As filed with the Securities and Exchange Commission on October 16, 2002
Registration No. 333-96537
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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
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AMENDMENT NO. 2
TO
FORM F-4
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933
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COMPTON PETROLEUM CORPORATION
(Exact name of registrant as specified in its charter)
PROVINCE OF ALBERTA, CANADA 1311 NOT APPLICABLE
(State or other jurisdiction (Primary Standard Industrial (I.R.S. Employer
of incorporation or Classification Code Number) Identification Number)
organization)
SUITE 3300, 425 - 1ST STREET S.W.
CALGARY, ALBERTA, CANADA
T2P 3L8
(403) 237-9400
(Address, including zip code, and telephone number, including area code, of
registrant's principal executive offices)
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HORNET ENERGY LTD.
(Exact name of registrant as specified in its charter)
867791 ALBERTA LTD.
(Exact name of registrant as specified in its charter)
899776 ALBERTA LTD.
(Exact name of registrant as specified in its charter)
COMPTON PETROLEUM
(Exact name of registrant as specified in its charter)
PROVINCE OF ALBERTA, CANADA 1311 NOT APPLICABLE
(State or other jurisdiction (Primary Standard Industrial (I.R.S. Employer
of incorporation or Classification Code Number) Identification Number)
organization)
SUITE 3300, 425 - 1ST STREET S.W.
CALGARY, ALBERTA, CANADA
T2P 3L8
(403) 237-9400
(Name, address, including zip code, and telephone number, including area
code, of registrant's principal executive offices)
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CT CORPORATION SYSTEM
111 EIGHTH AVENUE
NEW YORK, NY 10011
(212) 894-8940
(Name, address, including zip code, and telephone number, including area
code, of agent for service)
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WITH COPIES TO:
ANDREW J. FOLEY, ESQ. DAVID LEFEBVRE, ESQ.
PAUL, WEISS, RIFKIND, WHARTON & GARRISON FRASER, MILNER & CRASGRAIN, LLP
1285 AVENUE OF THE AMERICAS 30TH FLOOR, FIFTH AVENUE PLACE
NEW YORK, NEW YORK 10019-6064 237-4TH AVENUE S.W.
(212) 373-3000 CALGARY, ALBERTA T2P 4X7, CANADA
(403) 268-7000
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APPROXIMATE DATE OF COMMENCEMENT OF SALE TO THE PUBLIC: AS SOON AS
PRACTICABLE AFTER THIS REGISTRATION STATEMENT IS DECLARED EFFECTIVE.
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If this Form is filed to register additional securities for an offering
pursuant to Rule 462(b) under the Securities Act, check the following box and
list the Securities Act registration statement number of the earlier effective
registration statement for the same offering. [_]
If this Form is a post-effective amendment filed pursuant to Rule
462(d) under the Securities Act, check the following box and list the Securities
Act registration statement number of the earlier effective registration
statement for the same offering. [_]
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CALCULATION OF REGISTRATION FEE
===================================================================================================================================
TITLE OF EACH CLASS OF AMOUNT TO BE PROPOSED MAXIMUM OFFERING PROPOSED MAXIMUM AGGREGATE AMOUNT OF
SECURITIES TO BE REGISTERED REGISTERED PRICE PER UNIT(1)(2) OFFERING PRICE(1)(2) REGISTRATION FEE(3)
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9.90% notes due 2009............. $165,000,000 100% $ 165,000,000 $ 15,180
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Guarantees of Notes.............. ------------ ------------ ------------- ----------
===================================================================================================================================
(1) Determined solely for the purpose of calculating the registration fee in
accordance with Rule 457 promulgated under the Securities Act of 1933, as
amended.
(2) No separate consideration will be received for the subsidiary guarantees.
(3) Pursuant to Rule 457(n), no separate fee for the subsidiary guarantees is
payable.
----------------------------------
THE REGISTRANTS HEREBY AMEND THIS REGISTRATION STATEMENT ON SUCH DATE OR
DATES AS MAY BE NECESSARY TO DELAY ITS EFFECTIVE DATE UNTIL THE REGISTRANTS
SHALL FILE A FURTHER AMENDMENT WHICH SPECIFICALLY STATES THAT THIS
REGISTRATION STATEMENT SHALL THEREAFTER BECOME EFFECTIVE IN ACCORDANCE WITH
SECTION 8(A) OF THE SECURITIES ACT OF 1933 OR UNTIL THE REGISTRATION
STATEMENT SHALL BECOME EFFECTIVE ON SUCH DATE AS THE SECURITIES AND
EXCHANGE COMMISSION, ACTING PURSUANT TO SAID SECTION 8(A), MAY DETERMINE.
================================================================================
PART I
INFORMATION REQUIRED TO BE
DELIVERED TO OFFEREES OR PURCHASERS
The information in this prospectus is not complete and may be changed. We may
not sell these securities or accept any offer to sell these securities until we
deliver this prospectus to you in final form. We are not using this prospectus
to offer to sell these securities or to solicit offers to buy these securities
in any place where the offer or sale is not permitted.
PROSPECTUS
[GRAPHIC OMITTED]
COMPTON
------------------------------------
PETROLEUM CORPORATION
EXCHANGE OFFER OF
US$165,000,000 OF OUR
9.90% SENIOR NOTES
DUE 2009
- --------------------------------------------------------------------------------
TERMS OF THE EXCHANGE OFFER:
o It will expire at 5:00 p.m., New York City time, on
__________2002, unless we extend it.
o If all the conditions to this exchange offer are satisfied, we
will exchange all of our 9.90% Senior Notes due 2009 issued on
May 8, 2002, which we refer to as the initial notes, that are
validly tendered and not withdrawn for new notes, which we
refer to as the exchange notes.
o You may withdraw your tender of initial notes at any time
before the expiration of this exchange offer.
o The exchange notes that we will issue to you in exchange for
your initial notes will be substantially identical to your
initial notes except that, unlike your initial notes, the
exchange notes will have no transfer restrictions or
registration rights.
o The exchange notes that we will issue to you in exchange for
your initial notes are new securities with no established
market for trading.
BEFORE PARTICIPATING IN THIS EXCHANGE OFFER, PLEASE REFER TO THE
SECTION IN THIS PROSPECTUS ENTITLED "RISK FACTORS" COMMENCING ON PAGE 13.
Neither the Securities and Exchange Commission nor any state securities
commission has approved or disapproved of these securities or determined if this
prospectus is truthful or complete. Any representation to the contrary is a
criminal offense.
- --------------------------------------------------------------------------------
The date of this prospectus is ____________, 2002.
