --- ---------- ---------
CEE -- -- Revenue 4,790.7 2,874.4 Rate of Return (%) -- --
CDE -- -- Royalties 611.3 366.8 Payout (yrs) -- --
CCA -- -- Op. Costs 1,383.8 830.3 P/I - 0.0% Discount -- --
COGPE -- -- Capital -- -- P/I - 12.0% Discount -- --
Abandonment -- -- ARTC -- -- Op. Cost ($/boe) 6.6 --
Cap. Cost ($/boe) -- --
--------------------------------------------------------------------------------
Total -- -- Before Tax 2,795.7 1,677.4
ANNUAL CASH FLOW
-------------------------------------------------
GROSS ROYALTY OPERATING CAPITAL
WELL RATE PRICE REVENUE & TAXES COST COST ARTC
YEAR COUNT MCF/D $/MCF M$ M$ M$ M$ M$
----------------------------------------------------------------------------------------------------------------------------
2002 0.60 232.1 2.86 242.3 47.1 59.7 -- --
2003 0.60 233.0 3.76 319.4 67.8 61.7 -- --
2004 0.60 225.3 3.75 309.4 65.0 61.8 -- --
2005 0.60 199.8 3.85 280.5 56.8 57.0 -- --
2006 0.60 161.5 3.84 226.5 41.7 48.6 -- --
2007 0.60 132.5 3.84 185.7 30.2 42.3 -- --
2008 0.60 110.5 3.83 155.0 21.7 37.5 -- --
2009 0.60 93.3 3.83 130.3 14.8 33.6 -- --
2010 0.60 79.7 3.82 111.2 9.5 30.6 -- --
2011 0.60 69.0 3.87 97.3 5.8 28.2 -- --
REM. 0.60 27.0 4.27 816.9 6.4 369.5 -- --
----------------------------------------------------------------------------------------------------------------------------
TOTAL 70.1 3.82 2,874.4 366.8 830.3 -- --
BTAX NET BTAX ATAX NET ATAX
REVENUE NET CUM TAX PAID REVENUE NET CUM
YEAR M$ M$ M$ M$ M$
----------------------------------------------------------------------------
2002 126.7 126.7 58.7 68.0 68.0
2003 178.5 305.2 82.7 95.8 163.8
2004 171.4 476.6 79.4 92.0 255.9
2005 156.7 633.3 72.0 84.6 340.5
2006 128.1 761.4 57.4 70.7 411.2
2007 106.5 867.9 46.3 60.2 471.4
2008 90.3 958.1 37.9 52.4 523.8
2009 77.3 1,035.4 31.2 46.1 569.9
2010 67.2 1,102.5 26.0 41.2 611.0
2011 59.8 1,162.3 22.3 37.5 648.5
REM. 411.6 1,573.9 143.3 268.3 916.8
----------------------------------------------------------------------------
TOTAL 1,573.9 657.1 916.8
129
CEDAR ABERFELDY D14-15-49-27 (141/14-15-049-27W3/0) PROVED PRODUCING - RAW
STATUS Producer: Active gas well ON TIME 95%
FIELD N/A RIG RELEASE Jun 1985
POOL Lloydminster WI 0%
UNIT N/A RLI 0.0
OPERATOR N/A TYPE P-DP
LICENSEE Atcor Resources Limited Raw
RESERVES (JAN 1, 2002)
ULTIMATE CUMULATIVE REMAINING REMAINING
P-DP RESERVES PRODUCTION GROSS NET
--------------------------------------------------------------------------------
Oil (mbbl) 0.0 0.0 0.0 0.0
Gas (mmcf) 57.9 56.1 1.8 0.0
Water (mbbl) 0.0 0.0 0.0 0.0
DECLINES
DECLINE SEGMENT DATE QI DI NI TYPE
--------------------------------------------------------------------------------
NO DECLINES.
PRODUCTION (4 MO. HISTORY / 4 MO. FORECAST)
DATE WELL CDOR CDGR CDWR LGR
COUNT (BBL/D) (MCF/D) (BBL/D) (BBL/MMCF)
--------------------------------------------------------------------------------
Sep 2001 1.0 0 565 0 0
Oct 2001 1.0 0 457 0 0
Nov 2001 1.0 0 426 0 0
Dec 2001 1.0 0 395 0 0
--------------------------------------------------------------------------------
Jan 2002 1.0 0 31 0 0
Feb 2002 1.0 0 28 0 0
[LINE GRAPH]
[CHART]
130
SUMMARY
Westerra 2000
141/14-15-049-27W3/0
Cedar Aberfeldy D14-15-49-27
Lloydminster
Proved Producing
As Of Date January 1, 2002
Prediction Date January 31, 2002
Saskatchewan
UWI 141/14-15-049-27W3/0
Net No. Xxxxx 0.60
Average WI 60%
Average Royalty 18%
Price Schedule ATB 2001 Q4
Price File Saskatchewan
Econ. Limit Enabled
GCA Applied Yes
BOE Ratio 10:1
[LINE CHART]
COMPANY WI SHARE NET PRESENT WORTH VALUE BEFORE TAX (M$) PRICE
----------------------- -------------------------------------------------------- ---------
REMAINING GROSS NET 8.0% 10.0% 12.0% 15.0% 20.0% YEAR 1
--------- ----- --- ---- ----- ----- ----- ----- ------
Oil (mbbl) (1:10) -- -- -- -- -- -- -- -- --
Gas (mmcf) 1.7 1.0 0.9 1.1 1.1 1.1 1.1 1.1 2.76
NGL (mbbl) (1:1) -- -- -- -- -- -- -- -- --
C2 (mbbl) (1:1) -- -- -- -- -- -- -- -- --
C3 (mbbl) (1:1) -- -- -- -- -- -- -- -- --
C4 (mbbl) (1:1) -- -- -- -- -- -- -- -- --
C5+ (mbbl) (1:1) -- -- -- -- -- -- -- -- --
Sulphur (mlt) (1:1) -- -- -- -- -- -- -- -- --
-------------------------------------------------------------------------------------------------------------------------------
TOTALS (MBOE) 0.2 0.1 0.1 1.1 1.1 1.1 1.1 1.1
AFTER TAX 1.1 1.1 1.1 1.1 1.1
CAPITAL COSTS (M$) CASH FLOW (M$) ECONOMIC INDICATORS
--------------------------------------- -------------------------------- ---------------------------------------------
GROSS NET GROSS NET BEFORE TAX AFTER TAX
----- --- ----- --- ---------- ---------
CEE -- -- Revenue 4.8 2.9 Rate of Return (%) -- --
CDE -- -- Royalties 0.8 0.5 Payout (yrs) -- --
CCA -- -- Op. Costs 1.9 1.1 P/I - 0.0% Discount -- --
COGPE -- -- Capital -- -- P/I - 12.0% Discount -- --
Abandonment -- -- ARTC -- -- Op. Cost ($/boe) 6.5 --
Cap. Cost ($/boe) -- --
-------------------------------------------------------------------------------
Total -- -- Before Tax 2.1 1.3
ANNUAL CASH FLOW
-----------------------------
GROSS ROYALTY OPERATING CAPITAL BTAX NET BTAX ATAX NET ATAX
WELL RATE PRICE REVENUE & TAXES COST COST ARTC REVENUE NET CUM TAX PAID REVENUE NET CUM
YEAR COUNT MCF/D $/MCF M$ M$ M$ M$ M$ M$ M$ M$ M$ M$
------------------------------------------------------------------------------------------------------------------------------------
2002 0.60 17.7 2.76 2.9 0.5 1.1 -- -- 1.2 1.2 -- 1.2 1.2
------------------------------------------------------------------------------------------------------------------------------------
TOTAL 17.7 2.76 2.9 0.5 1.1 -- -- 1.2 -- 1.2
131
CEDAR ABERFELDY D14-15-49-27 (141/14-15-049-27W3/2) PROVED PRODUCING - RAW
STATUS Producer: Active gas well ON TIME 99%
FIELD N/A RIG RELEASE Jun 1985
POOL Xxxxxxxx WI 0%
UNIT N/A RLI 0.0
OPERATOR N/A TYPE P-DP
LICENSEE Atcor Resources Limited Raw
RESERVES (JAN 1, 2002)
ULTIMATE CUMULATIVE REMAINING REMAINING
P-DP RESERVES PRODUCTION GROSS NET
--------------------------------------------------------------------------------
Oil (mbbl) 0.0 0.0 0.0 0.0
Gas (mmcf) 855.7 483.8 371.9 0.0
Water (mbbl) 1.7 1.7 0.0 0.0
DECLINES
DECLINE SEGMENT DATE QI DI NI TYPE
--------------------------------------------------------------------------------
NO DECLINES.
PRODUCTION (6 MO. HISTORY / 6 MO. FORECAST)
DATE WELL CDOR CDGR CDWR LGR
COUNT (BBL/D) (MCF/D) (BBL/D) (BBL/MMCF)
--------------------------------------------------------------------------------
Jan 1997 1.0 0 10 0 0
Feb 1997 1.0 0 7 0 0
Sep 2001 1.0 0 116 0 0
Oct 2001 1.0 0 352 0 0
Nov 2001 1.0 0 222 0 0
Dec 2001 1.0 0 125 0 0
--------------------------------------------------------------------------------
Jan 2002 1.0 0 118 0 0
Feb 2002 1.0 0 117 0 0
Mar 2002 1.0 0 108 0 0
Apr 2002 1.0 0 107 0 0
May 2002 1.0 0 106 0 0
Jun 2002 1.0 0 106 0 0
[LINE GRAPH]
[LINE GRAPH]
132
SUMMARY
Westerra 2000
141/14-15-049-27W3/2
Cedar Aberfeldy D14-15-49-27
Xxxxxxxx
Proved Producing
As Of Date January 1, 2002
Prediction Date January 31, 2002
Saskatchewan
UWI 141/14-15-049-27W3/2
Net No. Xxxxx 0.60
Average WI 60%
Average Royalty 18%
Price Schedule ATB 2001 Q4
Price File Saskatchewan
Econ. Limit Enabled
GCA Applied Yes
BOE Ratio 10:1
[BAR CHART]
COMPANY WI SHARE NET PRESENT WORTH VALUE BEFORE TAX (M$) PRICE
---------------------- -------------------------------------------------------- ----------
REMAINING GROSS NET 8.0% 10.0% 12.0% 15.0% 20.0% YEAR 1
--------- ----- --- ---- ----- ----- ----- ----- ------
Oil (mbbl) (1:10) -- -- -- -- -- -- -- -- --
Gas (mmcf) 360.4 216.2 178.4 228.4 211.4 196.6 177.8 153.2 2.86
NGL (mbbl) (1:1) -- -- -- -- -- -- -- -- --
C2 (mbbl) (1:1) -- -- -- -- -- -- -- -- --
C3 (mbbl) (1:1) -- -- -- -- -- -- -- -- --
C4 (mbbl) (1:1) -- -- -- -- -- -- -- -- --
C5+ (mbbl) (1:1) -- -- -- -- -- -- -- -- --
Sulphur (mlt) (1:1) -- -- -- -- -- -- -- -- --
-------------------------------------------------------------------------------------------------------------------------------
TOTALS (MBOE) 36.0 21.6 17.8 228.4 211.4 196.6 177.8 153.2
AFTER TAX 155.2 143.5 133.4 120.4 103.6
CAPITAL COSTS (M$) CASH FLOW (M$) ECONOMIC INDICATORS
----------------------------------------- ---------------------------------- --------------------------------------------
GROSS NET GROSS NET BEFORE TAX AFTER TAX
----- --- ----- --- ---------- ---------
CEE -- -- Revenue 1,359.7 815.8 Rate of Return (%) -- --
CDE -- -- Royalties 237.7 142.6 Payout (yrs) -- --
CCA -- -- Op. Costs 521.4 312.8 P/I - 0.0% Discount -- --
COGPE -- -- Capital -- -- P/I - 12.0% Discount -- --
Abandonment -- -- ARTC -- -- Op. Cost ($/boe) 8.7 --
Cap. Cost ($/boe) -- --
--------------------------------------------------------------------------------
Total -- -- Before Tax 600.6 360.4
ANNUAL CASH FLOW
----------------------------------------------
GROSS ROYALTY OPERATING CAPITAL
WELL RATE PRICE REVENUE & TAXES COST COST ARTC
YEAR COUNT MCF/D $/MCF M$ M$ M$ M$ M$
--------------------------------------------------------------------------------------------------------------------
2002 0.60 63.9 2.86 66.7 13.4 19.1 -- --
2003 0.60 60.0 3.76 82.2 16.6 20.1 -- --
2004 0.60 55.9 3.75 76.8 14.7 19.8 -- --
2005 0.60 50.8 3.85 71.4 12.8 19.0 -- --
2006 0.60 44.8 3.84 62.9 10.5 18.0 -- --
2007 0.60 39.7 3.84 55.7 9.2 17.2 -- --
2008 0.60 35.4 3.83 49.6 8.2 16.5 -- --
2009 0.60 31.6 3.83 44.2 7.3 15.9 -- --
2010 0.60 28.4 3.82 39.7 6.5 15.4 -- --
2011 0.60 25.6 3.87 36.2 5.9 15.0 -- --
REM. 0.60 16.0 4.07 230.5 37.6 136.7 -- --
--------------------------------------------------------------------------------------------------------------------
TOTAL 30.1 3.78 815.8 142.6 312.8 -- --
BTAX NET BTAX ATAX NET ATAX
REVENUE NET CUM TAX PAID REVENUE NET CUM
YEAR M$ M$ M$ M$ M$
---------------------------------------------------------------------------
2002 31.9 31.9 10.7 21.2 21.2
2003 42.6 74.5 14.2 28.4 49.6
2004 39.5 114.0 12.9 26.6 76.2
2005 37.0 151.0 11.8 25.1 101.3
2006 32.1 183.1 10.0 22.1 123.4
2007 27.3 210.3 8.5 18.8 142.2
2008 23.1 233.5 7.2 16.0 158.1
2009 19.4 252.9 6.0 13.4 171.6
2010 16.3 269.2 5.0 11.3 182.8
2011 13.9 283.1 4.3 9.6 192.4
REM. 47.9 331.0 14.3 33.6 226.0
---------------------------------------------------------------------------
TOTAL 331.0 105.0 226.0
133
CEDAR ET AL ABERFELDY RE 00-00-00-00 (141/15-15-049-27W3/3) PROVED PRODUCING-RAW
STATUS Producer: Inactive gas well ON TIME 100%
FIELD N/A RIG RELEASE Sep 2001
POOL Sparky WI 0%
UNIT N/A RLI 0.0
OPERATOR N/A TYPE P-DP
LICENSEE Cedar Energy Inc. Raw
RESERVES (JAN 1, 2002)
ULTIMATE CUMULATIVE REMAINING REMAINING
P-DP RESERVES PRODUCTION GROSS NET
--------------------------------------------------------------------------------
Oil (mbbl) 0.0 0.0 0.0 0.0
Gas (mmcf) 360.2 23.4 336.8 0.0
Water (mbbl) 0.0 0.0 0.0 0.0
DECLINES
DECLINE SEGMENT DATE QI DI NI TYPE
--------------------------------------------------------------------------------
NO DECLINES.