TABLE OF CONTENTS
PROSPECTUS SUMMARY.............................................................3
RISK FACTORS..................................................................12
ENFORCEABILITY OF CIVIL LIABILITIES AGAINST FOREIGN PERSONS...................19
CURRENCY TRANSLATION..........................................................20
FORWARD-LOOKING STATEMENTS....................................................20
USE OF PROCEEDS...............................................................21
CAPITALIZATION................................................................21
SELECTED HISTORICAL CONSOLIDATED FINANCIAL DATA...............................22
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS.............................................23
BUSINESS......................................................................34
MANAGEMENT....................................................................46
RELATED PARTY TRANSACTIONS....................................................49
SECURITY OWNERSHIP OF BENEFICIAL OWNERS AND MANAGEMENT........................50
DESCRIPTION OF OTHER INDEBTEDNESS.............................................51
THE EXCHANGE OFFER............................................................52
DESCRIPTION OF THE EXCHANGE NOTES.............................................59
DESCRIPTION OF THE INITIAL NOTES..............................................94
BOOK-ENTRY, DELIVERY AND FORM.................................................94
MATERIAL INCOME TAX CONSIDERATIONS............................................97
PLAN OF DISTRIBUTION.........................................................100
LEGAL MATTERS................................................................101
INDEPENDENT PETROLEUM ENGINEERS..............................................101
INDEPENDENT ACCOUNTANTS......................................................101
WHERE YOU CAN FIND MORE INFORMATION..........................................101
FINANCIAL STATEMENTS INDEX ..................................................F-1
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-2-
PROSPECTUS SUMMARY
THE FOLLOWING SUMMARY IS QUALIFIED IN ITS ENTIRETY BY AND SHOULD BE
READ IN CONJUNCTION WITH THE DETAILED INFORMATION AND FINANCIAL STATEMENTS
APPEARING ELSEWHERE IN THIS PROSPECTUS. YOU SHOULD READ THE ENTIRE PROSPECTUS
CLOSELY. THE TERMS "COMPTON", "WE", "OUR" AND "US", EXCEPT AS OTHERWISE
INDICATED IN THIS PROSPECTUS OR AS THE CONTEXT OTHERWISE INDICATES, REFER TO
COMPTON PETROLEUM CORPORATION AND OUR SUBSIDIARIES AS A COMBINED ENTITY.
THE TERM "INITIAL NOTES" REFERS TO THE 9.90% SENIOR NOTES DUE 2009 THAT
WERE ISSUED ON MAY 8, 2002 IN A PRIVATE OFFERING. THE TERM "EXCHANGE NOTES"
REFERS TO THE 9.90% SENIOR NOTES DUE 2009 OFFERED WITH THIS PROSPECTUS. EXCEPT
AS OTHERWISE PROVIDED HEREIN, THE TERM "NOTES" REFERS TO THE INITIAL NOTES AND
THE EXCHANGE NOTES, COLLECTIVELY.
UNLESS OTHERWISE INDICATED, ALL REFERENCES TO "$" IN THIS PROSPECTUS
REFER TO CANADIAN DOLLARS AND ALL REFERENCES TO "US$" REFER TO UNITED STATES
DOLLARS.
THE COMPANY
We are an independent public company actively engaged in the
exploration, development and production of natural gas, natural gas liquids and
crude oil in western Canada. We have established our current operational base
through a combination of a program of full-cycle exploration and strategic
acquisitions. This involves:
o establishing core geographic operating areas through strategic
acquisitions;
o developing significant operational and technical expertise
through exploration and development activities;
o acquiring strategic control over infrastructure; and
o reinvesting operating cash-flow to further consolidate our
position in each of our core areas and to further grow our
inventory of drilling prospects.
We began operations in 1993 with a small technical team and a large
seismic database. Through a series of acquisitions and continued drilling
success, we have established total proved reserves of 321 bcfe as of December
31, 2001. Approximately 82% of our total proved reserves are natural gas and
approximately 89% of our total proved reserves are proved developed. As of June
30, 2002, we held working interests in 826,591 (635,371 net) acres of
undeveloped land and we held working interests in 1,056 gross (437.2 net)
producing wells in western Canada.
We currently focus our operations in four geographic areas:
o SOUTHERN ALBERTA-- ESTABLISHED IN 1993: We have one of the
largest land positions in the area, with more than 452,488 net
acres (330,001 net undeveloped acres) of gas-prone lands.
Concentrated in and around our net acreage, there are
approximately 1,800,000 acres or 2,850 sections of land. We
own approximately 25% of these lands, which represents the
largest percentage of land ownership among oil and gas
companies operating within this area. These lands are
primarily gas-prone, with 64% of producing wells within the
area being natural gas wells. We operate substantially all of
our production and have long-term access to necessary
processing facilities in this area. We believe that our land
ownership position in this area will provide us with a
multi-year inventory of exploration and development prospects.
This area represented 69% of our proved reserves as of
December 31, 2001, 52% of our net undeveloped land as of June
30, 2002, 53% of our production for the year ended December
31, 2001 and 55% of our production for the six months ended
June 30, 2002.
o WEST CENTRAL ALBERTA -- ESTABLISHED IN 1998: This area has
significant natural gas and light oil production. We plan to
increase our long-life, high-quality, light oil production
through a variety of exploitation techniques and to pursue
multi-zone gas exploration targets. This area represented 17%
of our proved reserves as of December 31, 2001, 18% of our net
undeveloped land as of June 30, 2002, 26% of our production
for the year ended December 31, 2001 and 24% of our production
for the six months ended June 30, 2002.
-3-
o PEACE RIVER ARCH-- ESTABLISHED IN 1998: This north-central
Alberta core area offers us a range of opportunities,
including lower-risk exploitation, secondary recovery efforts
and pure natural gas exploration. Our light oil development
program, which consists of secondary recovery through water
flooding of the reservoir and infill drilling, provides us
with predictable ongoing production and an extension of the
area's reserve life. We plan to expand and consolidate our
operations in this core area by acquiring additional land and
increasing control of operatorship and infrastructure. This
area represented 13% of our proved reserves as of December 31,
2001, 10% of our net undeveloped land as of June 30, 2002, 18%
of our production for the year ended December 31, 2001 and 19%
of our production for the six months ended June 30, 2002.
o NORTHERN ALBERTA-- ESTABLISHED IN 1996: Within the
Rainbow/Zama area in northern Alberta, we have a large
undeveloped land base consisting of more than 96,000 net acres
that we believe provides us with multi-zone exploration
opportunities. This area is relatively under-explored due to
its remoteness. Industry interest, however, has heightened
with increased drilling and infrastructure activity on lands
adjacent to ours. Since 1996, drilling activity and
infrastructure construction has increased considerably in the
Rainbow/Zama area. In 1996, a total of 63 wells were drilled
by the oil and gas industry, as compared to approximately 225
wells in fiscal 2001. Moreover, a major natural gas pipeline
was installed in fiscal 2000 which transports gas through our
main block of lands. More recently, two other oil and gas
companies have installed natural gas gathering pipelines in
the area. This area represented 1% of our proved reserves as
of December 31, 2001, 15% of our net undeveloped land as of
June 30, 2002, 3% of our production for the year ended
December 31, 2001 and 2% of our production for the six months
ended June 30, 2002.
In addition to our four core areas discussed above, we have 5% of our
net undeveloped land in minor properties outside of our four geographic core
areas. These lands are located in northeastern British Columbia, northeastern
Saskatchewan and southern Manitoba. These minor properties were acquired
primarily as a result of acquisitions of corporations whose primary assets were
in one or more of our core areas. Currently, less than 1% of our production
comes from these minor properties.
BUSINESS STRATEGY
Our strategy is to grow our reserves and increase our production in our
four core geographic areas and other areas where we have technical expertise.
Our senior management team has significant technical and operational expertise
with an average of 20 years of experience in one or more of our core areas.
CONCENTRATE ON FOUR CORE GEOGRAPHIC AREAS. We currently operate in four
core geographic areas which provides us with a balanced portfolio of exploration
and development prospects.
FOCUS ON NATURAL GAS. We have gained considerable technical expertise
and achieved significant success in exploring for deeper and larger natural gas
reservoirs. In 2001, our average well depth was approximately 1,790 meters,
which is significantly deeper than the Alberta oil and gas industry average well
depth of approximately 1,000 meters. Notwithstanding our increased focus on
drilling for deeper gas reservoirs, we were able to achieve a drilling success
rate of 76% in 2001, as compared to our drilling success rate of 61% in 1998. We
plan to continue to focus on finding and developing long-life natural gas
reserves. Our proved reserves as of December 31, 2001 of 321 bcfe were
approximately 82% natural gas with an estimated reserve life of 8.2 years at
that date.
PURSUE FULL-CYCLE EXPLORATION COMPLEMENTED BY SELECTIVE ACQUISITIONS.
We plan to continue to reinvest internally generated cash flow to fund the
growth of our exploration prospects and development projects and to further
consolidate our undeveloped land base to maintain a growing inventory of
drilling prospects in our core geographic areas.
CONTROL OF INFRASTRUCTURE AND OPERATORSHIP. We believe that control
over gathering and processing infrastructure and operatorship of drilling
programs will continue to be critical to the success of our full-cycle
exploration program.
MAINTAIN A LARGE PORTFOLIO OF UNDEVELOPED LAND. We have assembled a
significant portfolio of undeveloped land (working interests in 826,591 (635,371
net) acres of undeveloped land, as of June 30, 2002) and complementary seismic
data in our core areas.
MAINTAIN FINANCIAL FLEXIBILITY. We are committed to maintaining
financial flexibility to allow us to pursue our full-cycle exploration program
in periods of low commodity prices.
-4-
RECENT DEVELOPMENTS
Our average daily production for the first six months of 2002 was
19,193 boe/d, an increase of 13% over the 17,009 boe/d for the comparable period
in 2001. Commodity prices realized during the period, however, were
significantly lower than the historically high prices realized during the first
six months of 2001. Both the West Texas Intermediate oil benchmark price and the
AECO natural gas price index decreased substantially from the first six months
of 2001, down 16% and 57%, respectively. "AECO" refers to the price of natural
gas located at a reference sales point storage facility in the province of
Alberta. This dramatic drop in commodity prices had an adverse impact on our
earnings and cash flow for the first six months of 2002.
REGULATORY REQUIREMENTS
Other than under the U.S. securities laws, we are not required to
obtain any regulatory approvals relating to the issuance of the exchange notes.
We will be required, however, to comply with all applicable U.S. federal
securities laws and any securities or blue sky laws of the various states.
-----------------------------------------------------
We were incorporated under the BUSINESS CORPORATIONS ACT (Alberta) in
1992 AS A CORPORATION WITH AN INDEFINITE LIFE and we commenced active business
operations in July 1993. Our principal executive offices are located at Suite
3300, 425 - 1st Street S.W., Calgary, Alberta, T2P 3L8. Our general telephone
number is (403) 237-9400 and our website is located at WWW.COMPTONPETROLEUM.COM.
The information on our website is not part of this prospectus. Our common shares
are listed and posted for trading on The Toronto Stock Exchange under the
trading symbol "CMT".
-5-
SUMMARY OF THE EXCHANGE OFFER
We are offering to exchange US$165,000,000 aggregate principal amount
of our exchange notes for a like aggregate principal amount of our initial
notes. In order to exchange your initial notes, you must properly tender them
and we must accept your tender. We will exchange all outstanding initial notes
that are validly tendered and not validly withdrawn.
Exchange Offer...................... We will exchange our exchange notes for
a like aggregate principal amount at
maturity of our initial notes.
Expiration Date..................... This exchange offer will expire at 5:00
p.m., New York City time, on ______,
2002, unless we decide to extend it.
Conditions to the Exchange Offer.... We will complete this exchange offer
only if:
o there is no change in the laws and
regulations which would impair our
ability to proceed with this
exchange offer;
o there is no change in the current
interpretation of the staff of the
Securities and Exchange Commission
(the "Commission") which permits
resales of the exchange notes;
o there is no stop order issued by
the Commission which would suspend
the effectiveness of the
registration statement which
includes this prospectus or the
qualification of the exchange
notes under the TRUST INDENTURE
ACT OF 1939;
o there is no litigation or
threatened litigation which would
impair our ability to proceed with
this exchange offer; and
o we obtain all the governmental
approvals we deem necessary to
complete this exchange offer.
Please refer to the section in
this prospectus entitled "The
Exchange Offer -- Conditions to
the Exchange Offer".
Please refer to the section in this
prospectus entitled "The Exchange Offer
-- Conditions to the Exchange Offer".
Procedures for Tendering Initial To participate in this exchange offer,
Notes....................... you must complete, sign and date the
letter of transmittal or its facsimile
and transmit it, together with your
initial notes to be exchanged and all
other documents required by the letter
of transmittal, to The Bank of Nova
Scotia Trust Company of New York, as
exchange agent, at its address
indicated under "The Exchange Offer--
Exchange Agent." In the alternative,
you can tender your initial notes by
book-entry delivery following the
procedures described in this
prospectus. If your initial notes are
registered in the name of a broker,
dealer, commercial bank, trust company
or other nominee, you should contact
that person promptly to tender your
initial notes in this exchange offer.
For more information on tendering your
notes, please refer to the section in
this prospectus entitled "The Exchange
Offer-- Procedures for Tendering
Initial Notes".
Special Procedures for Beneficial If you are a beneficial owner of
Owners...................... initial notes that are registered in
the name of a broker, dealer,
commercial bank, trust company or other
nominee and you wish to tender your
initial notes in the exchange offer,
you should contact the registered
holder promptly and instruct that
person to tender on your behalf.
Guaranteed Delivery Procedures .... If you wish to tender your initial
notes and you cannot get the required
documents to the exchange agent on
time, you may tender your notes by
using the guaranteed delivery
procedures described under the section
of this prospectus entitled "The
Exchange Offer-- Procedures for
Tendering Initial Notes-- Guaranteed
Delivery Procedure".