PRODUCTION (2 MO. HISTORY / 2 MO. FORECAST)
DATE WELL CDOR CDGR CDWR LGR
COUNT (BBL/D) (MCF/D) (BBL/D) (BBL/MMCF)
--------------------------------------------------------------------------------
Nov 2001 1.0 0 215 0 0
Dec 2001 1.0 0 546 0 0
--------------------------------------------------------------------------------
Jan 2002 1.0 0 550 0 0
Feb 2002 1.0 0 550 0 0
Mar 2002 1.0 0 551 0 0
Apr 2002 1.0 0 550 0 0
May 2002 1.0 0 550 0 0
Jun 2002 1.0 0 514 0 0
[LINE GRAPH]
[CHART]
134
SUMMARY
Westerra 2000
141/15-15-049-27W3/3
Cedar et al Aberfeldy RE 00-00-00-00
Sparky
Proved Producing
As Of Date January 1, 2002
Prediction Date January 31, 2002
Saskatchewan
UWI 141/15-15-049-27W3/3
Net No. Xxxxx 0.60
Average WI 60%
Average Royalty 18%
Price Schedule ATB 2001 Q4
Price File Saskatchewan
Econ. Limit Enabled
GCA Applied Yes
BOE Ratio 10:1
[BAR CHART]
COMPANY WI SHARE NET PRESENT WORTH VALUE BEFORE TAX (M$) PRICE
---------------------- --------------------------------------------------------- ----------
REMAINING GROSS NET 8.0% 10.0% 12.0% 15.0% 20.0% YEAR 1
--------- ----- --- ---- ----- ----- ----- ----- ------
Oil (mbbl) (1:10) -- -- -- -- -- -- -- -- --
Gas (mmcf) 292.0 175.2 144.6 111.9 109.9 108.1 105.4 101.4 2.86
NGL (mbbl) (1:1) -- -- -- -- -- -- -- -- --
C2 (mbbl) (1:1) -- -- -- -- -- -- -- -- --
C3 (mbbl) (1:1) -- -- -- -- -- -- -- -- --
C4 (mbbl) (1:1) -- -- -- -- -- -- -- -- --
C5+ (mbbl) (1:1) -- -- -- -- -- -- -- -- --
Sulphur (mlt) (1:1) -- -- -- -- -- -- -- -- --
-------------------------------------------------------------------------------------------------------------------------------
TOTALS (MBOE) 29.2 17.5 14.5 111.9 109.9 108.1 105.4 101.4
AFTER TAX 53.3 52.3 51.4 50.1 48.1
CAPITAL COSTS (M$) CASH FLOW (M$) ECONOMIC INDICATORS
--------------------------------------- -------------------------------- ----------------------------------------------
GROSS NET GROSS NET BEFORE TAX AFTER TAX
----- --- ----- --- ---------- ---------
CEE -- -- Revenue 936.9 562.2 Rate of Return (%) -- --
CDE -- -- Royalties 307.5 184.5 Payout (yrs) -- --
CCA -- -- Op. Costs 394.9 236.9 P/I - 0.0% Discount -- --
COGPE -- -- Capital -- -- P/I - 12.0% Discount -- --
Abandonment -- -- ARTC -- -- Op. Cost ($/boe) 8.1 --
Cap. Cost ($/boe) -- --
-----------------------------------------------------------------------------
Total -- -- Before Tax 234.6 140.7
ANNUAL CASH FLOW
-----------------------------
GROSS ROYALTY OPERATING CAPITAL BTAX NET BTAX ATAX NET ATAX
WELL RATE PRICE REVENUE & TAXES COST COST ARTC REVENUE NET CUM TAX PAID REVENUE NET CUM
YEAR COUNT MCF/D $/MCF M$ M$ M$ M$ M$ M$ M$ M$ M$ M$
------------------------------------------------------------------------------------------------------------------------------------
2002 0.60 279.8 2.86 292.1 107.4 104.2 -- -- 70.1 70.1 38.0 32.0 32.0
2003 0.60 129.7 3.76 177.8 57 .6 71.2 -- -- 42.6 112.6 21.5 21.1 53.1
2004 0.60 63.3 3.75 86.9 18 .7 57.0 -- -- 8.1 120.8 3.5 4.7 57.8
2005 0.60 44.4 3.85 5.3 0.9 4.5 -- -- -0.3 120.5 -- -0.3 57.5
------------------------------------------------------------------------------------------------------------------------------------
TOTAL 154.4 3.23 562.2 184.5 236.9 -- -- 120.5 63.0 57.5
135
CEDAR LLOYDMINSTER 6C-9-50-1 (1C0/06-09-050-01W4/0) PROVED NON PRODUCING - RAW
STATUS Standing: Suspended gas storage well ON TIME 100%
FIELD Lloydminster RIG RELEASE Jun 1948
POOL Sparky Gas Storage WI 0%
UNIT RLI 0.0
OPERATOR TYPE P-NP
LICENSEE Cedar Energy Inc. Raw
RESERVES (JAN 1, 2002)
ULTIMATE CUMULATIVE REMAINING REMAINING
P-NP RESERVES PRODUCTION GROSS NET
--------------------------------------------------------------------------------
Oil (mbbl) 0.0 0.0 0.0 0.0
Gas (mmcf) 479.9 0.0 479.9 0.0
Water (mbbl) 0.0 0.0 0.0 0.0
DECLINES
DECLINE SEGMENT DATE QI DI NI TYPE
--------------------------------------------------------------------------------
P-NP Gas 1 Jun 2002 2,500.0 1.895 0.00 Exp
PRODUCTION (0 MO. HISTORY / 0 MO. FORECAST)
DATE WELL CDOR CDGR CDWR LGR
COUNT (BBL/D) (MCF/D) (BBL/D) (BBL/MMCF)
--------------------------------------------------------------------------------
Jul 2002 1.0 0 1,000 0 0
Aug 2002 1.0 0 1,000 0 0
Sep 2002 1.0 0 1,000 0 0
Oct 2002 1.0 0 1,000 0 0
Nov 2002 1.0 0 1,000 0 0
Dec 2002 1.0 0 1,000 0 0
[LINE GRAPH]
[CHART]
136
SUMMARY
Westerra 2000
1C0/06-09-050-01W4/0
Cedar Lloydminster 6c-9-50-1
Lloydminster Sparky & Gen Xxxx C&d
Proved Non Producing
As Of Date January 1, 2002
Prediction Date July 31, 2002
Alberta
UWI 1C0/06-09-050-01W4/0
Net No. Xxxxx 0.00
Average WI 60%
Average Royalty 0%
Price Schedule ATB 2001 Q4
Price File Alberta
Econ. Limit Enabled
GCA Applied Yes
BOE Ratio 10:1
[BAR CHART]
COMPANY WI SHARE NET PRESENT WORTH VALUE BEFORE TAX (M$) PRICE
---------------------- --------------------------------------------------------- ---------
REMAINING GROSS NET 8.0% 10.0% 12.0% 15.0% 20.0% YEAR 1
--------- ----- --- ---- ----- ----- ----- ----- ------
Oil (mbbl) (1:10) -- -- -- -- -- -- -- -- --
Gas (mmcf) 452.5 271.5 271.5 772.8 755.2 738.4 714.6 678.1 --
NGL (mbbl) (1:1) -- -- -- -- -- -- -- -- --
C2 (mbbl) (1:1) -- -- -- -- -- -- -- -- --
C3 (mbbl) (1:1) -- -- -- -- -- -- -- -- --
C4 (mbbl) (1:1) -- -- -- -- -- -- -- -- --
C5+ (mbbl) (1:1) -- -- -- -- -- -- -- -- --
Sulphur (mlt) (1:1) -- -- -- -- -- -- -- -- --
-------------------------------------------------------------------------------------------------------------------------------
TOTALS (MBOE) 45.3 27.2 27.2 772.8 755.2 738.4 714.6 678.1
AFTER TAX 558.0 545.0 532.7 515.1 488.3
CAPITAL COSTS (M$) CASH FLOW (M$) ECONOMIC INDICATORS
----------------------------------------- ---------------------------------- --------------------------------------------
GROSS NET GROSS NET BEFORE TAX AFTER TAX
----- --- ----- --- ---------- ---------
CEE -- -- Revenue 1,632.0 979.2 Rate of Return (%) -- --
CDE 82.4 49.4 Royalties -- -- Payout (yrs) 0.6 0.0
CCA -- -- Op. Costs 129.3 77.6 P/I - 0.0% Discount 17.2 12.5
COGPE -- -- Capital 82.4 49.4 P/I - 12.0% Discount 15.8 11.4
Abandonment -- -- ARTC -- -- Op. Cost ($/boe) 1.7 --
Cap. Cost ($/boe) 1.1 --
--------------------------------------------------------------------------------
Total 82.4 49.4 Before Tax 1,420.3 852.2
ANNUAL CASH FLOW
------------------------------
GROSS ROYALTY OPERATING CAPITAL BTAX NET BTAX ATAX NET ATAX
WELL RATE PRICE REVENUE & TAXES COST COST ARTC REVENUE NET CUM TAX PAID REVENUE NET CUM
YEAR COUNT MCF/D $/MCF M$ M$ M$ M$ M$ M$ M$ M$ M$ M$
------------------------------------------------------------------------------------------------------------------------------------
2002 0.51 490.1 3.00 314.6 -- 14.5 49.4 -- 250.7 250.7 -- -- --
2003 0.60 387.3 4.00 565.4 -- 29.8 -- -- 535.6 786.4 141.3 394.4 394.4
2004 0.60 66.0 4.00 96.6 -- 30.7 -- -- 65.9 852.3 14.3 51.6 446.0
2005 0.60 20.5 4.00 2.5 -- 2.6 -- -- -0.1 852.2 -- -0.1 445.9
------------------------------------------------------------------------------------------------------------------------------------
TOTAL 277.7 3.61 979.2 -- 77.6 49.4 -- 852.2 155.5 445.9
137
CEDAR LLOYDMINSTER 6C-9-50-1 (1C0/06-09-050-01W4/0) PROVED + PROB. NON
PRODUCING - RAW
STATUS Standing: Suspended gas storage well ON TIME 100%
FIELD Lloydminster RIG RELEASE Jun 1948
POOL Sparky Gas Storage WI 0%
UNIT RLI 0.0
OPERATOR TYPE P+P-NP
LICENSEE Cedar Energy Inc. Raw
RESERVES (JAN 1, 2002)
ULTIMATE CUMULATIVE REMAINING REMAINING
P+P-NP RESERVES PRODUCTION GROSS NET
--------------------------------------------------------------------------------
Oil (mbbl) 0.0 0.0 0.0 0.0
Gas (mmcf) 606.4 0.0 606.4 0.0
Water (mbbl) 0.0 0.0 0.0 0.0
DECLINES
DECLINE SEGMENT DATE QI DI NI TYPE
--------------------------------------------------------------------------------
P+P-NP Gas 1 Jun 2002 2,500.0 2.821 0.50 Hyp
PRODUCTION (0 MO. HISTORY / 0 MO. FORECAST)
DATE WELL CDOR CDGR CDWR LGR
COUNT (BBL/D) (MCF/D) (BBL/D) (BBL/MMCF)
--------------------------------------------------------------------------------
Jul 2002 1.0 0 1,000 0 0
Aug 2002 1.0 0 1,000 0 0
Sep 2002 1.0 0 1,000 0 0
Oct 2002 1.0 0 1,000 0 0
Nov 2002 1.0 0 1,000 0 0
Dec 2002 1.0 0 1,000 0 0
[LINE GRAPH]
[CHART]
138
SUMMARY
Westerra 2000
1C0/06-09-050-01W4/0
Cedar Lloydminster 6c-9-50-1
Lloydminster Sparky & Gen Xxxx C&d
Proved + Prob. Non Producing
As Of Date January 1, 2002
Prediction Date July 31, 2002
Alberta
UWI 1C0/06-09-050-01W4/0
Net No. Xxxxx 0.00
Average WI 60%
Average Royalty 0%
Price Schedule ATB 2001 Q4
Price File Alberta
Econ. Limit Enabled
GCA Applied Yes
BOE Ratio 10:1
[BAR CHART]
COMPANY WI SHARE NET PRESENT WORTH VALUE BEFORE TAX (M$) PRICE
---------------------- --------------------------------------------------------- ---------
REMAINING GROSS NET 8.0% 10.0% 12.0% 15.0% 20.0% YEAR 1
--------- ----- --- ---- ----- ----- ----- ----- ------
Oil (mbbl) (1:10) -- -- -- -- -- -- -- -- --
Gas (mmcf) 539.9 323.9 323.9 863.2 839.6 817.3 786.0 738.8 --
NGL (mbbl) (1:1) -- -- -- -- -- -- -- -- --
C2 (mbbl) (1:1) -- -- -- -- -- -- -- -- --
C3 (mbbl) (1:1) -- -- -- -- -- -- -- -- --
C4 (mbbl) (1:1) -- -- -- -- -- -- -- -- --
C5+ (mbbl) (1:1) -- -- -- -- -- -- -- -- --
Sulphur (mlt) (1:1) -- -- -- -- -- -- -- -- --
-------------------------------------------------------------------------------------------------------------------------------
TOTALS (MBOE) 54.0 32.4 32.4 863.2 839.6 817.3 786.0 738.8
AFTER TAX 628.6 610.9 594.3 570.9 535.8
CAPITAL COSTS (M$) CASH FLOW (M$) ECONOMIC INDICATORS
----------------------------------------- ---------------------------------- --------------------------------------------
GROSS NET GROSS NET BEFORE TAX AFTER TAX
----- --- ----- --- ---------- ---------
CEE -- -- Revenue 1,980.3 1,188.2 Rate of Return (%) -- --
CDE 82.4 49.4 Royalties -- -- Payout (yrs) 0.6 0.0
CCA -- -- Op. Costs 277.2 166.3 P/I - 0.0% Discount 19.7 14.4
COGPE -- -- Capital 82.4 49.4 P/I - 12.0% Discount 17.5 12.7
Abandonment -- -- ARTC -- -- Op. Cost ($/boe) 3.1 --
Cap. Cost ($/boe) 0.9 --
--------------------------------------------------------------------------------
Total 82.4 49.4 Before Tax 1,620.7 972.4
ANNUAL CASH FLOW
----------------------------------------------------
GROSS ROYALTY OPERATING CAPITAL
WELL RATE PRICE REVENUE & TAXES COST COST ARTC
YEAR COUNT MCF/D $/MCF M$ M$ M$ M$ M$
------------------------------------------------------------------------------------------------------------------------------------
2002 0.51 490.1 3.00 314.6 -- 14.6 49.4 --
2003 0.60 360.4 4.00 526.2 -- 30.2 -- --
2004 0.60 121.8 4.00 178.3 -- 31.1 -- --
2005 0.60 60.7 4.00 88.6 -- 32.0 -- --
2006 0.60 36.3 4.00 53.0 -- 33.0 -- --
2007 0.60 25.2 4.00 27.5 -- 25.5 -- --
------------------------------------------------------------------------------------------------------------------------------------
TOTAL 166.0 3.68 1,188.2 -- 166.3 49.4 --
BTAX NET BTAX ATAX NET ATAX
REVENUE NET CUM TAX PAID REVENUE NET CUM
YEAR M$ M$ M$ M$ M$
-----------------------------------------------------------------------------
2002 250.6 250.6 -- -- --
2003 496.0 746.6 130.5 365.5 365.5
2004 147.3 893.8 35.1 112.2 477.7
2005 56.6 950.4 12.6 44.0 521.6
2006 20.0 970.4 3.7 16.3 537.9
2007 2.0 972.4 -- 2.0 540.0
-----------------------------------------------------------------------------
TOTAL 972.4 181.9 540.0
139