Withdrawal Rights................... You may withdraw the tender of your
initial notes at any time before 5:00
p.m., New York City time, on the
expiration date of the exchange offer.
To withdraw, you must send a written or
facsimile transmission notice of
withdrawal to the exchange agent at its
address indicated under "The Exchange
Offer-- Exchange Agent" before 5:00
-6-
p.m., New York City time, on the
expiration date of the exchange offer.
Acceptance of Initial Notes and If all the conditions to the completion
Delivery of Exchange Notes....... of this exchange offer are satisfied,
we will accept any and all initial
notes that are properly tendered in
this exchange offer on or before 5:00
p.m., New York City time, on the
expiration date. We will return any
initial note that we do not accept for
exchange to you without expense as
promptly as practicable after the
expiration date. We will deliver the
exchange notes to you as promptly as
practicable after the expiration date
and acceptance of your initial notes
for exchange. Please refer to the
section in this prospectus entitled
"The Exchange Offer -- Acceptance of
Initial Notes for Exchange; Delivery of
Exchange Notes".
Federal Income Tax Considerations Exchanging your initial notes for
Relating to the Exchange Offer... exchange notes will not be a taxable
event to you for United States federal
income tax purposes. Please refer to
the section of this prospectus entitled
"Material Income Tax Considerations--
U.S. Federal Income Tax
Considerations".
Exchange Agent...................... The Bank of Nova Scotia Trust Company
of New York is serving as exchange
agent in the exchange offer.
Fees and Expenses................... We will pay all expenses related to
this exchange offer. Please refer to
the section of this prospectus entitled
"The Exchange Offer-- Fees and
Expenses".
Use of Proceeds..................... We will not receive any proceeds from
the issuance of the exchange notes. We
are making this exchange offer solely
to satisfy certain of our obligations
under our registration rights agreement
entered into in connection with the
offering of the initial notes.
The net proceeds to us from the
offering of the initial notes were
approximately US$156.3 million, after
deducting the initial purchasers'
discount and offering expenses. We used
the proceeds from the offering to repay
our outstanding debt under our senior
credit facilities. The remaining net
proceeds, approximately US$5.7 million,
were used for general corporate
purposes.
Consequences to Holders Who Do If you do not participate in this
Not Participate in the Exchange exchange offer:
Offer............................
o you will not necessarily be able
to require us to register your
initial notes under the U.S.
SECURITIES ACT OF 1933 (the
"Securities Act");
o you will not be able to resell,
offer to resell or otherwise
transfer your initial notes unless
they are registered under the
Securities Act or unless you
resell, offer to resell or
otherwise transfer them under an
exemption from the registration
requirements of, or in a
transaction not subject to, the
Securities Act; and
o the trading market for your
initial notes will become more
limited to the extent other
holders of initial notes
participate in the exchange offer.
Please refer to the section of
this prospectus entitled "Risk
Factors -- Your failure to
participate in the exchange offer
will have adverse consequences."
Resales............................. It may be possible for you to resell
the notes issued in the exchange offer
without compliance with the
registration and prospectus delivery
provisions of the Securities Act,
subject to some conditions. Please
refer to the section of this prospectus
entitled "Risk Factors-- Risks Relating
to the Exchange Offer-- Some persons
who participate in the exchange offer
must deliver a prospectus in connection
with resales of the exchange notes" and
"Plan of Distribution".
-7-
THE EXCHANGE NOTES
THIS SUMMARY DESCRIBES THE PRINCIPAL TERMS OF THE EXCHANGE NOTES. SOME
OF THE TERMS AND CONDITIONS DESCRIBED BELOW ARE SUBJECT TO IMPORTANT LIMITATIONS
AND EXCEPTIONS. YOU SHOULD CAREFULLY READ THE "DESCRIPTION OF THE EXCHANGE
NOTES" SECTION OF THIS PROSPECTUS FOR A MORE DETAILED DESCRIPTION OF THE
OFFERING.
Company............................. Compton Petroleum Corporation.
Exchange Notes...................... US$165.0 million aggregate principal
amount of 9.90% Senior Notes due 2009.
The forms and terms of the exchange
notes are the same as the form and
terms of the initial notes except that
the issuance of the exchange notes is
registered under the Securities Act,
the exchange notes will not bear
legends restricting their transfer and
will not be entitled to registration
rights under our registration rights
agreement. The exchange notes will
evidence the same debt as the initial
notes, and both the initial notes and
the exchange notes will be governed by
the same indenture.
Maturity Date....................... May 15, 2009.
Interest............................ 9.90% per year. We will make interest
payments in U.S. dollars.
Interest Payment Dates.............. May 15 and November 15, beginning on
November 15, 2002.
Mandatory Redemption................ We will not be required to make
mandatory redemption or sinking fund
payments with respect to the notes.
Optional Redemption................. We may redeem the notes in whole or in
part at any time on or after May 15,
2006, at the redemption prices
described under "Description of the
Exchange Notes-- Optional Redemption".
Prior to May 15, 2005, we may redeem up
to 35% of the notes with the proceeds
of certain equity offerings, provided
at least 65% of the aggregate principal
amount of the notes under the indenture
remains outstanding after the
redemption and subject to limitations
contained in our senior credit
facilities.
Redemption for Changes in We will make payments on the notes free
Canadian Withholding Taxes....... of withholding or deduction for
Canadian taxes. If withholding or
deduction is required, we will be
required to pay additional amounts so
that the net amounts you receive will
equal the amount you would have
received if withholding or deduction
had not been imposed.
If, as a result of a change in law
occurring after the date of the
offering, we are required to pay such
additional amounts, we may redeem the
notes in whole but not in part, at any
time at 100% of their principal amount,
plus accrued and unpaid interest, if
any, to the redemption date.
Guarantees.......................... All payments with respect to the notes,
including principal and interest, will
be fully and unconditionally guaranteed
on an unsecured senior basis by all of
our current subsidiaries and future
restricted subsidiaries, enforceable
against all of these subsidiaries
collectively or against any of them
individually. Should a future
restricted subsidiary of ours guarantee
the notes, this guarantee will
constitute a new issuance of securities
under the Securities Act and will
require us to register such issuance
under the Securities Act or effect such
issuance under an exemption from
registration. Each of our guarantors
also guarantees our senior credit
facilities on a senior secured basis.
Change of Control................... Upon specified change of control
events, each holder of a note will have
the right to sell to us all or a
portion of its notes at a purchase
price in cash equal to 101% of the
principal amount, plus accrued and
unpaid interest, if any, to the date of
repurchase.
Ranking............................. The notes and the guarantees will be:
-8-
o unsecured;
o equal in right of payment to our
and our guarantor subsidiaries'
current and future unsecured
senior indebtedness;
o senior in right of payment to our
and our guarantor subsidiaries'
future debt that expressly
provides for subordination to the
notes or the guarantees; and
o effectively subordinated in right
of payment to any of our and our
guarantor subsidiaries' senior
credit facilities which are
secured by substantially all of
our and our guarantors' assets.
Covenants........................... The indenture governing the notes will
limit our ability and that of our
restricted subsidiaries to, among other
things:
o incur additional indebtedness and
issue preferred stock;
o create liens;
o make restricted payments;
o impose restrictions on the ability
of restricted subsidiaries to make
specified payments and
distributions;
o make material dispositions of
assets;
o engage in transactions with
affiliates;
o engage in specified business
activities; and
o engage in mergers, consolidations
and certain transfers of assets.
These covenants are subject to
important exceptions and
qualifications, as described under
"Description of the Exchange Notes".
Registration Rights Agreement....... Under a registration rights agreement,
we have agreed to file a registration
statement on an appropriate form with
respect to this offer to exchange the
initial notes for the exchange notes,
which will be registered under the
Securities Act. This prospectus is part
of that registration statement.
Use of Proceeds..................... We will not receive any proceeds from
the issuance of the exchange notes in
exchange for the outstanding initial
notes. We are making this exchange
solely to satisfy our obligations under
the registration rights agreement
entered into in connection with the
offering of the initial notes.
Absence of a Public Market for the The exchange notes are new securities
Exchange Notes................... with no established market for them. We
cannot assure you that a market for
these exchange notes will develop or
that this market will be liquid. Please
refer to the section of this prospectus
entitled "Risk Factors -- Risks
Relating to the Exchange Offer".
Form of the Exchange Notes.......... The exchange notes will be represented
by one or more permanent global
securities in registered form deposited
on behalf of The Depository Trust
Company with The Bank of Nova Scotia
Trust Company of New York, as
custodian. You will not receive
exchange notes in certificated form
unless one of the events described in
the section of this prospectus entitled
"Description of the Exchange Notes--
Book Entry; Delivery and Form--
Exchange of Book Entry Notes for
Certificated Notes" occurs. Instead,
beneficial interests in the exchange
notes will be shown on, and transfers
of these exchange notes will be
effected only through, records
maintained in book-entry form by The
Depository Trust Company with respect
to its participants.
-9-
SUMMARY RESERVE AND UNDEVELOPED LAND DATA
The following table summarizes our undeveloped land and our natural
gas, crude oil and natural gas liquids reserves as of the dates indicated and
the present value attributable to the reserves as of those dates, discounted at
10%. The reserve information as of December 31, 2001 was prepared by Outtrim
Szabo Associates Ltd. The reserve information as of December 31, 1999 and 2000
was prepared by or reviewed by Outtrim Szabo Associates Ltd.
HISTORICAL
------------------------------------------
AS OF DECEMBER 31,
------------------------------------------
1999 2000 2001
------------ ------------ ------------
PROVED RESERVES:
Natural gas (mmcf).................. 181,759 223,761 262,448
Crude oil & natural gas liquids (mbbls) 10,682 9,423 9,777
Natural gas equivalent (mmcfe).... 245,851 280,302 321,110
% natural gas..................... 74% 80% 82%
% proved developed................ 85% 85% 89%
Estimated reserve life (in years)(1) 8.9 7.9 8.2
Annual reserve replacement ratio(2). 268% 197% 204%
Recycle ratio(3).................... 1.2x 2.2x 1.5x
PV-10 (thousands of dollars)(4)..... $ 393,448 $ 1,227,443 $ 465,619
Standardized measure of discounted
future net cash flows (thousands of
dollars)............................ $ 271,486 $ 709,869 $ 317,461
UNDEVELOPED LAND
Gross undeveloped land (thousands of
acres)............................ 707 808 962
Working interest percentage......... 71% 76% 73%
- ------------------------
(1) Reserve life is calculated by dividing our proved reserves at year end
by our annual production in that year.
(2) The annual reserve replacement ratio is a percentage determined by
dividing our estimated proved reserves added during a year from
exploitation, development and exploration activities, acquisition of
proved reserves and revisions of previous estimates, excluding property
sales, by our annual production in that year.
(3) The recycle ratio is a multiple determined by dividing our netback per
boe by our finding and development costs per boe in that year. Netback
per boe is calculated by dividing our annual net revenues generated
from producing oil and natural gas volumes, net of operating costs and
administrative expenses by our annual production in that year. Finding
and development costs per boe is calculated by dividing our estimated
finding and development costs associated with our estimated proved
reserves added during the year by our estimated proved reserves added
in that year from exploitation, development and exploration activities,
acquisition of proved reserves and revisions of previous estimates,
excluding property sales.
(4) PV-10 is the present value of our estimated future net cash flows
before income taxes, discounted at 10% per year, calculated using
constant pricing. The prices used in 1999 were $2.88 per mcf of natural
gas, $36.64 per barrel of crude oil and $30.88 per barrel of natural
gas liquids. The prices used in 2000 were $9.69 per mcf of natural gas,
$39.33 per barrel of crude oil and $37.57 per barrel of natural gas
liquids. The prices used in 2001 were $3.68 per mcf of natural gas,
$32.63 per barrel of crude oil and $22.98 per barrel of natural gas
liquids. PV-10 is not necessarily indicative of actual future cash
flows.
-10-
SUMMARY OPERATING DATA
The following provides summary data with respect to our production and
sales of crude oil and natural gas for the periods indicated and the costs
related to such production.
SIX MONTHS ENDED
YEAR ENDED DECEMBER 31, JUNE 30,
------------------------------ ---------------------
1999 2000 2001 2001 2002
-------- ------- ------- -------- ----------
PRODUCTION:
Natural gas (mmcf)................... 19,834 25,039 28,405 13,315 15,469
Natural gas liquids (mbbls).......... 463 528 506 215 294
Crude oil (mbbls).................... 841 1,235 1,320 645 602
Natural gas equivalent (mmcfe).... 27,653 35,618 39,363 18,471 20,843
AVERAGE SALES PRICE PER UNIT:
Natural gas (per mcf)................ $ 2.62 $ 4.54 $ 4.77 $ 6.69 $ 3.26
Natural gas liquids (per bbl)........ 16.27 25.12 20.80 22.95 18.38
Crude oil (per bbl).................. 25.43 33.82 32.55 36.45 32.44
Natural gas equivalent (per mcfe). 2.93 4.74 4.80 6.36 3.62
COSTS:
Operating (per mcfe)................. $ 0.74 $ 0.89 $ 1.02 $ 1.00 $ 1.05
General and administrative (per mcfe) 0.15 0.17 0.16 0.20 0.21
DEFINITIONS AND OTHER MATTERS
As used in this prospectus, the following terms have the meaning
indicated:
o "AECO" means the price of natural gas located at a reference sales
point storage facility in the province of Alberta;
o "bbls" and "mbbls" mean barrels and thousand barrels, respectively;
o "boe" and "mboe" mean barrels of oil equivalent and thousand barrels of
oil equivalent, respectively;
o "bbls/d", "mcf/d", "mmcf/d" and "boe/d" mean barrels per day, thousand
cubic feet per day, million cubic feet per day and barrels of oil
equivalent per day, respectively;
o "developed land" means acreage on which we have a productive well;
o "farm-in" means an arrangement whereby one person or entity carries out
drilling operations on certain crude oil and natural gas properties
owned by another to earn an ownership interest in those properties;
o "GJ" means gigajoule;
o "GJ/d means gigajoules per day;
o "light oil" means crude oil with an American Petroleum Institute (API)
gravity score that is 26 or greater;
o "mcf", "mmcf" and "bcf" mean thousand cubic feet, million cubic feet
and billion cubic feet, respectively;
o "mcfe", "mmcfe" and "bcfe" means thousand cubic feet equivalent,
million cubic feet equivalent and billion cubic feet equivalent,
respectively;
o "production" means production attributable to our interest after
deducting royalties;
o "proved developed" means reserves that can be expected to be recovered
through existing wells with existing equipment and operating methods.