CEDAR LLOYDMINSTER 8C-22-50-2 (1C0/08-22-050-02W4/2) PROVED NON PRODUCING - RAW
STATUS Producer: Suspended gas well ON TIME 82%
FIELD Lloydminster RIG RELEASE
POOL Colony WI 0%
UNIT N/A RLI 0.0
OPERATOR Northwestern Utilities Limited TYPE P-NP
LICENSEE Raw
RESERVES (JAN 1, 2002)
ULTIMATE CUMULATIVE REMAINING REMAINING
P-NP RESERVES PRODUCTION GROSS NET
--------------------------------------------------------------------------------
Oil (mbbl) 0.0 0.0 0.0 0.0
Gas (mmcf) 1,131.7 304.5 827.2 0.0
Water (mbbl) 0.0 0.0 0.0 0.0
DECLINES
DECLINE SEGMENT DATE QI DI NI TYPE
--------------------------------------------------------------------------------
P-NP Gas 1 Jan 2002 0.0 0.25 0.00 Exp
P-NP Gas 2 Sep 2002 500.0 0.217 0.00 Exp
PRODUCTION (6 MO. HISTORY / 6 MO. FORECAST)
DATE WELL CDOR CDGR CDWR LGR
COUNT (BBL/D) (MCF/D) (BBL/D) (BBL/MMCF)
--------------------------------------------------------------------------------
Apr 1985 1.0 0 4 0 0
Nov 1985 1.0 0 7 0 0
Dec 1985 1.0 0 37 0 0
Jan 1986 1.0 0 33 0 0
Feb 1986 1.0 0 35 0 0
Mar 1986 1.0 0 10 0 0
--------------------------------------------------------------------------------
Feb 2002 0.0 0 0 0 0
Mar 2002 0.0 0 0 0 0
Apr 2002 0.0 0 0 0 0
May 2002 0.0 0 0 0 0
Jun 2002 0.0 0 0 0 0
Jul 2002 0.0 0 0 0 0
[BAR/LINE GRAPH]
[CHART]
140
SUMMARY
Westerra 2000
1C0/08-22-050-02W4/2
Cedar Lloydminster 8C-22-50-2
Lloydminster Colony
Proved Non Producing
As Of Date January 1, 2002
Prediction Date February 28, 2002
Alberta
UWI 1C0/08-22-050-02W4/2
Net No. Xxxxx 0.60
Average WI 60%
Average Royalty 20%
Price Schedule ATB 2001 Q4
Price File Alberta
Econ. Limit Enabled
GCA Applied Yes
BOE Ratio 10:1
[BAR CHART]
COMPANY WI SHARE NET PRESENT WORTH VALUE BEFORE TAX (M$) PRICE
---------------------- --------------------------------------------------------- ---------
REMAINING GROSS NET 8.0% 10.0% 12.0% 15.0% 20.0% YEAR 1
--------- ----- --- ---- ----- ----- ----- ----- ------
Oil (mbbl) (1:10) -- -- -- -- -- -- -- -- --
Gas (mmcf) 818.9 491.4 394.6 806.6 738.5 680.0 606.5 511.5 2.76
NGL (mbbl) (1:1) -- -- -- -- -- -- -- -- --
C2 (mbbl) (1:1) -- -- -- -- -- -- -- -- --
C3 (mbbl) (1:1) -- -- -- -- -- -- -- -- --
C4 (mbbl) (1:1) -- -- -- -- -- -- -- -- --
C5+ (mbbl) (1:1) -- -- -- -- -- -- -- -- --
Sulphur (mlt) (1:1) -- -- -- -- -- -- -- -- --
-------------------------------------------------------------------------------------------------------------------------------
TOTALS (MBOE) 81.9 49.1 39.5 806.6 738.5 680.0 606.5 511.5
AFTER TAX 534.8 487.8 447.6 397.2 332.4
CAPITAL COSTS (M$) CASH FLOW (M$) ECONOMIC INDICATORS
----------------------------------------- ---------------------------------- --------------------------------------------
GROSS NET GROSS NET BEFORE TAX AFTER TAX
----- --- ----- --- ---------- ---------
CEE -- -- Revenue 3,094.3 1,856.6 Rate of Return (%) -- --
CDE -- -- Royalties 542.1 325.3 Payout (yrs) 1.0 1.0
CCA 41.2 24.7 Op. Costs 451.0 270.6 P/I - 0.0% Discount 50.0 33.7
COGPE -- -- Capital 41.2 24.7 P/I - 12.0% Discount 29.1 19.2
Abandonment -- -- ARTC -- -- Op. Cost ($/boe) 3.3 --
Cap. Cost ($/boe) 0.3 --
--------------------------------------------------------------------------------
Total 41.2 24.7 Before Tax 2,060.0 1,236.0
ANNUAL CASH FLOW
-------------------------------------------------
GROSS ROYALTY OPERATING CAPITAL
WELL RATE PRICE REVENUE & TAXES COST COST ARTC
YEAR COUNT MCF/D $/MCF M$ M$ M$ M$ M$
----------------------------------------------------------------------------------------------------------------------------
2002 0.60 238.3 2.76 60.5 15.5 7.5 24.7 --
2003 0.60 213.5 3.75 292.4 74.1 27.7 -- --
2004 0.60 178.2 3.75 244.2 56.7 24.3 -- --
2005 0.60 149.5 3.74 204.0 42.9 21.5 -- --
2006 0.60 125.2 3.73 170.4 32.3 19.0 -- --
2007 0.60 104.8 3.72 142.3 24.3 16.9 -- --
2008 0.60 87.4 3.71 118.8 18.2 15.1 -- --
2009 0.60 73.4 3.70 99.2 13.7 13.6 -- --
2010 0.60 61.4 3.70 82.9 10.2 12.3 -- --
2011 0.60 51.4 3.79 71.1 8.0 11.2 -- --
REM. 0.60 17.6 4.22 370.7 29.4 101.5 -- --
----------------------------------------------------------------------------------------------------------------------------
TOTAL 58.7 3.78 1,856.6 325.3 270.6 24 .7 --
BTAX NET BTAX ATAX NET ATAX
REVENUE NET CUM TAX PAID REVENUE NET CUM
YEAR M$ M$ M$ M$ M$
-----------------------------------------------------------------------------
2002 12.9 12.9 -- -- --
2003 190.6 203.5 69.4 121.2 121.2
2004 163.3 366.7 55.1 108.2 229.4
2005 139.6 506.4 45.9 93.7 323.1
2006 119.1 625.4 38.1 80.9 404.1
2007 101.1 726.6 31.6 69.5 473.5
2008 85.5 812.0 26.2 59.3 532.8
2009 72.0 884.0 21.7 50.3 583.2
2010 60.3 944.4 17.9 42.5 625.6
2011 51.9 996.3 15.2 36.7 662.4
REM. 239.7 1,236.0 68.1 171.6 834.0
-----------------------------------------------------------------------------
TOTAL 1,236.0 389.2 834.0
141
CEDAR LLOYDMINSTER 8C-22-50-2 (1C0/08-22-050-02W4/2) PROVED + PROB. NON
PRODUCING - RAW
STATUS Producer: Suspended gas well ON TIME 82%
FIELD Lloydminster RIG RELEASE
POOL Colony WI 0%
UNIT N/A RLI 0.0
OPERATOR Northwestern Utilities Limited TYPE P+P-NP
LICENSEE Raw
RESERVES (JAN 1, 2002)
ULTIMATE CUMULATIVE REMAINING REMAINING
P+P-NP RESERVES PRODUCTION GROSS NET
--------------------------------------------------------------------------------
Oil (mbbl) 0.0 0.0 0.0 0.0
Gas (mmcf) 1,461.4 304.5 1,156.9 0.0
Water (mbbl) 0.0 0.0 0.0 0.0
DECLINES
DECLINE SEGMENT DATE QI DI NI TYPE
--------------------------------------------------------------------------------
P+P-NP Gas 1 Jan 2002 0.0 0.25 0.00 Exp
P+P-NP Gas 2 Sep 2002 500.0 0.154 0.00 Exp
PRODUCTION (6 MO. HISTORY / 6 MO. FORECAST)
DATE WELL CDOR CDGR CDWR LGR
COUNT (BBL/D) (MCF/D) (BBL/D) (BBL/MMCF)
--------------------------------------------------------------------------------
Apr 1985 1.0 0 4 0 0
Nov 1985 1.0 0 7 0 0
Dec 1985 1.0 0 37 0 0
Jan 1986 1.0 0 33 0 0
Feb 1986 1.0 0 35 0 0
Mar 1986 1.0 0 10 0 0
--------------------------------------------------------------------------------
Feb 2002 0.0 0 0 0 0
Mar 2002 0.0 0 0 0 0
Apr 2002 0.0 0 0 0 0
May 2002 0.0 0 0 0 0
Jun 2002 0.0 0 0 0 0
Jul 2002 0.0 0 0 0 0
[BAR/LINE CHART]
[BAR CHART]
142
SUMMARY
Westerra 2000
1C0/08-22-050-02W4/2
Cedar Lloydminster 8C-22-50-2
Lloydminster Colony
Proved + Prob. Non Producing
As Of Date January 1, 2002
Prediction Date February 28, 2002
Alberta
UWI 1C0/08-22-050-02W4/2
Net No. Xxxxx 0.60
Average WI 60%
Average Royalty 20%
Price Schedule ATB 2001 Q4
Price File Alberta
Econ. Limit Enabled
GCA Applied Yes
BOE Ratio 10:1
[BAR CHART]
COMPANY WI SHARE NET PRESENT WORTH VALUE BEFORE TAX (M$) PRICE
------------------------------------------------------------------------------------------
REMAINING GROSS NET 8.0% 10.0% 12.0% 15.0% 20.0% YEAR 1
--------- ----- --- ---- ----- ----- ----- ----- ------
Oil (mbbl) (1:10) - - - - - - - - -
Gas (mmcf) 1,145.4 687.2 551.1 1,028.2 922.3 834.8 728.9 598.9 2.76
NGL (mbbl) (1:1) - - - - - - - - -
C2 (mbbl) (1:1) - - - - - [ - - -
C3 (mbbl) (1:1) - - - - - - - - -
C4 (mbbl) (1:1) - - - - - - - - -
C5+ (mbbl) (1:1) - - - - - - - - -
Sulphur (mlt) (1:1) - - - - - - - - -
----------------------------------------------------------------------------------------------------------------------------
TOTALS (MBOE) 114.5 68.7 55.1 1,028.2 922.3 834.8 728.9 598.9
AFTER TAX 681.4 608.7 548.7 476.5 388.3
CAPITAL COSTS (M$) CASH FLOW (M$) ECONOMIC INDICATORS
--------------------------------- --------------------------------------- -----------------------------------------------
GROSS NET GROSS NET BEFORE TAX AFTER TAX
----- --- ----- --- ---------- ---------
CEE - - Revenue 4,466.3 2,679.8 Rate of Return (%) - -
CDE - - Royalties 775.2 465.1 Payout (yrs) 1.0 1.0
CCA 41.2 24.7 Op. Costs 647.1 388.3 P/I - 0.0% Discount 72.9 49.3
COGPE - - Capital 41.2 24.7 P/I - 12.0% Discount 35.7 23.5
Abandonment - - ARTC - - Op. Cost ($/boe) 3.4 -
---------------------------------------------------------------------------- Cap. Cost ($/boe) 0.2 -
Total 41.2 24.7 Before Tax 3,002.8 1,801.7
ANNUAL CASH FLOW
----------------
ROYALTY BTAX BTAX ATAX ATAX
GROSS & OPERATING CAPITAL NET NET TAX NET NET
WELL RATE PRICE REVENUE TAXES COST COST ARTC REVENUE CUM PAID REVENUE CUM
YEAR COUNT MCF/D $/MCF M$ M$ M$ M$ M$ M$ M$ M$ M$ M$
-----------------------------------------------------------------------------------------------------------------------------------
2002 0.60 239.9 2.76 60.9 15.6 7.5 24.7 - 13.1 13.1 - - -
2003 0.60 221.8 3.75 303.8 78.3 28.6 - - 196.8 209.9 72.1 124.7 124.7
2004 0.60 194.9 3.75 267.2 64.9 26.3 - - 176.0 385.9 60.2 11 5.8 240.6
2005 0.60 172.3 3.74 235.0 53.4 24.3 - - 157.4 543.2 53.0 104.3 344.9
2006 0.60 151.8 3.73 206.7 43.8 22.4 - - 140.5 683.8 46.6 94.0 438.8
2007 0.60 133.8 3.72 181.8 35.8 20.7 - - 125.3 809.0 40.8 84.5 523.4
2008 0.60 117.6 3.71 159.9 29.2 19.2 - - 111.5 920.5 35.7 75.8 599.2
2009 0.60 104.0 3.70 140.6 23.7 17.8 - - 99.0 1,019.5 31.1 67.9 667.1
2010 0.60 91.6 3.70 123.6 19.2 16.6 - - 87.8 1,107.4 27.2 60.6 727.7
2011 0.60 80.8 3.79 111.6 16.0 15.5 - - 80.1 1,187.4 24.4 55.6 783.3
REM. 0.60 27.4 4.40 888.7 85.2 189.2 - - 614.3 1,801.7 178.3 436.0 1,219.3
-----------------------------------------------------------------------------------------------------------------------------------
TOTAL 64.0 3.90 2,679.8 465.1 388.3 24.7 - 1,801.7 569.3 1,219.3
143
CEDAR LLOYDMINSTER 8C-22-50-2 (1C0/08-22-050-02W4/W) PROVED + PROB. NON
PRODUCING - RAW
STATUS Producer: Suspended gas well ON TIME 82%
FIELD Lloydminster RIG RELEASE
POOL Waseca WI 0%
UNIT N/A RLI 0.0
OPERATOR Northwestern Utilities Limited TYPE P+P-NP
LICENSEE Raw
RESERVES (JAN 1, 2002)
ULTIMATE CUMULATIVE REMAINING REMAINING
P+P-NP RESERVES PRODUCTION GROSS NET
------------------------------------------------------------------------
Oil (mbbl) 0.0 0.0 0.0 0.0
Gas (mmcf) 658.8 0.0 658.8 0.0
Water (mbbl) 0.0 0.0 0.0 0.0
DECLINES
DECLINE SEGMENT DATE QI DI NI TYPE
----------------------------------------------------------------------
P+P-NP Gas 1 Sep 2002 400.0 0.215 0.00 Exp
PRODUCTION (0 MO. HISTORY / 0 MO. FORECAST)
DATE WELL CDOR CDGR CDWR LGR
COUNT (BBL/D) (MCF/D) (BBL/D) (BBL/MMCF)
--------------------------------------------------------------------
Oct 2002 1.0 0 326 0 0
Nov 2002 1.0 0 321 0 0
Dec 2002 1.0 0 316 0 0
Jan 2003 1.0 0 312 0 0
Feb 2003 1.0 0 307 0 0
Mar 2003 1.0 0 303 0 0
[LINE CHART]
[LINE CHART]
144
SUMMARY
Westerra 2000
1C0/08-22-050-02W4/W
Cedar Lloydminster 8C-22-50-2
Lloydminster Waseca
Proved + Prob. Non Producing
As Of Date January 1, 2002
Prediction Date October 31, 2002
Alberta
UWI 1C0/08-22-050-02W4/w
Net No. Xxxxx 0.15
Average WI 15%
Average Royalty 18%
Price Schedule ATB 2001 Q4
Price File Alberta
Econ. Limit Enabled
GCA Applied Yes
BOE Ratio 10:1
[LINE CHART]
COMPANY WI SHARE NET PRESENT WORTH VALUE BEFORE TAX (M$) PRICE
------------------------------------------------------------------------------------
REMAINING GROSS NET 8.0% 10.0% 12.0% 15.0% 20.0% YEAR 1
--------- ----- --- ---- ----- ----- ----- ----- ------
Oil (mbbl) (1:10) - - - - - - - - -
Gas (mmcf) 652.2 97.8 80.5 158.5 144.9 133.1 118.2 99.0 2.76
NGL (mbbl) (1:1) - - - - - - - - -
C2 (mbbl) (1:1) - - - - - - - - -
C3 (mbbl) (1:1) - - - - - - - - -
C4 (mbbl) (1:1) - - - - - - - - -
C5+ (mbbl) (1:1) - - - - - - - - -
Sulphur (mlt) (1:1) - - - - - - - - -
--------------------------------------------------------------------------------------------------------------------------
TOTALS (MBOE) 65.2 9.8 8.1 158.5 144.9 133.1 118.2 99.0
AFTER TAX 106.2 96.6 88.4 78.0 64.6
CAPITAL COSTS (M$) CASH FLOW (M$) ECONOMIC INDICATORS
---------------------------------- ----------------------------------- -----------------------------------------------
GROSS NET GROSS NET BEFORE TAX AFTER TAX
----- --- ----- --- ---------- ---------
CEE - - Revenue 2,455.7 368.4 Rate of Return (%) > 500.0 > 500.0
CDE 41.2 6.2 Royalties 386.9 58.0 Payout (yrs) 1.2 1.3
CCA 41.2 6.2 Op. Costs 363.6 54.5 P/I - 0.0% Discount 19.7 13.4
COGPE - - Capital 82.4 12.4 P/I - 12.0% Discount 11.4 7.6
Abandonment - - ARTC - - Op. Cost ($/boe) 0.8 -
Cap. Cost ($/boe) 0.2 -
------------------------------------------------------------------------------------------------------------------------------
Total 82.4 12.4 Before Tax 1,622.9 243.4
ANNUAL CASH FLOW
----------------
GROSS ROYALTY OPERATING CAPITAL BTAX NET BTAX ATAX NET ATAX
WELL RATE PRICE REVENUE & TAXES COST COST ARTC REVENUE NET CUM TAX PAID REVENUE NET CUM
YEAR COUNT MCF/D $/MCF M$ M$ M$ M$ M$ M$ M$ M$ M$ M$
-----------------------------------------------------------------------------------------------------------------------------------
2002 0.15 47.7 2.76 12.1 2.8 1.5 12.4 - -4.6 -4.6 - - -
2003 0.15 42.7 3.75 58.5 13.3 5.7 - - 39.6 35.0 13.5 26.1 26.1
2004 0.15 35.7 3.75 49.0 10.1 5.0 - - 33.9 68.9 10.7 23.2 49.4
2005 0.15 30.0 3.74 41.0 7.6 4.5 - - 28.9 97.8 8.9 20.0 69.4
2006 0.15 25.2 3.73 34.3 5.7 4.0 - - 24.6 122.4 7.4 17.2 86.5
2007 0.15 21.1 3.72 28.7 4.3 3.6 - - 20.8 143.2 6.2 14.6 101.1
2008 0.15 17.7 3.71 24.0 3.3 3.2 - - 17.5 160.8 5.1 12.4 113.5
2009 0.15 14.8 3.70 20.1 2.5 2.9 - - 14.7 175.5 4.3 10.4 124.0
2010 0.15 12.4 3.70 16.8 1.9 2.7 - - 12.3 187.7 3.5 8.8 132.7
2011 0.15 10.4 3.79 14.4 1.5 2.4 - - 10.5 198.3 3.0 7.5 140.2
REM. 0.15 4.3 4.17 69.5 5.3 19.1 - - 45.2 243.4 12.6 32.6 172.8
-----------------------------------------------------------------------------------------------------------------------------------
TOTAL 13.5 3.77 368.4 58.0 54.5 12.4 - 243.4 75.2 172.8
145
XXXX NORTHMINSTER C2-14-50-28 (131/02-14-050-28W3/L) PROVED + PROB. NON
PRODUCING - RAW
STATUS Standing: Active oil well ON TIME 100%
FIELD N/A RIG RELEASE Jul 0000
XXXX Xxxxxxxxxxxx XX 0%
UNIT RLI 0.0
OPERATOR TYPE P+P-NP
LICENSEE Lone Rock Energy Limited Raw
RESERVES (JAN 1, 2002)
ULTIMATE CUMULATIVE REMAINING REMAINING
P+P-NP RESERVES PRODUCTION GROSS NET
---------------------------------------------------------------------
Oil (mbbl) 0.0 0.0 0.0 0.0
Gas (mmcf) 458.9 0.0 458.9 0.0
Water (mbbl) 0.0 0.0 0.0 0.0
DECLINES
DECLINE SEGMENT DATE QI DI NI TYPE
----------------------------------------------------------------------
P+P-NP Gas 1 Apr 2002 500.0 0.39 0.00 Exp
PRODUCTION (0 MO. HISTORY / 0 MO. FORECAST)
DATE WELL CDOR CDGR CDWR LGR
COUNT (BBL/D) (MCF/D) (BBL/D) (BBL/MMCF)
--------------------------------------------------------------
May 2002 1.0 0 492 0 0
Jun 2002 1.0 0 476 0 0
Jul 2002 1.0 0 461 0 0
Aug 2002 1.0 0 446 0 0
Sep 2002 1.0 0 432 0 0
Oct 2002 1.0 0 418 0 0
[LINE CHART]
[LINE CHART]
146
SUMMARY
Westerra 2000
131/02-14-050-28W3/L
Xxxx Northminster C2-14-50-28
Lloydminster
(Recompletion and Pooling)
[BAR GRAPH]
Proved + Prob. Non Producing
As Of Date January 1, 2002
Prediction Date May 31, 2002
Saskatchewan
UWI 131/02-14-050-28W3/L
Net No. Xxxxx 0.00
Average WI 15%
Average Royalty 23%
Price Schedule ATB 2001 Q4
Price File Saskatchewan
Econ. Limit Enabled
GCA Applied Yes
BOE Ratio 10:1
COMPANY WI SHARE NET PRESENT WORTH VALUE BEFORE TAX (M$) PRICE
------------------------------------------------------------------------------------
REMAINING GROSS NET 8.0% 10.0% 12.0% 15.0% 20.0% YEAR 1
--------- ----- --- ---- ----- ----- ----- ----- ------
Oil (mbbl) (1:10) - - - - - - - - -
Gas (mmcf) 453.9 68.1 52.3 95.6 91.2 87.2 81.7 73.9 -
NGL (mbbl) (1:1) - - - - - - - - -
C2 (mbbl) (1:1) - - - - - - - - -
C3 (mbbl) (1:1) - - - - - - - - -
C4 (mbbl) (1:1) - - - - - - - - -
C5+ (mbbl) (1:1) - - - - - - - - -
Sulphur (mlt) (1:1) - - - - - - - - -
------------------------------------------------------------------------------------------------------------------------
TOTALS (MBOE) 45.4 6.8 5.2 95.6 91.2 87.2 81.7 73.9
AFTER TAX 50.1 47.6 45.3 42.2 37.9
CAPITAL COSTS (M$) CASH FLOW (M$) ECONOMIC INDICATORS
---------------------------------- -------------------------------- ------------------------------------------------
GROSS NET GROSS NET BEFORE TAX AFTER TAX
----- --- ----- --- ---------- ---------
CEE - - Revenue 1,620.7 243.1 Rate of Return (%) - -
CDE 24.7 3.7 Royalties 335.8 50.4 Payout (yrs) 0.5 0.0
CCA - - Op. Costs 414.7 62.2 P/I - 0.0% Discount 31.8 16.9
COGPE - - Capital 24.7 3.7 P/I - 12.0% Discount 24.9 12.9
Abandonment - - ARTC - - Op. Cost ($/boe) 1.4 -
Cap. Cost ($/boe) 0.1 -
------------------------------------------------------------------------
Total 24.7 3.7 Before Tax 845.5 126.8
ANNUAL CASH FLOW
----------------
GROSS ROYALTY OPERATING CAPITAL BTAX NET BTAX ATAX NET ATAX
WELL RATE PRICE REVENUE & TAXES COST COST ARTC REVENUE NET CUM TAX PAID REVENUE NET CUM
YEAR COUNT MCF/D $/MCF M$ M$ M$ M$ M$ M$ M$ M$ M$ M$
-----------------------------------------------------------------------------------------------------------------------------------
2002 0.13 58.2 2.86 45.8 12.3 11.2 3.7 - 17.0 17.0 - - -
2003 0.15 47.4 3.76 64.9 17.7 12.8 - - 32.1 49.1 15.7 16.4 16.4
2004 0.15 32.0 3.75 43.9 10.3 9.4 - - 22.6 71.7 10.6 12.0 28.3
2005 0.15 21.7 3.85 30.5 5.6 7.0 - - 16.7 88.4 7.4 9.3 37.7
2006 0.15 14.7 3.84 20.6 2.5 5.4 - - 11.9 100.3 4.8 7.1 44.8
2007 0.15 10.0 3.84 13.9 1.1 4.3 - - 8.0 108.3 3.0 5.0 49.8
2008 0.15 6.7 3.83 9.4 0.5 3.5 - - 5.1 113.4 1.8 3.2 53.0
2009 0.15 4.6 3.83 6.4 0.2 3.0 - - 2.9 116.3 1.0 1.9 54.9
2010 0.15 3.1 3.82 4.3 0.1 2.7 - - 1.4 117.7 0.5 0.9 55.8
2011 0.15 2.1 3.87 3.0 0.0 2.5 - - 0.4 118.1 0.1 0.2 56.0
REM. 0.15 1.7 3.91 0.4 0.0 0.4 - - 0.0 118.1 - 0.0 56.0
-----------------------------------------------------------------------------------------------------------------------------------
TOTAL 18.8 3.57 243.1 50.4 62.2 3.7 - 118.1 45.1 56.0
147
GAS STORAGE WELL 6-9-50-1W4
ECONOMICS WITH 15% FREEHOLD ROYALTY
148
SUMMARY
Westerra 2000
1C0/06-09-050-01W4/0
Cedar Lloydminster 6C-9-50-1
Lloydminster Sparky & Gen Xxxx C&d
Proved Non Producing
As Of Date January 1, 2002
Prediction Date July 31, 2002
Alberta
UWI 1C0/06-09-050-01W4/0
Net No. Xxxxx 0.00
Average WI 60%
Average Royalty 15%
Price Schedule ATB 2001 Q4
Price File Alberta
Econ. Limit Enabled
GCA Applied Yes
BOE Ratio 10:1
[BAR CHART]
COMPANY WI SHARE NET PRESENT WORTH VALUE BEFORE TAX (M$) PRICE
-------------------- ---------------------------------------------------- --------
REMAINING GROSS NET 8.0% 10.0% 12.0% 15.0% 20.0% YEAR 1
--------- ----- --- ---- ----- ----- ----- ----- ------
Oil (mbbl) (1:10) - - - - - - - - -
Gas(mmcf) 452.5 271.5 230.8 603.9 590.0 576.7 557.8 529.0 -
NGL(mbbl) (1:1) - - - - - - - - -
C2 (mbbl) (1:1) - - - - - - - - -
C3 (mbbl) (1:1) - - - - - - - - -
C4 (mbbl) (1:1) - - - - - - - - -
C5+ (mbbl) (1:1) - - - - - - - - -
Sulphur (mlt) (1:1) - - - - - - - - -
--------------------------------------------------------------------------------------------------------------------
TOTALS (MBOE) 45.3 27.2 23.1 603.9 590.0 576.7 557.8 529.0
AFTER TAX 422.7 412.7 403.2 389.6 369.0
CAPITAL COSTS (M$) CASH FLOW (M$) ECONOMIC INDICATORS
------------------------------- ------------------------------------ ------------------------------------------------
GROSS NET GROSS NET BEFORE TAX AFTER TAX
----- --- ----- --- ---------- ---------
CEE - - Revenue 1,632.0 979.2 Rate of Return (%) - -
CDE 82.4 49.4 Royalties 309.1 185.5 Payout (yrs) 0.6 0.0
CCA - - Op. Costs 129.3 77.6 P/I - 0.0% Discount 13.5 9.5
COGPE - - Capital 82.4 49.4 P/I - 12.0% Discount 12.3 8.6
Abandonment - - ARTC - - Op. Cost ($/boe) 1.7 -
Cap. Cost ($/boe) 1.1 -
------------------------------- ------------------------------------
Total 82.4 49.4 Before Tax 1,111.2 666.7
ANNUAL CASH FLOW
GROSS ROYALTY OPERATING CAPITAL BTAX NET BTAX ATAX NET ATAX
WELL RATE PRICE REVENUE & TAXES COST COST ARTC REVENUE NET CUM TAX PAID REVENUE NET CUM
YEAR COUNT MCF/D $/MCF M$ M$ M$ M$ M$ M$ M$ M$ M$ M$
-----------------------------------------------------------------------------------------------------------------------------------
2002 0.51 490.1 3.00 314.6 62.6 14.5 49.4 - 188.1 188.1 - - -
2003 0.60 387.3 4.00 565.4 111.0 29.8 - - 424.7 612.8 119.5 305.2 305.2
2004 0.60 66.0 4.00 96.6 11.9 30.7 - - 54.0 666.8 11.7 42.2 347.4
2005 0.60 20.5 4.00 2.5 0.0 2.6 - - -0.1 666.7 - -0.1 347.3
-----------------------------------------------------------------------------------------------------------------------------------
TOTAL 277.7 3.61 979.2 185.5 77.6 49.4 - 666.7 131.3 347.3
149
SUMMARY
Westerra 2000
1C0/06-09-050-01W4/0
Cedar Lloydminster 6C-9-50-1
Lloydminster Sparky & Gen Xxxx C&d
Proved + Prob. Non Producing
As Of Date January 1, 2002
Prediction Date July 31, 2002
Alberta
UWI 1C0/06-09-050-01W4/0
Net No. Xxxxx 0.00
Average WI 60%
Average Royalty 15%
Price Schedule ATB 2001 Q4
Price File Alberta
Econ. Limit Enabled
GCA Applied Yes
BOE Ratio 10:1
[BAR CHART]
COMPANY WI SHARE NET PRESENT WORTH VALUE BEFORE TAX (M$) PRICE
-------------------- --------------------------------------------------- --------
REMAINING GROSS NET 8.0% 10.0% 12.0% 15.0% 20.0% YEAR 1
--------- ----- --- ---- ----- ----- ----- ----- ------
Oil (mbbl) (1:10) - - - - - - - - -
Gas(mmcf) 539.9 323.9 275.3 678.1 659.3 641.5 616.5 578.9 -
NGL(mbbl) (1:1) - - - - - - - - -
C2 (mbbl) (1:1) - - - - - - - - -
C3 (mbbl) (1:1) - - - - - - - - -
C4 (mbbl) (1:1) - - - - - - - - -
C5+ (mbbl) (1:1) - - - - - - - - -
Sulphur (mlt) (1:1) - - - - - - - - -
----------------------------------------------------------------------------------------------------------------------
TOTALS (MBOE) 54.0 32.4 27.5 678.1 659.3 641.5 616.5 578.9
AFTER TAX 480.5 466.7 453.7 435.4 407.9
CAPITAL COSTS (M$) CASH FLOW (M$) ECONOMIC INDICATORS
--------------------------------- ---------------------------------- -----------------------------------------------
GROSS NET GROSS NET BEFORE TAX AFTER TAX
----- --- ----- --- ---------- ---------
CEE - - Revenue 1,980.3 1,188.2 Rate of Return (%) - -
CDE 82.4 49.4 Royalties 344.9 207.0 Payout (yrs) 0.6 0.0
CCA - - Op. Costs 277.2 166.3 P/I - 0.0% Discount 15.5 11.0
COGPE - - Capital 82.4 49.4 P/I - 12.0% Discount 13.7 9.7
Abandonment - - ARTC - - Op. Cost ($/boe) 3.1 -
Cap. Cost ($/boe) 0.9 -
--------------------------------- ----------------------------------
Total 82.4 49.4 Before Tax 1,275.8 765.5
ANNUAL CASH FLOW
GROSS ROYALTY OPERATING CAPITAL BTAX NET BTAX ATAX NET ATAX
WELL RATE PRICE REVENUE & TAXES COST COST ARTC REVENUE NET CUM TAX PAID REVENUE NET CUM
YEAR COUNT MCF/D $/MCF M$ M$ M$ M$ M$ M$ M$ M$ M$ M$
-----------------------------------------------------------------------------------------------------------------------------------
2002 0.51 490.1 3.00 314.6 62.6 14.6 49.4 - 188.0 188.0 - - -
2003 0.60 360.4 4.00 526.2 102.9 30.2 - - 393.2 581.1 110.4 282.8 282.8
2004 0.60 121.8 4.00 178.3 27.8 31.1 - - 119.4 700.5 29.4 90.0 372.8
2005 0.60 60.7 4.00 88.6 9.9 32.0 - - 46.6 747.2 10.4 36.2 409.0