Additional crude oil and natural gas expected to be obtained through
the application of fluid injection, or other improved recovery
techniques for supplementing the
-11-
natural forces and mechanisms of primary recovery, are included as
"proved developed reserves" only after testing by a pilot project or
after the operation of an installed program has confirmed through
production response that increased recovery will be achieved;
o "proved reserves" are the estimated quantities of crude oil, natural
gas and natural gas liquids, which geological and engineering data
demonstrate with reasonable certainty to be recoverable in future years
from known reservoirs under existing economic and operating conditions,
i.e. prices and costs as of the date the estimate is made. Prices
include consideration of changes in existing prices provided only by
contractual arrangements, but not on escalations based upon future
conditions.
(i) reservoirs are considered proved if economic producibility is
supported by either actual production or conclusive formation
test. The area of a reservoir considered proved includes: (A)
that portion delineated by drilling and defined by gas-oil
and/or oil-water contacts, if any; and (B) the immediately
adjoining portions not yet drilled, but which can be
reasonably judged as economically productive on the basis of
available geological and engineering data. In the absence of
information on fluid contacts, the lowest known structural
occurrence of hydrocarbons controls the lower proved limit of
the reservoir;
(ii) reserves which can be produced economically through
application of improved recovery techniques (such as fluid
injection) are included in the "proved" classification when
successful testing by a pilot project, or the operation of an
installed program in the reservoir, provides support for the
engineering analysis on which the project or program was
based.
(iii) estimates of proved reserves do not include the following: (A)
oil that may become available from known reservoirs but is
classified separately as "indicated additional reserves"; (B)
crude oil, natural gas and natural gas liquids, the recovery
of which is subject to reasonable doubt because of uncertainty
as to geology, reservoir characteristics, or economic factors;
(C) crude oil, natural gas, and natural gas liquids, that may
occur in underlaid prospects; and (D) crude oil, natural gas,
and natural gas liquids, that may be recovered from oil
shales, coal, gilsonite and other such sources; and
o "undeveloped land" means acreage on which we do not have a productive
well and includes exploratory acreage.
Natural gas volumes are converted to barrels of oil equivalent using
the ratio of 6 thousand cubic feet of natural gas to one barrel of oil and are
stated at the official temperature and pressure bases of the area in which the
reserves are located. Proved reserve volumes have been determined after
deducting royalties.
PRESENTATION OF FINANCIAL INFORMATION
The historical financial statements contained in this prospectus are
reported in Canadian dollars and have been prepared in accordance with Canadian
generally accepted accounting principles. Note 17 to our historical consolidated
financial statements contained in this prospectus summarizes the differences
between generally accepted accounting principles in Canada and the United
States.
RISK FACTORS
YOU SHOULD CAREFULLY CONSIDER THE FOLLOWING MATTERS, AS WELL AS THE
OTHER INFORMATION CONTAINED IN THIS PROSPECTUS, BEFORE TENDERING YOUR INITIAL
NOTES IN THE EXCHANGE OFFER. INFORMATION CONTAINED IN THIS PROSPECTUS CONTAINS
"FORWARD-LOOKING STATEMENTS", WHICH ARE QUALIFIED BY THE INFORMATION CONTAINED
IN THE SECTION OF THIS PROSPECTUS ENTITLED "FORWARD-LOOKING STATEMENTS". IF ANY
OF THE RISKS DESCRIBED BELOW MATERIALIZE, OUR ABILITY TO SATISFY OUR OBLIGATIONS
TO THE HOLDERS OF THE EXCHANGE NOTES AND THE TRADING PRICE OF THE EXCHANGE NOTES
COULD BE ADVERSELY AFFECTED.
-12
RISKS RELATED TO OUR BUSINESS
OIL AND NATURAL GAS PRICES ARE VOLATILE AND LOW PRICES WILL ADVERSELY AFFECT OUR
BUSINESS.
Fluctuations in the prices of oil and natural gas will affect many
aspects of our business, including:
o our revenues, cash flows and earnings;
o our ability to attract capital to finance our operations;
o our cost of capital;
o the amount we are allowed to borrow under our senior credit
facilities; and
o the value of our oil and natural gas properties.
Both oil and natural gas prices are extremely volatile. Oil prices are
determined by international supply and demand. Political developments,
compliance or non-compliance with self-imposed quotas or agreements between
members of the Organization of Petroleum Exporting Countries can affect world
oil supply prices. Any material decline in prices could result in a reduction of
our production revenue and overall value. The economics of producing from some
wells could change as a result of lower prices. As a result, we could elect not
to produce from certain wells. Any material decline in prices could also result
in a reduction in our oil and natural gas acquisition and development
activities.
Natural gas and oil prices have declined substantially since fiscal
2000. The AECO spot price of natural gas was $3.00 per GJ on June 30, 2001 and
has decreased to $2.06 per GJ on June 30, 2002. Average natural gas prices
realized by us in fiscal 2000 were $4.54 per mcf and average natural gas prices
in fiscal 2001 were $4.77 per mcf. Any extended weakness in the price of natural
gas would have an adverse effect on our operating results and our borrowing
capacity because borrowings under our senior credit facility are limited by a
borrowing base amount that is established periodically by the lenders. This
borrowing base amount is the lenders' estimate of the present value of the
future net cash flow from our petroleum and natural gas properties.