2006 0.60 36.3 4.00 53.0 3.4 33.0 - - 16.6 763.8 2.9 13.7 422.7
2007 0.60 25.2 4.00 27.5 0.4 25.5 - - 1.7 765.5 - 1.7 424.3
-----------------------------------------------------------------------------------------------------------------------------------
TOTAL 166.0 3.68 1,188.2 207.0 166.3 49.4 - 765.5 153.2 424.3
150
MATERIAL BALANCE PLOTS
151
Aberfeldy Xxxxxxxx Formation
41/14-15-049-27W3/2
[LINE CHART]
-------------------------------------------------------------------------------------------------------
Julian Numeric Character Cum Gas Pressure Z P/Z
UID Date Date Date bcf psi psi
-------------------------------------------------------------------------------------------------------
0.48 430 0.947 454
41/14-15-049-27W3/0 1985/06/21 1985.47 8506 618 0.926 667
41/14-15-049-27W3/0 1985/10/09 1985.77 8510 622 0.926 671
41/14-15-049-27W3/0 1990/01/01 1990.00 9001 0.19 555 0.933 594
41/14-15-049-27W3/0 1992/03/27 1992.24 9203 0.35 524 0.936 560
41/14-15-049-27W3/0 1994/09/05 1994.68 9409 0.41 441 0.945 466
41/14-15-049-27W3/0 2001/11/12 2001.87 10111 0.46 430 0.947 454
-------------------------------------------------------------------------------------------------------
152
Aberfeldy Sparky Formation
41/15-15-049-27W3/3, 41/16-15-049-27W3/0, 41/09-22-049-27W3/2
[LINE CHART]
------------------------------------------------------------------------------------------------------
Julian Numeric Character Cum Gas Pressure Z P/Z
UID Date Date Date bcf psi psi
------------------------------------------------------------------------------------------------------
1.61 130 0.983 132
Initial Pressure 1985/06/21 1985.47 8506 460 0.943 488
Current Pressure 2001/12/15 2001.96 10112 1.61 130 0.983 132
------------------------------------------------------------------------------------------------------
153
Lloydminster Colony Formation
Sections 23, 24, 25, 26, 35-49-28W3
[LINE CHART]
-----------------------------------------------------------------------------------------------------------------
Julian Numeric Character Cum Gas Pressure Z P/Z
UID Date Date Date bcf psi psi
-----------------------------------------------------------------------------------------------------------------
8.46 275
01/12-24-049-28W3/0 1945/02/01 1945.09 4502 0.76 450 0.947 475
31/15-24-049-28W3/0 1945/04/04 1945.26 4504 0.79 464 0.945 491
31/16-23-049-28W3/0 1961/09/11 1961.70 6109 5.12 257 0.969 265
21/01-26-049-28W3/0 1962/08/09 1962.61 6208 5.20 268 0.968 276
31/13-25-049-28W3/0 1986/07/23 1986.56 8607 7.89 237 0.971 244
31/06-26-049-28W3/0 1986/08/02 1986.59 8608 7.89 230 0.972 237
31/16-23-049-28W3/0 1987/08/09 1987.61 8708 7.90 254 0.969 262
31/16-23-049-28W3/0 1994/08/06 1994.60 9408 8.20 256 0.969 264
21/13-24-049-28W3/0 1994/08/08 1994.60 9408 8.20 227 0.972 234
31/13-24-049-28W3/0 1994/08/08 1994.60 9408 8.20 221 0.973 227
21/01-26-049-28W3/0 1994/08/11 1994.61 9408 8.20 255 0.969 263
01/12-24-049-28W3/0 1994/09/09 1994.69 9409 8.20 251 0.970 259
31/13-25-049-28W3/0 1994/09/10 1994.69 9409 8.20 245 0.970 253
21/02-25-049-28W3/0 1994/09/11 1994.70 9409 8.20 231 0.972 238
31/15-24-049-28W3/0 1994/09/12 1994.70 9409 8.20 235 0.971 242
31/16-23-049-28W3/0 1998/07/27 1998.57 9807 8.24 266 0.968 275
21/13-24-049-28W3/1 1998/07/27 1998.57 9807 8.24 260 0.968 269
31/13-24-049-28W3/0 1998/07/27 1998.57 9807 8.24 221 0.973 227
31/15-24-049-28W3/0 1998/07/27 1998.57 9807 8.24 260 0.968 269
21/02-25-049-28W3/0 1998/07/27 1998.57 9807 8.24 259 0.969 268
21/01-26-049-28W3/0 1998/07/27 1998.57 9807 8.24 266 0.968 275
-----------------------------------------------------------------------------------------------------------------
154
Sparky Gas Storage Well
C0/06-09-050-01W4/0
[LINE CHART]
---------------------------------------------------------------------------------------------------------------
Sort UID Julian Numeric Character Cum Gas Pressure Z P/Z
Order Date Date Date bcf psi psi
---------------------------------------------------------------------------------------------------------------
-0.81 170 0.959 177
1 C0/06-09-050-01W4/0 Aug 23, 1948 1948.64 4808 470 0.897 524
1 C0/06-09-050-01W4/0 Mar 28, 1951 1951.24 5103 0.38 374 0.915 408
1 C0/06-09-050-01W4/0 May 30, 1952 1952.41 5205 0.56 306 0.929 330
1 C0/06-09-050-01W4/0 May 30, 1953 1953.41 5305 0.64 282 0.934 302
1 C0/06-09-050-01W4/0 Jul 30, 1956 1956.58 5607 0.79 265 0.938 282
1 C0/06-09-050-01W4/0 Apr 27, 1959 1959.32 5904 0.82 245 0.942 260
16 C0/06-09-050-01W4/0 Mar 20, 1997 1997.22 9703 -0.81 126 0.969 130
16 C0/06-09-050-01W4/0 Jan 1, 2002 2002.00 10201 -0.81 162 0.961 168
---------------------------------------------------------------------------------------------------------------
155
Lloydminster Colony Formation
C0/08-22-050-02W4/2
[LINE CHART]
----------------------------------------------------------------------------------------------------------------
Julian Numeric Character Cum Gas Pressure Z P/Z
UID Date Date Date bcf psi psi
----------------------------------------------------------------------------------------------------------------
0.30 375 0.953 393
EUB Initial Pressure 1961/01/13 1961.04 6101 442 0.945 468
CO/08-22-050-02W4/2 1961/01/13 1961.04 6101 413 0.949 435
CO/08-22-050-02W4/2 1986/07/22 1986.56 8607 0.30 301 0.962 313
CO/08-22-050-02W4/2 1986/08/02 1986.59 8608 0.30 280 0.964 290
CO/08-22-050-02W4/2 1986/08/07 1986.60 8608 0.30 285 0.964 296
CO/08-22-050-02W4/2 1986/08/07 1986.60 8608 0.30 299 0.962 311
CO/08-22-050-02W4/2 1989/05/25 1989.40 8905 0.30 368 0.954 386
XxXxxxxxx'x 1995/09/15 1995.71 9509 0.30 363 0.954 381
CO/08-22-050-02W4/2 1990/10/18 1990.80 9010 0.30 346 0.956 362
CO/08-22-050-02W4/2 1994/09/13 1994.70 9409 0.30 321 0.959 335
----------------------------------------------------------------------------------------------------------------
156
PRODUCTION FORECAST
XXXXX CONNECTED TO MAIN SALES COMPRESSOR
157
ABERFELDY
41/14-15-049-27W3/0 - LLOYDMINSTER FORMATION
Wellbore Description
Roughness, in 7.00E-04
Depth, ft 1916
Deviation, deg 90
Flow Path Tubing
Tbg ID, in 1.051
Tbg OD, in 2.875
Csg ID, in 5.500
Calibration
q, mcf/d 379
P flow, psi 471
P tbg, psi 418.11
P csg, psi 450.02
Flowline, ft 4.044
Reservoir Conditions
Pool Number 1
OGIP mmcf 87
Pi psi 600
C mcfd/psi*2 0.001369
n 1.00
T surf o F 39
T res o F 60
Gas Analysis
H2 C1 91.37
He 0.16 C2 0.90
N2 7.02 C3 0.04
CO2 0.50 iC4 0.01
H2S nC4
SG 0.591 C5
Tc 662 C6
Pc 337 C7+
Calculated Production Information
Production Rate Cum Tbg Csg Reservoir Flow
Date Hours mcf mcd/d mmcf psi psi psi psi
Dec 31, 2001 395.4 56.1
Jan 31, 2002 744.0 968.2 31.2 57.1 156.9 163.4 216.4 164.3
Feb 28, 2002 672.0 790.7 28.2 57.9 154.6 161.1 210.8 161.9
Mar 31, 2002 744.0 57.9 181.6 189.2 210.8 189.2
Apr 30, 2002 720.0 365.4 12.2 58.3 180.8 188.4 208.3 188.6
May 31, 2002 744.0 58.3 179.0 186.5 208.3 186.5
Jun 30, 2002 720.0 400.9 13.4 58.7 175.8 183.1 205.4 183.3
Jul 31, 2002
Aug 31, 2002
Sep 30, 2002
Oct 31, 2002
Nov 30, 2002
Dec 31, 2002
Jan 31, 2003
Feb 28, 2003
Mar 31, 2003
Apr 30, 2003
May 31, 2003
Jun 30, 2003
Jul 31, 2003
Aug 31, 2003
Sep 30, 2003
Oct 31, 2003
Nov 30, 2003
Dec 31, 2003
Jan 31, 2004
Feb 29, 2004
Mar 31, 2004
Apr 30, 2004
May 31, 2004
Jun 30, 2004
Jul 31, 2004
Aug 31, 2004
Sep 30, 2004
Oct 31, 2004
Nov 30, 2004
Dec 31, 2004
Jan 31, 2005
Feb 28, 2005
Mar 31, 2005
Apr 30, 2005
May 31, 2005
Jun 30, 2005
Jul 31, 2005
Aug 31, 2005
Sep 30, 2005
Oct 31, 2005
Nov 30, 2005
Dec 31, 2005
158
ABERFELDY
41/14-15-049-27W3/0 - XXXXXXXX FORMATION
Wellbore Description
Roughness, in 7.00E-04
Depth, ft 1968
Deviation, deg 90
Flow Path Tubing
Tbg ID, in 1.270
Tbg OD, in 2.375
Csg ID, in 6.336
Calibration
q, mcf/d 122
P flow, psi 152
P tbg, psi 140.98
P csg, psi 145.49
Flowline, ft 4.044
Reservoir Conditions
Pool Number 2
OGIP mmcf 1500
Pi psi 622
C mcfd/psi*2 0.000749
n 1.00
T surf o F 39
T res o F 60
Gas Analysis
H2 C1 91.37
He 0.16 C2 0.90
N2 7.02 C3 0.04
CO2 0.50 iC4 0.01
H2S nC4
SG 0.591 C5
Tc 662 C6
Pc 337 C7+
Calculated Production Information
Production Rate Cum Tbg Csg Reservoir Flow
Date Hours mcf mcd/d mmcf psi psi psi psi
Dec 31, 2001 123.7 483.8
Jan 31, 2002 744.0 3,650.8 117.8 487.5 156.9 163.6 430.0 167.7
Feb 28, 2002 672.0 3,270.0 116.8 490.7 154.6 161.3 428.6 165.5
Mar 31, 2002 744.0 3,355.3 108.2 494.1 181.6 189.4 427.3 192.4
Apr 30, 2002 720.0 3,211.0 107.0 497.3 180.8 188.6 426.0 191.7
May 31, 2002 744.0 3,293.5 106.2 500.6 179.0 186.7 424.7 189.7
Jun 30, 2002 720.0 3,173.2 105.8 503.8 175.8 183.3 423.4 186.4
Jul 31, 2002 744.0 3,275.9 105.7 507.0 171.3 178.6 422.1 181.7
Aug 31, 2002 744.0 3,272.6 105.6 510.3 166.6 173.7 420.7 176.9
Sep 30, 2002 720.0 3,156.0 105.2 513.5 162.8 169.8 419.5 173.1
Oct 31, 2002 744.0 3,250.5 104.9 516.7 159.0 165.8 418.2 169.1
Nov 30, 2002 720.0 3,135.1 104.5 519.9 155.0 161.6 416.9 165.1
Dec 31, 2002 744.0 3,228.8 104.2 523.1 151.1 157.5 415.6 161.0
Jan 31, 2003 744.0 3,217.6 103.8 526.3 147.0 153.3 414.3 156.8
Feb 28, 2003 672.0 2,891.1 103.3 529.2 143.6 149.8 413.1 153.3
Mar 31, 2003 744.0 3,188.4 102.9 532.4 139.9 145.9 411.8 149.5
Apr 30, 2003 720.0 3,068.9 102.3 535.5 136.5 142.3 410.6 146.1
May 31, 2003 744.0 3,156.3 101.8 538.6 132.9 138.5 409.3 142.3
Jun 30, 2003 720.0 3,040.1 101.3 541.7 129.0 134.5 408.1 138.3
Jul 31, 2003 744.0 3,121.6 100.7 544.8 126.0 131.4 406.8 135.3
Aug 31, 2003 744.0 3,110.3 100.3 547.9 121.4 126.5 405.5 130.6
Sep 30, 2003 720.0 2,991.7 99.7 550.9 118.0 123.1 404.3 127.1
Oct 31, 2003 744.0 3,073.2 99.1 554.0 114.7 119.6 403.1 123.7
Nov 30, 2003 720.0 2,958.3 98.6 556.9 110.7 115.4 401.9 119.6
Dec 31, 2003 744.0 3,037.0 98.0 559.9 107.5 112.1 400.7 116.4
Jan 31, 2004 744.0 3,020.4 97.4 563.0 103.5 107.9 399.4 112.3
Feb 29, 2004 696.0 2,809.0 96.9 565.8 99.6 103.9 398.3 108.3
Mar 31, 2004 744.0 2,985.7 96.3 568.8 95.7 99.8 397.1 104.4
Apr 30, 2004 720.0 2,866.7 95.6 571.6 93.0 96.9 395.9 101.7
May 31, 2004 744.0 2,948.5 95.1 574.6 88.0 91.8 394.7 96.7
Jun 30, 2004 720.0 2,833.5 94.4 577.4 84.5 88.1 393.6 93.1
Jul 31, 2004 744.0 2,909.3 93.8 580.3 80.5 83.9 392.4 89.1
Aug 31, 2004 744.0 2,891.6 93.3 583.2 75.8 79.1 391.2 84.6
Sep 30, 2004 720.0 2,782.4 92.7 586.0 70.7 73.7 390.1 79.5
Oct 31, 2004 744.0 2,851.3 92.0 588.8 68.1 70.9 388.9 76.8
Nov 30, 2004 720.0 2,742.5 91.4 591.6 62.7 65.3 387.8 71.7
Dec 31, 2004 744.0 2,818.1 90.9 594.4 56.5 58.9 386.7 65.8
Jan 31, 2005 744.0 2,802.1 90.4 597.2 49.7 51.8 385.5 59.4
Feb 28, 2005 672.0 2,515.6 89.8 599.7 42.4 44.2 384.5 52.7
Mar 31, 2005 744.0 2,756.3 88.9 602.5 42.1 43.9 383.4 52.5
Apr 30, 2005 720.0 2,638.2 87.9 605.1 42.1 43.9 382.3 52.3
May 31, 2005 744.0 2,697.1 87.0 607.8 42.1 43.9 381.2 52.1
Jun 30, 2005 720.0 2,581.5 86.0 610.4 42.1 43.9 380.1 52.1
Jul 31, 2005 744.0 2,639.6 85.1 613.0 42.1 43.9 379.1 51.8
Aug 31, 2005 744.0 2,610.9 84.2 615.6 42.1 43.9 378.0 51.8
Sep 30, 2005 720.0 2,499.7 83.3 618.1 42.1 43.9 377.0 51.6
Oct 31, 2005 744.0 2,556.0 82.5 620.7 42.1 43.9 375.9 51.4
Nov 30, 2005 720.0 2,447.0 81.6 623.2 42.1 43.9 374.9 51.4
Dec 31, 2005 744.0 2,502.3 80.7 625.7 42.1 43.9 373.9 51.2
159
ABERFELDY
41/15-15-049-27W3/0 - SPARKY FORMATION
Wellbore Description
Roughness, in 7.00E-04
Depth, ft 1771
Deviation, deg 90
Flow Path Tubing
Tbg ID, in 1.910
Tbg OD, in 2.375
Csg ID, in 6.336
Calibration
q, mcf/d 613
P flow, psi 88
P tbg, psi 63.02
P csg, psi 85.02
Flowline, ft
Reservoir Conditions
Pool Number 3
OGIP mmcf 2200
Pi psi 460
C mcfd/psi*2 0.078109
n 1.00
T surf o F 39
T res o F 60
Gas Analysis
H2 C1 91.37
He 0.16 C2 0.90
N2 7.02 C3 0.04
CO2 0.50 iC4 0.01
H2S nC4
SG 0.591 C5
Tc 662 C6
Pc 337 C7+
Calculated Production Information
Production Rate Cum Tbg Csg Reservoir Flow
Date Hours mcf mcd/d mmcf psi psi psi psi
Dec 31, 2001 620.1 1,633.2
Jan 31, 2002 744.0 17,046.2 549.9 1,650.3 68.7 71.3 120.1 89.8
Feb 28, 2002 672.0 15,393.7 549.8 1,665.7 60.6 62.9 116.8 83.3
Mar 31, 2002 744.0 17,078.8 550.9 1,682.8 52.0 54.0 113.1 76.9
Apr 30, 2002 720.0 16,494.9 549.8 1,699.3 41.5 43.1 109.6 69.6
May 31, 2002 744.0 17,053.1 550.1 1,716.3 27.3 28.4 105.9 61.7
Jun 30, 2002 720.0 15,419.6 514.0 1,731.7 25.0 25.9 102.5 57.5
Jul 31, 2002 744.0 14,791.2 477.1 1,746.5 25.0 25.9 99.4 54.4
Aug 31, 2002 744.0 13,700.6 442.0 1,760.2 25.0 25.9 96.4 51.5
Sep 30, 2002 720.0 12,299.1 410.0 1,772.5 25.0 25.9 93.7 48.9
Oct 31, 2002 744.0 11,817.2 381.2 1,784.3 25.0 25.9 91.2 46.5
Nov 30, 2002 720.0 10,627.0 354.2 1,795.0 25.0 25.9 88.9 44.4
Dec 31, 2002 744.0 10,229.1 330.0 1,805.2 25.0 25.9 86.6 42.5
Jan 31, 2003 744.0 9,521.6 307.1 1,814.7 25.0 25.9 84.6 40.8
Feb 28, 2003 672.0 8,011.9 286.1 1,822.7 25.0 25.9 82.8 39.3
Mar 31, 2003 744.0 8,311.9 268.1 1,831.0 25.0 25.9 81.0 38.0
Apr 30, 2003 720.0 7,510.6 250.4 1,838.5 25.0 25.9 79.4 36.7
May 31, 2003 744.0 7,262.3 234.3 1,845.8 25.0 25.9 77.8 35.6
Jun 30, 2003 720.0 6,576.3 219.2 1,852.4 25.0 25.9 76.4 34.6
Jul 31, 2003 744.0 6,372.0 205.5 1,858.8 25.0 25.9 75.0 33.8
Aug 31, 2003 744.0 5,974.3 192.7 1,864.7 25.0 25.9 73.7 33.0
Sep 30, 2003 720.0 5,426.9 180.9 1,870.2 25.0 25.9 72.5 32.3
Oct 31, 2003 744.0 5,273.6 170.1 1,875.4 25.0 25.9 71.4 31.7
Nov 30, 2003 720.0 4,799.7 160.0 1,880.2 25.0 25.9 70.3 31.1
Dec 31, 2003 744.0 4,673.2 150.7 1,884.9 25.0 25.9 69.3 30.6
Jan 31, 2004 744.0 4,403.5 142.0 1,889.3 25.0 25.9 68.3 30.2
Feb 29, 2004 696.0 3,885.3 134.0 1,893.2 25.0 25.9 67.5 29.7
Mar 31, 2004 744.0 3,927.9 126.7 1,897.1 25.0 25.9 66.6 29.4
Apr 30, 2004 720.0 3,591.4 119.7 1,900.7 25.0 25.9 65.9 29.1
May 31, 2004 744.0 3,512.1 113.3 1,904.2 25.0 25.9 65.1 28.8
Jun 30, 2004 720.0 3,216.8 107.2 1,907.4 25.0 25.9 64.4 28.5
Jul 31, 2004 744.0 3,151.0 101.6 1,910.6 25.0 25.9 63.7 28.3
Aug 31, 2004 744.0 2,986.8 96.3 1,913.6 25.0 25.9 63.1 28.1
Sep 30, 2004 720.0 2,742.0 91.4 1,916.3 25.0 25.9 62.5 27.9
Oct 31, 2004 744.0 2,691.8 86.8 1,919.0 25.0 25.9 61.9 27.7
Nov 30, 2004 720.0 2,474.8 82.5 1,921.5 25.0 25.9 61.3 27.6
Dec 31, 2004 744.0 2,432.8 78.5 1,923.9 25.0 25.9 60.8 27.4
Jan 31, 2005 744.0 2,314.3 74.7 1,926.2 25.0 25.9 60.3 27.3
Feb 28, 2005 672.0 1,989.9 71.1 1,928.2 25.0 25.9 59.9 27.2
Mar 31, 2005 744.0 2,102.4 67.8 1,930.3 25.0 25.9 59.4 27.1
Apr 30, 2005 720.0 1,939.2 64.6 1,932.3 25.0 25.9 59.0 27.0
May 31, 2005 744.0 1,912.0 61.7 1,934.2 25.0 25.9 58.6 26.9
Jun 30, 2005 720.0 1,765.5 58.8 1,935.9 25.0 25.9 58.2 26.8
Jul 31, 2005 744.0 1,742.6 56.2 1,937.7 25.0 25.9 57.8 26.8
Aug 31, 2005 744.0 1,664.5 53.7 1,939.3 25.0 25.9 57.4 26.7
Sep 30, 2005 720.0 1,539.5 51.3 1,940.9 25.0 25.9 57.1 26.7
Oct 31, 2005 744.0 1,521.7 49.1 1,942.4 25.0 25.9 56.8 26.6
Nov 30, 2005 720.0 1,408.7 47.0 1,943.8 25.0 25.9 56.4 26.6
Dec 31, 2005 744.0 1,393.8 45.0 1,945.2 25.0 25.9 56.1 26.5
160
ABERFELDY
31/16-23-049-28W3/0 - COLONY FORMATION
Wellbore Description
Roughness, in 7.00E-04
Depth, ft 1695
Deviation, deg 90
Flow Path Tubing
Tbg ID, in 1.067
Tbg OD, in 2.375
Csg ID, in 6.336
Calibration
q, mcf/d 202
P flow, psi 192
P tbg, psi 164.95
P csg, psi 184.95
Flowline, ft 0.772
Reservoir Conditions
Pool Number 4
OGIP mmcf 17700
Pi psi 485
C mcfd/psi*2 0.006704
n 1.00
T surf o F 39
T res o F 60
Gas Analysis
H2 C1 91.37
He 0.16 C2 0.90
N2 7.02 C3 0.04
CO2 0.50 iC4 0.01
H2S nC4
SG 0.591 C5
Tc 662 C6
Pc 337 C7+
Calculated Production Information
Production Rate Cum Tbg Csg Reservoir Flow
Date Hours mcf mcd/d mmcf psi psi psi psi
Dec 31, 2001 204.9 725.3
Jan 31, 2002 744.0 7,165.6 231.1 732.5 147.1 152.5 259.3 183.2
Feb 28, 2002 672.0 6,430.0 229.6 738.9 144.8 150.2 257.7 180.7
Mar 31, 2002 744.0 5,739.0 185.1 744.6 171.7 178.1 256.2 195.9
Apr 30, 2002 720.0 5,454.7 181.8 750.1 171.0 177.3 254.7 194.8
May 31, 2002 744.0 5,626.7 181.5 755.7 169.2 175.4 253.3 192.6
Jun 30, 2002 720.0 5,463.4 182.1 761.2 166.0 172.1 251.8 190.1
Jul 31, 2002 744.0 5,756.0 185.7 766.9 161.5 167.4 250.3 186.3
Aug 31, 2002 744.0 5,861.6 189.1 772.8 156.8 162.6 248.8 182.4
Sep 30, 2002 720.0 5,706.6 190.2 778.5 153.0 158.6 247.3 179.3
Oct 31, 2002 744.0 5,934.3 191.4 784.4 149.1 154.6 245.7 176.3
Nov 30, 2002 720.0 5,807.4 193.6 790.2 145.2 150.5 244.2 172.7
Dec 31, 2002 744.0 6,028.0 194.5 796.3 141.2 146.4 242.7 169.7
Jan 31, 2003 744.0 6,051.5 195.2 802.3 137.2 142.2 241.1 166.6
Feb 28, 2003 672.0 5,477.6 195.6 807.8 133.8 138.7 239.7 163.6
Mar 31, 2003 744.0 6,106.3 197.0 813.9 130.1 134.9 238.1 160.3
Apr 30, 2003 720.0 5,914.0 197.1 819.8 126.7 131.3 236.6 157.4
May 31, 2003 744.0 6,128.1 197.7 826.0 123.0 127.6 235.1 154.3
Jun 30, 2003 720.0 5,947.1 198.2 831.9 119.2 123.6 233.5 151.0
Jul 31, 2003 744.0 6,123.4 197.5 838.0 116.2 120.5 232.0 148.5
Aug 31, 2003 744.0 6,137.0 198.0 844.2 111.5 115.6 230.4 145.2
Sep 30, 2003 720.0 5,951.4 198.4 850.1 108.2 112.2 228.9 141.9
Oct 31, 2003 744.0 6,132.2 197.8 856.2 104.9 108.7 227.4 139.2
Nov 30, 2003 720.0 5,935.7 197.9 862.2 100.9 104.6 225.9 135.9
Dec 31, 2003 744.0 6,103.5 196.9 868.3 97.7 101.2 224.4 133.4
Jan 31, 2004 744.0 6,095.6 196.6 874.4 93.7 97.1 222.9 130.3
Feb 29, 2004 696.0 5,686.8 196.1 880.1 89.8 93.1 221.4 127.4
Mar 31, 2004 744.0 6,066.7 195.7 886.1 85.9 89.0 219.9 124.4
Apr 30, 2004 720.0 5,841.0 194.7 892.0 83.1 86.2 218.5 121.7
May 31, 2004 744.0 6,043.4 194.9 898.0 78.2 81.1 217.0 118.2
Jun 30, 2004 720.0 5,804.6 193.5 903.8 74.7 77.5 215.5 115.7
Jul 31, 2004 744.0 5,999.3 193.5 909.8 70.7 73.2 214.1 112.2
Aug 31, 2004 744.0 5,976.1 192.8 915.8 66.0 68.4 212.6 109.1
Sep 30, 2004 720.0 5,765.9 192.2 921.6 60.9 63.1 211.2 105.9
Oct 31, 2004 744.0 5,911.2 190.7 927.5 58.2 60.4 209.7 103.5
Nov 30, 2004 720.0 5,696.0 189.9 933.2 52.9 54.8 208.3 100.4
Dec 31, 2004 744.0 5,868.6 189.3 939.0 46.7 48.4 206.9 97.0
Jan 31, 2005 744.0 5,844.8 188.5 944.9 39.8 41.3 205.5 93.7
Feb 28, 2005 672.0 5,274.0 188.4 950.2 32.6 33.8 204.2 89.8
Mar 31, 2005 744.0 5,751.2 185.5 955.9 32.3 33.5 202.8 88.7
Apr 30, 2005 720.0 5,471.1 182.4 961.4 32.3 33.5 201.5 87.8
May 31, 2005 744.0 5,561.2 179.4 966.9 32.3 33.5 200.2 86.9
Jun 30, 2005 720.0 5,292.2 176.4 972.2 32.3 33.5 198.9 86.0
Jul 31, 2005 744.0 5,407.1 174.4 977.6 32.3 33.5 197.6 84.1
Aug 31, 2005 744.0 5,318.9 171.6 983.0 32.3 33.5 196.3 83.2
Sep 30, 2005 720.0 5,064.5 168.8 988.0 32.3 33.5 195.1 82.3
Oct 31, 2005 744.0 5,152.5 166.2 993.2 32.3 33.5 193.8 81.4
Nov 30, 2005 720.0 4,907.8 163.6 998.1 32.3 33.5 192.7 80.5
Dec 31, 2005 744.0 4,994.8 161.1 1,003.1 32.3 33.5 191.4 79.6
161
ABERFELDY
01/12-24-049-28W3/0 - COLONY FORMATION
Wellbore Description
Roughness, in 7.00E-04
Depth, ft 1673
Deviation, deg 90
Flow Path Tubing
Tbg ID, in 1.157
Tbg OD, in 2.375
Csg ID, in 6.336
Calibration
q, mcf/d 389
P flow, psi 197
P tbg, psi 141.03
P csg, psi 189.95
Flowline, ft 0.551
Reservoir Conditions
Pool Number 4
OGIP mmcf 17700
Pi psi 485
C mcfd/psi*2 0.013786
n 1.00
T surf (Degrees) F 39
T res (Degrees) F 60
Gas Analysis
H2 C1 91.37
He 0.16 C2 0.90
N2 7.02 C3 0.04
CO2 0.50 iC4 0.01
H2S nC4
SG 0.591 C5
Tc 662 C6
Pc 337 C7+
Calculated Production Information
Production Rate Cum Tbg Csg Reservoir Flow
Date Hours mcf mcd/d mmcf psi psi psi psi
Dec 31, 2001 393.3 799.2
Jan 31, 2002 744.0 11,805.3 380.8 811.0 146.4 151.7 259.3 201.1
Feb 28, 2002 672.0 10,590.9 378.2 821.6 144.2 149.4 257.7 198.8
Mar 31, 2002 744.0 9,654.4 311.4 831.3 171.1 177.3 256.2 208.5
Apr 30, 2002 720.0 9,223.6 307.5 840.5 170.4 176.6 254.7 207.0
May 31, 2002 744.0 9,524.7 307.2 850.0 168.5 174.6 253.3 205.0
Jun 30, 2002 720.0 9,257.3 308.6 859.3 165.3 171.3 251.8 202.6
Jul 31, 2002 744.0 9,723.4 313.7 869.0 160.8 166.6 250.3 199.6
Aug 31, 2002 744.0 9,870.1 318.4 878.8 156.1 161.8 248.8 196.4
Sep 30, 2002 720.0 9,624.5 320.8 888.5 152.3 157.9 247.3 193.7
Oct 31, 2002 744.0 10,025.3 323.4 898.5 148.5 153.9 245.7 190.9
Nov 30, 2002 720.0 9,771.7 325.7 908.3 144.5 149.7 244.2 188.1
Dec 31, 2002 744.0 10,156.1 327.6 918.4 140.6 145.7 242.7 185.4
Jan 31, 2003 744.0 10,207.7 329.3 928.6 136.5 141.5 241.1 182.6
Feb 28, 2003 672.0 9,251.5 330.4 937.9 133.2 138.0 239.7 179.9
Mar 31, 2003 744.0 10,264.3 331.1 948.2 129.4 134.1 238.1 177.5
Apr 30, 2003 720.0 9,951.5 331.7 958.1 126.0 130.6 236.6 174.9
May 31, 2003 744.0 10,326.6 333.1 968.4 122.4 126.8 235.1 172.1
Jun 30, 2003 720.0 10,035.8 334.5 978.5 118.6 122.8 233.5 169.2
Jul 31, 2003 744.0 10,334.3 333.4 988.8 115.5 119.7 232.0 167.0
Aug 31, 2003 744.0 10,365.4 334.4 999.2 110.9 114.9 230.4 164.1
Sep 30, 2003 720.0 10,069.4 335.6 1,009.2 107.6 111.4 228.9 161.2
Oct 31, 2003 744.0 10,377.7 334.8 1,019.6 104.2 108.0 227.4 158.8
Nov 30, 2003 720.0 10,053.6 335.1 1,029.7 100.2 103.8 225.9 156.0
Dec 31, 2003 744.0 10,335.8 333.4 1,040.0 97.0 100.5 224.4 153.8
Jan 31, 2004 744.0 10,327.8 333.2 1,050.3 93.0 96.4 222.9 151.2
Feb 29, 2004 696.0 9,637.3 332.3 1,060.0 89.1 92.3 221.4 148.7
Mar 31, 2004 744.0 10,285.0 331.8 1,070.3 85.2 88.3 219.9 146.2
Apr 30, 2004 720.0 9,904.9 330.2 1,080.2 82.5 85.5 218.5 143.9
May 31, 2004 744.0 10,258.3 330.9 1,090.4 77.5 80.3 217.0 140.9
Jun 30, 2004 720.0 9,910.4 330.3 1,100.3 74.1 76.7 215.5 138.2
Jul 31, 2004 744.0 10,189.1 328.7 1,110.5 70.0 72.5 214.1 136.0
Aug 31, 2004 744.0 10,149.3 327.4 1,120.7 65.4 67.7 212.6 133.5
Sep 30, 2004 720.0 9,793.2 326.4 1,130.5 60.2 62.4 211.2 130.9
Oct 31, 2004 744.0 10,102.0 325.9 1,140.6 57.6 59.6 209.7 128.2
Nov 30, 2004 720.0 9,732.5 324.4 1,150.3 52.2 54.1 208.3 125.7
Dec 31, 2004 744.0 10,027.9 323.5 1,160.3 46.0 47.7 206.9 123.1
Jan 31, 2005 744.0 9,985.0 322.1 1,170.3 39.2 40.6 205.5 120.6
Feb 28, 2005 672.0 9,017.6 322.1 1,179.3 31.9 33.0 204.2 117.5
Mar 31, 2005 744.0 9,818.4 316.7 1,189.1 31.7 32.8 202.8 116.7
Apr 30, 2005 720.0 9,381.3 312.7 1,198.5 31.7 32.8 201.5 115.2
May 31, 2005 744.0 9,579.3 309.0 1,208.1 31.7 32.8 200.2 113.6
Jun 30, 2005 720.0 9,156.8 305.2 1,217.3 31.7 32.8 198.9 112.1
Jul 31, 2005 744.0 9,353.9 301.7 1,226.6 31.7 32.8 197.6 110.6
Aug 31, 2005 744.0 9,243.3 298.2 1,235.9 31.7 32.8 196.3 109.1
Sep 30, 2005 720.0 8,787.7 292.9 1,244.6 31.7 32.8 195.1 108.3
Oct 31, 2005 744.0 8,928.0 288.0 1,253.6 31.7 32.8 193.8 107.6
Nov 30, 2005 720.0 8,544.4 284.8 1,262.1 31.7 32.8 192.7 106.1
Dec 31, 2005 744.0 8,737.8 281.9 1,270.9 31.7 32.8 191.4 104.5
162
ABERFELDY
21/13-24-049-28W3/0 - COLONY FORMATION
Wellbore Description
Roughness, in 7.00E-04
Depth, ft 1703
Deviation, deg 90
Flow Path Tubing
Tbg ID, in 0.733
Tbg OD, in 2.375
Csg ID, in 6.336
Calibration
q, mcf/d 134
P flow, psi 189
P tbg, psi 107.34
P csg, psi 181.94
Flowline, ft 0.515
Reservoir Conditions
Pool Number 4
OGIP mmcf 17700
Pi psi 485
C mcfd/psi*2 0.004267
n 1.00
T surf (DEGREES) F 39
T res (DEGREES) F 60
Gas Analysis
H2 C1 91.37
He 0.16 C2 0.90
N2 7.02 C3 0.04
CO2 0.50 iC4 0.01
H2S nC4
SG 0.591 C5
Tc 662 C6
Pc 337 C7+
Calculated Production Information
Production Rate Cum Tbg Csg Reservoir Flow
Date Hours mcf mcd/d mmcf psi psi psi psi