In addition, under Canadian generally accepted accounting principles,
oil and natural gas properties are reviewed for impairment to determine whether
the carrying amount of an asset or group of assets may not be recoverable based
on expected future cash flows. If we conclude that the carrying amount would not
be recoverable, an impairment charge would be included in depreciation,
depletion and amortization in our consolidated statement of income, which would
adversely affect operating results and shareholders' equity (but as a non-cash
charge, it does not affect cash generated from operations). A continuation of
recent historically low oil prices or any substantial and extended decline in
the prices of oil or natural gas may require us to write down the carrying
amount of our oil and natural gas properties. See "Management's Discussion and
Analysis of Financial Condition and Results of Operations -- Liquidity and
Capital Resources".
YOU SHOULD NOT UNDULY RELY ON RESERVE INFORMATION BECAUSE RESERVE INFORMATION
REPRESENTS ESTIMATES AND OUR ACTUAL RESERVES COULD BE LOWER THAN THE ESTIMATES.
Estimates of oil and natural gas reserves involve a great deal of
uncertainty, because they depend in large part upon the reliability of available
geologic and engineering data, which is inherently imprecise. Geologic and
engineering data are used to determine the probability that a reservoir of oil
and natural gas exists at a particular location, and whether oil and natural gas
are recoverable from a reservoir. The probability of the existence and
recoverability of reserves is less than 100% and actual recoveries of proved
reserves usually differ from estimates.
Estimates of oil and natural gas reserves also require numerous
assumptions relating to operating conditions and economic factors, including,
among others:
o the price at which recovered oil and natural gas can be sold;
o the costs associated with recovering oil and natural gas;
-13-
o the prevailing environmental conditions associated with
drilling and production sites;
o the availability of enhanced recovery techniques;
o the ability to transport oil and natural gas to markets; and
o governmental and other regulatory factors, such as taxes and
environmental laws.
A change in one or more of these factors could result in known
quantities of oil and natural gas previously estimated as proved reserves
becoming unrecoverable. For example, a decline in the market price of oil or
natural gas to an amount that is less than the cost of recovery of such oil and
natural gas in a particular location could make production thereof commercially
impracticable. Each of these factors, by having an impact on the cost of
recovery and the rate of production, will also reduce the present value of
future net cash flows from estimated reserves.
In addition, estimates of reserves and future net cash flows expected
from them are prepared by different independent engineers, or by the same
engineers at different times, and may vary substantially.
Furthermore, in accordance with Canadian generally accepted accounting
principles, we could be required to write down the carrying value of our oil and
natural gas properties if oil and natural gas prices become depressed for even a
short period of time, or if there are substantial downward revisions to our
quantities of proved reserves. A write down would result in a charge to earnings
and a reduction of shareholders' equity.
IF WE ARE UNABLE TO REPLACE RESERVES THAT WE HAVE PRODUCED, OUR RESERVES,
REVENUES AND CASH FLOWS MAY DECLINE.
Our future success depends upon our ability to find, develop and
acquire additional oil and natural gas reserves that are economically
recoverable. Without successful exploration, exploitation or acquisition
activities, our reserves, revenues and cash flow may decline. We may not be able
to find and develop or acquire additional reserves at an acceptable cost.
IF WE ARE UNSUCCESSFUL IN ACQUIRING AND DEVELOPING OIL AND NATURAL GAS
PROPERTIES, WE WILL BE PREVENTED FROM INCREASING OUR RESERVES AND OUR BUSINESS
WILL BE ADVERSELY AFFECTED BECAUSE WE WILL EVENTUALLY DEPLETE OUR RESERVES.
The successful acquisition and development of oil and natural gas
properties requires an assessment of:
o recoverable reserves;
o future oil and natural gas prices and operating costs;
o potential environmental and other liabilities; and
o productivity of new wells drilled.
These assessments are inexact and, if made too inaccurately, we will
not recover the purchase price of a property from the sale of production from
the property or might not recognize an acceptable return from properties we
acquire. In addition, the costs of exploitation and development could materially
exceed initial estimates.
IF WE ARE UNABLE TO GENERATE SUFFICIENT CASH FLOW OR RAISE CAPITAL, WE WILL NOT
BE ABLE TO DEVELOP OUR RESERVES. IF WE ARE UNABLE TO DEVELOP OUR RESERVES,
REVENUES AND CASH FLOWS MAY DECLINE.
We will be required to make substantial capital expenditures to develop
our existing reserves, to discover new oil and natural gas reserves and to make
acquisitions. We will be unable to accomplish these tasks if we are unable to
generate sufficient cash flow or raise capital in the future. We also make
offers to acquire oil and natural gas properties in the ordinary course of our
business. If these offers are accepted, our capital needs may increase
substantially.
-14-
DRILLING ACTIVITIES ARE SUBJECT TO MANY RISKS AND ANY INTERRUPTION OR LACK OF
SUCCESS IN OUR DRILLING ACTIVITIES WILL ADVERSELY AFFECT OUR BUSINESS.
Drilling activities are subject to many risks, including the risk that
no commercially productive reservoirs will be encountered and that we will not
recover all or any portion of our investment. The cost of drilling, completing
and operating wells is often uncertain. Our drilling operations could be
curtailed, delayed or cancelled as a result of numerous factors, many of which
are beyond our control, including:
o adverse weather conditions;
o compliance with governmental requirements; and
o shortages or delays in the delivery of equipment and services.
OUR OPERATIONS ARE AFFECTED BY OPERATING HAZARDS AND UNINSURED RISKS AND A
SHUTDOWN OR SLOWDOWN OF OUR OPERATIONS WILL ADVERSELY AFFECT OUR BUSINESS.
There are many operating hazards in exploring for and producing oil and
natural gas, including:
o our drilling operations could encounter unexpected formations
or pressures that could cause damage to equipment or personal
injury;
o we could experience blowouts, accidents, oil spills,
fires or incur other damage to a well that could require us to
redrill it or take other corrective action;
o we could experience equipment failure that curtails or stops
production;
o our drilling and production operations, such as trucking of
oil, are often interrupted by bad weather; and
o we could be unable to access our properties or conduct our
operations due to surface conditions.
Any of these events could result in damage to, or destruction of, oil and
natural gas wells, production facilities or other property. In addition, any of
the above events could result in environmental damage or personal injury for
which we will be liable.
The occurrence of a significant event not fully insured or indemnified
against could seriously harm our financial condition and operating results.
OUR HEDGING ACTIVITIES COULD RESULT IN LOSSES.
The nature of our operations results in exposure to fluctuations in
commodity prices. We monitor and, when appropriate, enter into hedging
arrangements and physical delivery contracts (in which we agree to sell a fixed
amount of oil or natural gas at a set price at a specified date in the future)
in order to reduce our exposure to these risks. We are exposed to credit-related
losses in the event of non-performance by counter-parties to these financial
instruments. From time to time, we enter into hedging activities in an effort to
mitigate the potential impact of declines in oil and natural gas prices.
If product prices increase above those levels specified in our various
hedging agreements, we could lose the cost of floors or a ceiling or fixed price
could limit us from receiving the full benefit of commodity price increases. In
addition, by entering into these hedging activities, we may suffer financial
loss if:
o we are unable to produce oil or natural gas to fulfill our
obligations;
o we are required to pay a margin call on a hedge contract; or
-15-
o we are required to pay royalties based on a market or
reference price that is higher than our fixed or ceiling
price.