Dec 31, 2001 135.5 975.5
Jan 31, 2002 744.0 3,491.0 112.6 979.0 146.3 151.7 259.3 201.8
Feb 28, 2002 672.0 3,113.6 111.2 982.1 144.1 149.4 257.7 197.4
Mar 31, 2002 744.0 2,783.5 89.8 984.9 171.0 177.3 256.2 206.5
Apr 30, 2002 720.0 2,604.3 86.8 987.5 170.3 176.6 254.7 204.2
May 31, 2002 744.0 2,634.0 85.0 990.1 168.4 174.6 253.3 201.2
Jun 30, 2002 720.0 2,512.5 83.7 992.6 165.2 171.3 251.8 197.6
Jul 31, 2002 744.0 2,576.7 83.1 995.2 160.7 166.6 250.3 193.6
Aug 31, 2002 744.0 2,565.4 82.8 997.8 156.0 161.8 248.8 189.1
Sep 30, 2002 720.0 2,438.1 81.3 1,000.2 152.2 157.9 247.3 185.4
Oct 31, 2002 744.0 2,485.4 80.2 1,002.7 148.4 153.9 245.7 181.3
Nov 30, 2002 720.0 2,369.6 79.0 1,005.1 144.4 149.7 244.2 177.1
Dec 31, 2002 744.0 2,418.0 78.0 1,007.5 140.5 145.7 242.7 172.7
Jan 31, 2003 744.0 2,384.3 76.9 1,009.9 136.4 141.5 241.1 168.1
Feb 28, 2003 672.0 2,098.6 74.9 1,012.0 133.0 138.0 239.7 164.4
Mar 31, 2003 744.0 2,274.2 73.4 1,014.2 129.3 134.1 238.1 160.4
Apr 30, 2003 720.0 2,155.9 71.9 1,016.4 125.9 130.5 236.6 156.0
May 31, 2003 744.0 2,170.0 70.0 1,018.6 122.3 126.8 235.1 152.2
Jun 30, 2003 720.0 2,058.5 68.6 1,020.6 118.4 122.8 233.5 147.4
Jul 31, 2003 744.0 2,058.1 66.4 1,022.7 115.4 119.7 232.0 144.1
Aug 31, 2003 744.0 2,018.1 65.1 1,024.7 110.8 114.9 230.4 138.9
Sep 30, 2003 720.0 1,894.9 63.2 1,026.6 107.5 111.4 228.9 135.0
Oct 31, 2003 744.0 1,905.2 61.5 1,028.5 104.1 107.9 227.4 130.6
Nov 30, 2003 720.0 1,788.4 59.6 1,030.3 100.1 103.8 225.9 126.4
Dec 31, 2003 744.0 1,793.1 57.8 1,032.1 96.9 100.5 224.4 122.2
Jan 31, 2004 744.0 1,736.1 56.0 1,033.8 92.9 96.3 222.9 118.0
Feb 29, 2004 696.0 1,577.7 54.4 1,035.4 89.0 92.3 221.4 113.2
Mar 31, 2004 744.0 1,631.1 52.6 1,037.0 85.1 88.2 219.9 109.1
Apr 30, 2004 720.0 1,522.1 50.7 1,038.6 82.4 85.4 218.5 105.2
May 31, 2004 744.0 1,525.0 49.2 1,040.1 77.4 80.3 217.0 100.3
Jun 30, 2004 720.0 1,422.6 47.4 1,041.5 74.0 76.7 215.5 96.2
Jul 31, 2004 744.0 1,420.1 45.8 1,042.9 69.9 72.4 214.1 91.7
Aug 31, 2004 744.0 1,370.0 44.2 1,044.3 65.3 67.6 212.6 87.1
Sep 30, 2004 720.0 1,282.3 42.7 1,045.6 60.1 62.3 211.2 81.7
Oct 31, 2004 744.0 1,270.2 41.0 1,046.8 57.5 59.6 209.7 78.3
Nov 30, 2004 720.0 1,184.9 39.5 1,048.0 52.1 54.0 208.3 73.2
Dec 31, 2004 744.0 1,183.5 38.2 1,049.2 45.9 47.6 206.9 67.2
Jan 31, 2005 744.0 1,140.7 36.8 1,050.4 39.1 40.5 205.5 61.3
Feb 28, 2005 672.0 992.9 35.5 1,051.4 31.8 33.0 204.2 55.0
Mar 31, 2005 744.0 1,044.9 33.7 1,052.4 31.5 32.7 202.8 53.8
Apr 30, 2005 720.0 960.9 32.0 1,053.4 31.5 32.7 201.5 52.1
May 31, 2005 744.0 943.9 30.4 1,054.3 31.5 32.7 200.2 50.6
Jun 30, 2005 720.0 868.1 28.9 1,055.2 31.5 32.7 198.9 49.0
Jul 31, 2005 744.0 851.7 27.5 1,056.0 31.5 32.7 197.6 48.0
Aug 31, 2005 744.0 808.8 26.1 1,056.8 31.5 32.7 196.3 46.7
Sep 30, 2005 720.0 743.4 24.8 1,057.6 31.5 32.7 195.1 45.5
Oct 31, 2005 744.0 729.6 23.5 1,058.3 31.5 32.7 193.8 44.6
Nov 30, 2005 720.0 670.3 22.3 1,059.0 31.5 32.7 192.7 43.6
Dec 31, 2005 744.0 657.9 21.2 1,059.6 31.5 32.7 191.4 42.7
163
ABERFELDY
31/15-24-049-28W3/0 - COLONY FORMATION
Wellbore Description
Roughness, in 7.00E-04
Depth, ft 1673
Deviation, deg 90
Flow Path Tubing
Tbg ID, in 0.980
Tbg OD, in 2.375
Csg ID, in 6.336
Calibration
q, mcf/d 355
P flow, psi 255
P tbg, psi 169.07
P csg, psi 245.36
Flowline, ft 0.110
Reservoir Conditions
Pool Number 4
OGIP mmcf 17700
Pi psi 485
C mcfd/psi*2 0.496142
n 1.00
T surf o F 39
T res o F 60
Gas Analysis
H2 C1 91.37
He 0.16 C2 0.90
N2 7.02 C3 0.04
CO2 0.50 iC4 0.01
H2S nC4
SG 0.591 C5
Tc 662 C6
Pc 337 C7+
Calculated Production Information
Production Rate Cum Tbg Csg Reservoir Flow
Date Hours mcf mcd/d mmcf psi psi psi psi
Dec 31, 2001 575.2 499.2
Jan 31, 2002
Feb 28, 2002
Mar 31, 2002 744.0 10,823.4 349.1 531.0 169.7 175.9 256.2 256.2
Apr 30, 2002 720.0 10,360.7 345.4 541.3 169.0 175.2 254.7 254.6
May 31, 2002 744.0 10,717.1 345.7 552.0 167.2 173.3 253.3 253.1
Jun 30, 2002 720.0 10,378.0 345.9 562.4 164.0 170.0 251.8 251.5
Jul 31, 2002 744.0 11,002.0 354.9 573.4 159.5 165.3 250.3 249.9
Aug 31, 2002 744.0 10,952.6 353.3 584.4 154.8 160.4 248.8 248.3
Sep 30, 2002 720.0 10,832.5 361.1 595.2 151.0 156.5 247.3 246.6
Oct 31, 2002 744.0 11,234.9 362.4 606.4 147.2 152.5 245.7 245.0
Nov 30, 2002 720.0 10,851.2 361.7 617.3 143.2 148.4 244.2 243.4
Dec 31, 2002 744.0 11,291.5 364.2 628.6 139.3 144.3 242.7 241.8
Jan 31, 2003 744.0 11,328.4 365.4 639.9 135.2 140.1 241.1 240.1
Feb 28, 2003 672.0 10,262.3 366.5 650.2 131.8 136.6 239.7 238.4
Mar 31, 2003 744.0 11,377.9 367.0 661.6 128.1 132.7 238.1 236.8
Apr 30, 2003 720.0 11,164.9 372.2 672.7 124.7 129.2 236.6 235.1
May 31, 2003 744.0 11,459.5 369.7 684.2 121.1 125.4 235.1 233.4
Jun 30, 2003 720.0 11,011.8 367.1 695.2 117.2 121.5 233.5 231.8
Jul 31, 2003 744.0 11,565.0 373.1 706.8 114.2 118.4 232.0 230.0
Aug 31, 2003 744.0 11,455.6 369.5 718.2 109.6 113.5 230.4 228.3
Sep 30, 2003 720.0 11,099.3 370.0 729.3 106.2 110.1 228.9 226.6
Oct 31, 2003 744.0 11,532.9 372.0 740.8 102.9 106.6 227.4 224.9
Nov 30, 2003 720.0 11,070.8 369.0 751.9 98.9 102.5 225.9 223.2
Dec 31, 2003 744.0 11,600.8 374.2 763.5 95.7 99.1 224.4 221.4
Jan 31, 2004 744.0 11,538.5 372.2 775.1 91.7 95.0 222.9 219.7
Feb 29, 2004 696.0 10,789.6 372.1 785.8 87.8 91.0 221.4 217.9
Mar 31, 2004 744.0 11,480.2 370.3 797.3 83.9 86.9 219.9 216.3
Apr 30, 2004 720.0 11,198.2 373.3 808.5 81.2 84.1 218.5 214.5
May 31, 2004 744.0 11,415.7 368.2 819.9 76.2 79.0 217.0 212.9
Jun 30, 2004 720.0 11,078.5 369.3 831.0 72.7 75.4 215.5 211.1
Jul 31, 2004 744.0 11,448.2 369.3 842.5 68.7 71.1 214.1 209.3
Aug 31, 2004 744.0 11,428.8 368.7 853.9 64.0 66.3 212.6 207.6
Sep 30, 2004 720.0 11,010.7 367.0 864.9 58.9 61.0 211.2 205.8
Oct 31, 2004 744.0 11,458.6 369.6 876.4 56.3 58.3 209.7 204.0
Nov 30, 2004 720.0 11,061.8 368.7 887.4 50.9 52.7 208.3 202.2
Dec 31, 2004 744.0 11,326.2 365.4 898.7 44.7 46.3 206.9 200.5
Jan 31, 2005 744.0 11,272.8 363.6 910.0 37.9 39.2 205.5 198.7
Feb 28, 2005 672.0 10,111.5 361.1 920.1 30.6 31.7 204.2 197.0
Mar 31, 2005 744.0 11,188.8 360.9 931.3 30.3 31.4 202.8 195.3
Apr 30, 2005 720.0 10,783.9 359.5 942.1 30.3 31.4 201.5 193.5
May 31, 2005 744.0 10,985.2 354.4 953.1 30.3 31.4 200.2 191.8
Jun 30, 2005 720.0 10,597.1 353.2 963.7 30.3 31.4 198.9 190.0
Jul 31, 2005 744.0 10,809.8 348.7 974.5 30.3 31.4 197.6 188.4
Aug 31, 2005 744.0 10,636.1 343.1 985.1 30.3 31.4 196.3 186.7
Sep 30, 2005 720.0 10,269.8 342.3 995.4 30.3 31.4 195.1 184.9
Oct 31, 2005 744.0 10,362.7 334.3 1,005.8 30.3 31.4 193.8 183.4
Nov 30, 2005 720.0 10,010.2 333.7 1,015.8 30.3 31.4 192.7 181.6
Dec 31, 2005 744.0 10,232.7 330.1 1,026.0 30.3 31.4 191.4 180.0
164
ABERFELDY
21/02-25-049-28W3/0 - COLONY FORMATION
Wellbore Description
Roughness, in 7.00E-04
Depth, ft 1659
Deviation, deg 90
Flow Path Tubing
Tbg ID, in 0.746
Tbg OD, in 2.375
Csg ID, in 6.336
Calibration
q, mcf/d 167
P flow, psi 218
P tbg, psi 121.24
P csg, psi 210.03
Flowline, ft
Reservoir Conditions
Pool Number 4
OGIP mmcf 17700
Pi psi 485
C mcfd/psi*2 0.008530
n 1.00
T surf o F 39
T res o F 60
Gas Analysis
H2 C1 91.37
He 0.16 C2 0.90
N2 7.02 C3 0.04
CO2 0.50 iC4 0.01
H2S nC4
SG 0.591 C5
Tc 662 C6
Pc 337 C7+
Calculated Production Information
Production Rate Cum Tbg Csg Reservoir Flow
Date Hours mcf mcd/d mmcf psi psi psi psi
Dec 31, 2001 169.0 509.5
Jan 31, 2002 744.0 4,673.8 150.8 514.2 144.8 150.0 259.3 223.2
Feb 28, 2002 672.0 4,173.7 149.1 518.3 142.5 147.6 257.7 219.8
Mar 31, 2002 744.0 3,887.3 125.4 522.2 169.4 175.5 256.2 223.2
Apr 30, 2002 720.0 3,681.4 122.7 525.9 168.7 174.8 254.7 220.7
May 31, 2002 744.0 3,743.0 120.7 529.7 166.9 172.9 253.3 218.0
Jun 30, 2002 720.0 3,618.1 120.6 533.3 163.7 169.6 251.8 214.7
Jul 31, 2002 744.0 3,720.9 120.0 537.0 159.1 164.9 250.3 211.4
Aug 31, 2002 744.0 3,726.6 120.2 540.7 154.5 160.0 248.8 207.6
Sep 30, 2002 720.0 3,574.4 119.1 544.3 150.7 156.1 247.3 204.2
Oct 31, 2002 744.0 3,688.5 119.0 548.0 146.8 152.1 245.7 200.4
Nov 30, 2002 720.0 3,529.8 117.7 551.5 142.8 148.0 244.2 196.9
Dec 31, 2002 744.0 3,599.0 116.1 555.1 138.9 143.9 242.7 193.5
Jan 31, 2003 744.0 3,571.1 115.2 558.7 134.9 139.7 241.1 189.5
Feb 28, 2003 672.0 3,209.5 114.6 561.9 131.5 136.2 239.7 185.3
Mar 31, 2003 744.0 3,507.0 113.1 565.4 127.8 132.3 238.1 181.6
Apr 30, 2003 720.0 3,321.7 110.7 568.7 124.4 128.8 236.6 178.2
May 31, 2003 744.0 3,406.0 109.9 572.1 120.7 125.1 235.1 173.8
Jun 30, 2003 720.0 3,229.8 107.7 575.4 116.9 121.1 233.5 170.1
Jul 31, 2003 744.0 3,279.8 105.8 578.6 113.9 118.0 232.0 166.1
Aug 31, 2003 744.0 3,227.7 104.1 581.9 109.2 113.1 230.4 161.9
Sep 30, 2003 720.0 3,065.6 102.2 584.9 105.9 109.7 228.9 157.7
Oct 31, 2003 744.0 3,107.5 100.2 588.0 102.6 106.2 227.4 153.5
Nov 30, 2003 720.0 2,930.1 97.7 591.0 98.6 102.1 225.9 149.8
Dec 31, 2003 744.0 2,959.4 95.5 593.9 95.4 98.8 224.4 145.7
Jan 31, 2004 744.0 2,901.6 93.6 596.8 91.4 94.6 222.9 141.1
Feb 29, 2004 696.0 2,655.2 91.6 599.5 87.5 90.6 221.4 136.5
Mar 31, 2004 744.0 2,776.5 89.6 602.3 83.6 86.6 219.9 132.0
Apr 30, 2004 720.0 2,604.6 86.8 604.9 80.8 83.7 218.5 128.2
May 31, 2004 744.0 2,638.0 85.1 607.5 75.9 78.6 217.0 123.0
Jun 30, 2004 720.0 2,478.7 82.6 610.0 72.4 75.0 215.5 118.8
Jul 31, 2004 744.0 2,492.1 80.4 612.5 68.3 70.8 214.1 114.2
Aug 31, 2004 744.0 2,409.8 77.7 614.9 63.7 66.0 212.6 110.3
Sep 30, 2004 720.0 2,271.0 75.7 617.2 58.6 60.6 211.2 105.2
Oct 31, 2004 744.0 2,269.7 73.2 619.4 55.9 57.9 209.7 101.0
Nov 30, 2004 720.0 2,127.7 70.9 621.6 50.5 52.3 208.3 96.4
Dec 31, 2004 744.0 2,137.8 69.0 623.7 44.4 45.9 206.9 90.9
Jan 31, 2005 744.0 2,075.2 66.9 625.8 37.5 38.9 205.5 85.3
Feb 28, 2005 672.0 1,815.4 64.8 627.6 30.3 31.3 204.2 79.8
Mar 31, 2005 744.0 1,921.9 62.0 629.5 30.0 31.1 202.8 77.4
Apr 30, 2005 720.0 1,779.2 59.3 631.3 30.0 31.1 201.5 74.5
May 31, 2005 744.0 1,759.2 56.7 633.0 30.0 31.1 200.2 71.7
Jun 30, 2005 720.0 1,624.2 54.1 634.7 30.0 31.1 198.9 69.4
Jul 31, 2005 744.0 1,601.9 51.7 636.3 30.0 31.1 197.6 67.1
Aug 31, 2005 744.0 1,528.1 49.3 637.8 30.0 31.1 196.3 64.9
Sep 30, 2005 720.0 1,410.7 47.0 639.2 30.0 31.1 195.1 62.6
Oct 31, 2005 744.0 1,391.0 44.9 640.6 30.0 31.1 193.8 60.4
Nov 30, 2005 720.0 1,281.6 42.7 641.9 30.0 31.1 192.7 58.8
Dec 31, 2005 744.0 1,261.3 40.7 643.1 30.0 31.1 191.4 57.2
165
ABERFELDY
21/06-25-049-28W3/0 - COLONY FORMATION
Wellbore Description
Roughness, in 7.00E-04
Depth, ft 1695
Deviation, deg 90
Flow Path Tubing
Tbg ID, in 0.795
Tbg OD, in 2.375
Csg ID, in 6.336
Calibration
q, mcf/d 188
P flow, psi 209
P tbg, psi 114.40
P csg, psi 201.21
Flowline, ft 0.368
Reservoir Conditions
Pool Number 4
OGIP mmcf 17700
Pi psi 485
C mcfd/psi*2 0.008039
n 1.00
T surf o F 39
T res o F 60
Gas Analysis
H2 C1 91.37
He 0.16 C2 0.90
N2 7.02 C3 0.04
CO2 0.50 iC4 0.01
H2S nC4
SG 0.591 C5
Tc 662 C6
Pc 337 C7+
Calculated Production Information
Production Rate Cum Tbg Csg Reservoir Flow
Date Hours mcf mcd/d mmcf psi psi psi psi
Dec 31, 2001 190.5 843.1
Jan 31, 2002 744.0 5,115.0 165.0 848.2 145.9 151.2 259.3 216.4
Feb 28, 2002 672.0 4,517.5 161.3 852.7 143.6 148.9 257.7 213.3
Mar 31, 2002 744.0 4,194.2 135.3 856.9 170.5 176.8 256.2 217.7
Apr 30, 2002 720.0 3,953.6 131.8 860.9 169.8 176.1 254.7 215.3
May 31, 2002 744.0 4,013.9 129.5 864.9 168.0 174.2 253.3 212.5
Jun 30, 2002 720.0 3,850.3 128.3 868.7 164.8 170.8 251.8 209.1
Jul 31, 2002 744.0 3,977.1 128.3 872.7 160.3 166.2 250.3 205.4
Aug 31, 2002 744.0 3,966.2 127.9 876.7 155.6 161.3 248.8 201.5
Sep 30, 2002 720.0 3,808.0 126.9 880.5 151.8 157.4 247.3 197.7
Oct 31, 2002 744.0 3,902.0 125.9 884.4 147.9 153.4 245.7 193.9
Nov 30, 2002 720.0 3,738.0 124.6 888.1 143.9 149.2 244.2 190.0
Dec 31, 2002 744.0 3,815.3 123.1 892.0 140.0 145.2 242.7 186.2
Jan 31, 2003 744.0 3,763.2 121.4 895.7 136.0 141.0 241.1 182.3
Feb 28, 2003 672.0 3,352.7 119.7 899.1 132.6 137.5 239.7 178.2
Mar 31, 2003 744.0 3,645.7 117.6 902.7 128.9 133.6 238.1 174.5
Apr 30, 2003 720.0 3,469.2 115.6 906.2 125.5 130.1 236.6 170.5
May 31, 2003 744.0 3,529.7 113.9 909.7 121.8 126.3 235.1 166.2
Jun 30, 2003 720.0 3,360.6 112.0 913.1 118.0 122.3 233.5 161.9
Jul 31, 2003 744.0 3,390.1 109.4 916.5 115.0 119.2 232.0 158.1
Aug 31, 2003 744.0 3,322.9 107.2 919.8 110.3 114.4 230.4 153.8
Sep 30, 2003 720.0 3,137.3 104.6 922.9 107.0 110.9 228.9 149.8
Oct 31, 2003 744.0 3,183.6 102.7 926.1 103.7 107.5 227.4 145.1
Nov 30, 2003 720.0 3,012.4 100.4 929.1 99.7 103.3 225.9 140.6
Dec 31, 2003 744.0 3,026.1 97.6 932.1 96.5 100.0 224.4 136.7
Jan 31, 2004 744.0 2,951.2 95.2 935.1 92.5 95.8 222.9 132.2
Feb 29, 2004 696.0 2,687.2 92.7 937.8 88.6 91.8 221.4 127.9
Mar 31, 2004 744.0 2,796.8 90.2 940.6 84.7 87.8 219.9 123.5
Apr 30, 2004 720.0 2,626.9 87.6 943.2 81.9 84.9 218.5 119.2
May 31, 2004 744.0 2,635.1 85.0 945.8 77.0 79.8 217.0 114.8
Jun 30, 2004 720.0 2,478.8 82.6 948.3 73.5 76.2 215.5 110.0
Jul 31, 2004 744.0 2,482.8 80.1 950.8 69.4 72.0 214.1 105.6
Aug 31, 2004 744.0 2,407.8 77.7 953.2 64.8 67.2 212.6 100.7
Sep 30, 2004 720.0 2,260.7 75.4 955.5 59.7 61.8 211.2 95.6
Oct 31, 2004 744.0 2,245.3 72.4 957.7 57.0 59.1 209.7 92.2
Nov 30, 2004 720.0 2,104.3 70.1 959.8 51.6 53.5 208.3 87.0
Dec 31, 2004 744.0 2,107.7 68.0 961.9 45.5 47.1 206.9 81.5
Jan 31, 2005 744.0 2,040.1 65.8 964.0 38.6 40.0 205.5 75.8
Feb 28, 2005 672.0 1,780.1 63.6 965.7 31.4 32.5 204.2 70.2
Mar 31, 2005 744.0 1,879.8 60.6 967.6 31.1 32.2 202.8 68.1
Apr 30, 2005 720.0 1,737.7 57.9 969.4 31.1 32.2 201.5 65.3
May 31, 2005 744.0 1,710.1 55.2 971.1 31.1 32.2 200.2 63.4
Jun 30, 2005 720.0 1,575.4 52.5 972.7 31.1 32.2 198.9 61.5
Jul 31, 2005 744.0 1,550.4 50.0 974.2 31.1 32.2 197.6 59.7
Aug 31, 2005 744.0 1,475.9 47.6 975.7 31.1 32.2 196.3 57.8
Sep 30, 2005 720.0 1,359.6 45.3 977.0 31.1 32.2 195.1 56.0
Oct 31, 2005 744.0 1,338.1 43.2 978.4 31.1 32.2 193.8 54.3
Nov 30, 2005 720.0 1,232.7 41.1 979.6 31.1 32.2 192.7 52.5
Dec 31, 2005 744.0 1,211.5 39.1 980.8 31.1 32.2 191.4 51.2
166
ABERFELDY
31/13-25-049-28W3/0 - COLONY FORMATION
Wellbore Description
Roughness, in 7.00E-04
Depth, ft 1965
Deviation, deg 90
Flow Path Tubing
Tbg ID, in 1.000
Tbg OD, in 2.375
Csg ID, in 6.336
Calibration
q, mcf/d 298
P flow, psi 212
P tbg, psi 131.71
P csg, psi 202.86
Flowline, ft 1.103
Reservoir Conditions
Pool Number 4
OGIP mmcf 17700
Pi psi 485
C mcfd/psi*2 0.013468
n 1.00
T surf (degree) F 39
T res (degree) F 60
Gas Analysis
H2 C1 91.37
He 0.16 C2 0.90
N2 7.02 C3 0.04
CO2 0.50 iC4 0.01
H2S nC4
SG 0.591 C5
Tc 662 C6
Pc 337 C7+
Calculated Production Information
Production Rate Cum Tbg Csg Reservoir Flow
Date Hours mcf mcd/d mmcf psi psi psi psi
Dec 31, 2001 302.0 1,234.8
Jan 31, 2002 744.0 8,610.5 277.8 1,243.4 148.1 154.4 259.3 217.9
Feb 28, 2002 672.0 7,720.8 275.7 1,251.1 145.8 152.1 257.7 215.8
Mar 31, 2002 744.0 7,181.5 231.7 1,258.3 172.7 180.1 256.2 221.2
Apr 30, 2002 720.0 6,837.5 227.9 1,265.2 172.0 179.4 254.7 219.9
May 31, 2002 744.0 7,072.3 228.1 1,272.2 170.2 177.5 253.3 218.0
Jun 30, 2002 720.0 6,845.2 228.2 1,279.1 167.0 174.1 251.8 216.0
Jul 31, 2002 744.0 7,261.4 234.2 1,286.3 162.5 169.4 250.3 213.0
Aug 31, 2002 744.0 7,307.6 235.7 1,293.6 157.8 164.5 248.8 210.7
Sep 30, 2002 720.0 7,105.0 236.8 1,300.7 154.0 160.6 247.3 208.5
Oct 31, 2002 744.0 7,447.5 240.2 1,308.2 150.1 156.6 245.7 205.8
Nov 30, 2002 720.0 7,302.1 243.4 1,315.5 146.2 152.4 244.2 203.1
Dec 31, 2002 744.0 7,563.2 244.0 1,323.1 142.2 148.3 242.7 200.9
Jan 31, 2003 744.0 7,574.0 244.3 1,330.6 138.2 144.1 241.1 198.7
Feb 28, 2003 672.0 6,891.2 246.1 1,337.5 134.8 140.6 239.7 196.2
Mar 31, 2003 744.0 7,676.6 247.6 1,345.2 131.1 136.7 238.1 193.9
Apr 30, 2003 720.0 7,402.3 246.7 1,352.6 127.7 133.1 236.6 191.9
May 31, 2003 744.0 7,712.9 248.8 1,360.3 124.0 129.3 235.1 189.3
Jun 30, 2003 720.0 7,526.3 250.9 1,367.8 120.2 125.3 233.5 186.6
Jul 31, 2003 744.0 7,761.3 250.4 1,375.6 117.2 122.2 232.0 184.5
Aug 31, 2003 744.0 7,752.4 250.1 1,383.4 112.5 117.3 230.4 182.3
Sep 30, 2003 720.0 7,492.0 249.7 1,390.8 109.2 113.9 228.9 180.1
Oct 31, 2003 744.0 7,735.0 249.5 1,398.6 105.9 110.4 227.4 177.9
Nov 30, 2003 720.0 7,516.3 250.5 1,406.1 101.9 106.2 225.9 175.4
Dec 31, 2003 744.0 7,734.2 249.5 1,413.8 98.7 102.9 224.4 173.4
Jan 31, 2004 744.0 7,747.0 249.9 1,421.6 94.7 98.7 222.9 171.0
Feb 29, 2004 696.0 7,242.3 249.7 1,428.8 90.8 94.6 221.4 168.7
Mar 31, 2004 744.0 7,745.0 249.8 1,436.6 86.9 90.6 219.9 166.5
Apr 30, 2004 720.0 7,522.9 250.8 1,444.1 84.1 87.7 218.5 163.9
May 31, 2004 744.0 7,754.4 250.1 1,451.8 79.2 82.6 217.0 161.8
Jun 30, 2004 720.0 7,502.5 250.1 1,459.3 75.7 78.9 215.5 159.4
Jul 31, 2004 744.0 7,721.2 249.1 1,467.1 71.7 74.7 214.1 157.4
Aug 31, 2004 744.0 7,702.0 248.5 1,474.8 67.0 69.9 212.6 155.1
Sep 30, 2004 720.0 7,445.2 248.2 1,482.2 61.9 64.5 211.2 152.8
Oct 31, 2004 744.0 7,686.8 248.0 1,489.9 59.2 61.7 209.7 150.5
Nov 30, 2004 720.0 7,415.6 247.2 1,497.3 53.8 56.1 208.3 148.4
Dec 31, 2004 744.0 7,655.4 246.9 1,505.0 47.7 49.7 206.9 146.1
Jan 31, 2005 744.0 7,635.0 246.3 1,512.6 40.8 42.6 205.5 143.8
Feb 28, 2005 672.0 6,858.8 245.0 1,519.5 33.6 35.0 204.2 141.8
Mar 31, 2005 744.0 7,500.5 242.0 1,527.0 33.3 34.7 202.8 140.5
Apr 30, 2005 720.0 7,203.6 240.1 1,534.2 33.3 34.7 201.5 138.7
May 31, 2005 744.0 7,395.0 238.5 1,541.6 33.3 34.7 200.2 136.8
Jun 30, 2005 720.0 7,051.9 235.1 1,548.6 33.3 34.7 198.9 135.6
Jul 31, 2005 744.0 7,188.4 231.9 1,555.8 33.3 34.7 197.6 134.4
Aug 31, 2005 744.0 7,088.0 228.6 1,562.9 33.3 34.7 196.3 133.2
Sep 30, 2005 720.0 6,766.0 225.5 1,569.7 33.3 34.7 195.1 132.0
Oct 31, 2005 744.0 6,956.1 224.4 1,576.6 33.3 34.7 193.8 130.1
Nov 30, 2005 720.0 6,644.5 221.5 1,583.3 33.3 34.7 192.7 128.9
Dec 31, 2005 744.0 6,783.7 218.8 1,590.0 33.3 34.7 191.4 127.7
167
ABERFELDY
21/01-26-049-28W3/0 - COLONY FORMATION
Wellbore Description
Roughness, in 7.00E-04
Depth, ft 1677
Deviation, deg 90
Flow Path Annulus
Tbg ID, in 1.190
Tbg OD, in 1.250
Csg ID, in 1.994
Calibration
q, mcf/d 369
P flow, psi 182
P tbg, psi 175.02
P csg, psi 174.78
Flowline, ft 0.772
Reservoir Conditions
Pool Number 4
OGIP mmcf 17700
Pi psi 485
C mcfd/psi*2 0.010836
n 1.00
T surf (degree) F 39
T res (degree) F 60
Gas Analysis
H2 C1 91.37
He 0.16 C2 0.90
N2 7.02 C3 0.04
CO2 0.50 iC4 0.01
H2S nC4
SG 0.591 C5
Tc 662 C6
Pc 337 C7+
Calculated Production Information
Production Rate Cum Tbg Csg Reservoir Flow
Date Hours mcf mcd/d mmcf psi psi psi psi
Dec 31, 2001 373.9 1,237.4
Jan 31, 2002 744.0 14,977.4 483.1 1,252.4 152.4 147.1 259.3 152.9
Feb 28, 2002 672.0 13,386.4 478.1 1,265.8 150.1 144.8 257.7 150.6
Mar 31, 2002 744.0 11,456.0 369.5 1,277.2 178.0 171.7 256.2 178.3
Apr 30, 2002 720.0 10,864.9 362.2 1,288.1 177.3 171.0 254.7 177.5
May 31, 2002 744.0 11,150.1 359.7 1,299.2 175.3 169.2 253.3 175.6
Jun 30, 2002 720.0 10,859.3 362.0 1,310.1 172.0 166.0 251.8 172.3
Jul 31, 2002 744.0 11,441.1 369.1 1,321.5 167.4 161.5 250.3 167.6
Aug 31, 2002 744.0 11,652.4 375.9 1,333.2 162.5 156.8 248.8 162.8
Sep 30, 2002 720.0 11,371.8 379.1 1,344.6 158.6 153.0 247.3 158.9
Oct 31, 2002 744.0 11,853.1 382.4 1,356.4 154.6 149.1 245.7 154.9
Nov 30, 2002 720.0 11,564.3 385.5 1,368.0 150.4 145.2 244.2 150.8
Dec 31, 2002 744.0 12,035.1 388.2 1,380.0 146.4 141.2 242.7 146.7
Jan 31, 2003 744.0 12,114.9 390.8 1,392.1 142.2 137.2 241.1 142.6
Feb 28, 2003 672.0 10,951.0 391.1 1,403.1 138.7 133.8 239.7 139.1
Mar 31, 2003 744.0 12,180.6 392.9 1,415.3 134.8 130.1 238.1 135.2
Apr 30, 2003 720.0 11,784.5 392.8 1,427.0 131.3 126.7 236.6 131.7
May 31, 2003 744.0 12,193.5 393.3 1,439.2 127.5 123.0 235.1 127.9
Jun 30, 2003 720.0 11,816.3 393.9 1,451.1 123.5 119.2 233.5 124.0
Jul 31, 2003 744.0 12,163.5 392.4 1,463.2 120.4 116.2 232.0 120.9
Aug 31, 2003 744.0 12,227.1 394.4 1,475.4 115.6 111.5 230.4 116.0
Sep 30, 2003 720.0 11,791.3 393.0 1,487.2 112.1 108.2 228.9 112.6
Oct 31, 2003 744.0 12,145.0 391.8 1,499.4 108.7 104.9 227.4 109.2
Nov 30, 2003 720.0 11,744.9 391.5 1,511.1 104.5 100.9 225.9 105.0
Dec 31, 2003 744.0 12,077.6 389.6 1,523.2 101.2 97.7 224.4 101.7
Jan 31, 2004 744.0 12,054.2 388.8 1,535.3 97.1 93.7 222.9 97.6
Feb 29, 2004 696.0 11,242.0 387.7 1,546.5 93.0 89.8 221.4 93.6
Mar 31, 2004 744.0 11,986.9 386.7 1,558.5 89.0 85.9 219.9 89.6
Apr 30, 2004 720.0 11,493.0 383.1 1,570.0 86.2 83.1 218.5 86.7
May 31, 2004 744.0 11,878.4 383.2 1,581.9 81.0 78.2 217.0 81.7
Jun 30, 2004 720.0 11,415.1 380.5 1,593.3 77.4 74.7 215.5 78.1
Jul 31, 2004 744.0 11,739.4 378.7 1,605.0 73.2 70.7 214.1 73.9
Aug 31, 2004 744.0 11,692.2 377.2 1,616.7 68.4 66.0 212.6 69.1
Sep 30, 2004 720.0 11,277.5 375.9 1,628.0 63.1 60.9 211.2 63.8
Oct 31, 2004 744.0 11,520.1 371.6 1,639.5 60.3 58.2 209.7 61.1
Nov 30, 2004 720.0 11,100.5 370.0 1,650.6 54.8 52.9 208.3 55.6
Dec 31, 2004 744.0 11,434.1 368.8 1,662.0 48.3 46.7 206.9 49.3
Jan 31, 2005 744.0 11,386.4 367.3 1,673.4 41.3 39.8 205.5 42.4
Feb 28, 2005 672.0 10,226.4 365.2 1,683.6 33.7 32.6 204.2 35.1
Mar 31, 2005 744.0 11,126.5 358.9 1,694.8 33.5 32.3 202.8 34.8
Apr 30, 2005 720.0 10,563.1 352.1 1,705.3 33.5 32.3 201.5 34.8
May 31, 2005 744.0 10,714.0 345.6 1,716.1 33.5 32.3 200.2 34.7
Jun 30, 2005 720.0 10,174.6 339.2 1,726.2 33.5 32.3 198.9 34.7
Jul 31, 2005 744.0 10,322.4 333.0 1,736.5 33.5 32.3 197.6 34.6
Aug 31, 2005 744.0 10,131.4 326.8 1,746.7 33.5 32.3 196.3 34.6
Sep 30, 2005 720.0 9,625.1 320.8 1,756.3 33.5 32.3 195.1 34.6
Oct 31, 2005 744.0 9,768.7 315.1 1,766.1 33.5 32.3 193.8 34.5
Nov 30, 2005 720.0 9,282.7 309.4 1,775.4 33.5 32.3 192.7 34.5
Dec 31, 2005 744.0 9,423.6 304.0 1,784.8 33.5 32.3 191.4 34.5
168
ABERFELDY
NON PRODUCING XXXXX - COLONY FORMATION
Wellbore Description
Roughness, in 7.00E-04
Depth, ft 1965
Deviation, deg 90
Flow Path Tubing
Tbg ID, in 1.210
Tbg OD, in 2.375
Csg ID, in 6.336
Calibration
q, mcf/d
P flow, psi
P tbg, psi
P csg, psi
Flowline, ft
Reservoir Conditions
Pool Number 4
OGIP mmcf 17700
Pi psi 485
C mcfd/psi*2
n 1.00
T surf (Degrees) F 39
T res (Degrees) F 60
Gas Analysis
H2 C1 91.37
He 0.16 C2 0.90
N2 7.02 C3 0.04
CO2 0.50 iC4 0.01
H2S nC4
SG 0.591 C5
Tc 662 C6
Pc 337 C7+
Calculated Production Information
Production Rate Cum Tbg Csg Reservoir Flow
Date Hours mcf mcd/d mmcf psi psi psi psi
Dec 31, 2001 1,612.9
Jan 31, 2002
Feb 28, 2002
Mar 31, 2002
Apr 30, 2002
May 31, 2002
Jun 30, 2002
Jul 31, 2002
Aug 31, 2002
Sep 30, 2002
Oct 31, 2002
Nov 30, 2002
Dec 31, 2002
Jan 31, 2003
Feb 28, 2003
Mar 31, 2003
Apr 30, 2003
May 31, 2003
Jun 30, 2003
Jul 31, 2003
Aug 31, 2003
Sep 30, 2003
Oct 31, 2003
Nov 30, 2003
Dec 31, 2003
Jan 31, 2004
Feb 29, 2004
Mar 31, 2004
Apr 30, 2004
May 31, 2004
Jun 30, 2004
Jul 31, 2004
Aug 31, 2004
Sep 30, 2004
Oct 31, 2004
Nov 30, 2004
Dec 31, 2004
Jan 31, 2005
Feb 28, 2005
Mar 31, 2005
Apr 30, 2005
May 31, 2005
Jun 30, 2005
Jul 31, 2005
Aug 31, 2005
Sep 30, 2005
Oct 31, 2005
Nov 30, 2005
Dec 31, 2005
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