You should also refer to the section of this prospectus entitled
"Management's Discussion and Analysis of Financial Condition and Results of
Operations -- Hedging Policy".
COMPLYING WITH ENVIRONMENTAL AND OTHER GOVERNMENT REGULATIONS COULD BE COSTLY
AND COULD NEGATIVELY IMPACT OUR PRODUCTION.
Canadian laws and regulations at the provincial and federal level
govern the operation and maintenance of our facilities, the discharge of
materials into the environment and other environmental protection issues. Under
these laws and regulations, we could be liable for personal injury, clean-up
costs, remedial measures and other environmental and property damages, as well
as administrative, civil and criminal penalties. Although we do carry insurance
that covers environmental damages, we are not covered for the full potential
liability of environmental damages, so we could be liable or could be required
to cease production on properties if environmental damage occurs.
It is possible that the costs of complying with environmental laws and
regulations in the future will have a material adverse effect on our financial
condition or results of operations. Furthermore, future changes in environmental
laws and regulations, including adoption of stricter standards or more stringent
enforcement, could result in materially increased costs for us, such as larger
fines, incurring liability and increased capital expenditures and operating
costs, any of which could have a material adverse effect on our financial
condition or results of operations. You should refer to the section of this
prospectus entitled "Business -- Environmental".
FACTORS BEYOND OUR CONTROL AFFECT OUR ABILITY TO MARKET PRODUCTION. SINCE WE
CANNOT PROTECT OURSELVES FROM THESE FACTORS, THE IMPACT OF THEM, IF SERIOUS,
WILL ADVERSELY AFFECT OUR BUSINESS.
Our ability to market oil and natural gas from our wells depends upon
numerous factors beyond our control. These factors could:
o limit the availability of natural gas processing capacity
which would limit the amount of natural we produce;
o limit the availability of pipeline capacity which could limit
the amount of natural gas that we can market;
o limit the supply of and reduce demand for oil and natural gas
which could reduce our revenues;
o increase the availability of alternative fuel sources which
could reduce demand for oil and natural gas thereby reducing
our revenues;
In addition:
o the effects of inclement weather;
o Canadian federal and provincial regulation of oil and natural
gas marketing; and
o Canadian federal regulation of natural gas sold or
transported outside of the province of Alberta could adversely
effect our ability to economically produce and market oil or
natural gas at current levels of production.
OUR ACCESS TO FIXED COSTS PROCESSING AND TRANSPORTATION CAPACITY COULD BE
TERMINATED, RESULTING IN HIGHER COSTS.
The agreement governing the sale of the Mazeppa gas plants and related
facilities, which provides us with access to processing and transportation
capacity at set rates in our key southern Alberta core area, contains provisions
stating that our counter-party can terminate the agreement if the expenses of
operating the gas plants exceed the revenues of the gas plant for a period of 12
consecutive months. If the contract is terminated, our business would be
adversely affected, as we would be
-16-
forced to pay either higher rates for gas processing and transportation at the
Mazeppa gas plant or find new processing and transportation facilities.
ESSENTIAL EQUIPMENT MIGHT NOT BE AVAILABLE, WHICH COULD INTERFERE WITH THE
OPERATION OF OUR BUSINESS.
Oil and natural gas exploration and development activities depend upon
the availability of drilling and related equipment in the particular areas where
those activities will be conducted. Demand for that equipment or access
restrictions may affect the availability of that equipment to us and delay our
exploration and development activities.
WE ARE A MEDIUM-SIZED COMPANY OPERATING IN A HIGHLY COMPETITIVE INDUSTRY AND
LARGER COMPANIES WITH GREATER RESOURCES CAN OUTBID US FOR ACQUISITIONS.
The oil and natural gas industry is highly competitive. Our competitors
include companies that have greater financial and personnel resources than we
do. Our ability to acquire additional properties and to discover reserves in the
future depends upon our ability to evaluate and select suitable properties and
to complete transactions in a highly competitive and challenging environment.
You should refer to the section of this prospectus entitled "Business --
Competition".
RISKS RELATING TO THE EXCHANGE NOTES AND THE EXCHANGE OFFER
OUR SUBSTANTIAL INDEBTEDNESS COULD ADVERSELY AFFECT OUR FINANCIAL HEALTH AND
PREVENT US FROM FULFILLING OUR OBLIGATIONS UNDER THE EXCHANGE NOTES.
We have a significant amount of indebtedness. As of June 30, 2002, we
had total indebtedness of $251.0 million, which consists of the initial notes
and approximately $394,000 of indebtedness under capital lease obligations. In
addition, after giving pro forma effect to the offering of the initial notes and
the application of the net proceeds of that offering, our ratio of earnings to
fixed charges would have been 3.3x, for the year ended December 31, 2001.
Our substantial indebtedness could have important consequences to you.
For example, it could:
o make it more difficult for us to satisfy our obligations with
respect to the exchange notes;
o increase our vulnerability to general adverse economic and
industry conditions;
o require us to dedicate a substantial portion of our
cash flow from operations to payments on our indebtedness,
thereby reducing the availability of our cash flow to fund
working capital, capital expenditures, research and
development efforts and other general corporate purposes;
o limit our flexibility in planning for, or reacting to, changes
in our business and the industry in which we operate;
o place us at a competitive disadvantage compared to our
competitors that have less debt; and
o limit our ability to borrow additional funds.
In addition, the indenture and our senior credit facilities contain
financial and other restrictive covenants that will limit our ability to engage
in activities that may be in our long-term best interests. Our failure to comply
with those covenants could result in an event of default which, if not cured or
waived, could result in the acceleration of all of our debt.
DESPITE OUR CURRENT LEVEL OF INDEBTEDNESS, WE AND OUR SUBSIDIARIES MAY STILL BE
ABLE TO INCUR SUBSTANTIALLY MORE DEBT. THIS COULD FURTHER EXACERBATE THE RISKS
ASSOCIATED WITH OUR SUBSTANTIAL LEVERAGE.
We and our subsidiaries may be able to incur substantial additional
indebtedness in the future. The terms of the indenture do not fully prohibit us
or our subsidiaries from doing so. Our senior credit facilities currently permit
additional borrowing of up to $168.0 million. All of those borrowings would rank
senior to the exchange notes and our subsidiaries'
-17-
guarantees. If new debt is added to our and our subsidiaries' current level of
indebtedness, the related risks that we and they now face could intensify. See
"Description of Other Indebtedness".
TO SERVICE OUR INDEBTEDNESS, WE WILL REQUIRE A SIGNIFICANT AMOUNT OF CASH. OUR
ABILITY TO GENERATE CASH DEPENDS ON MANY FACTORS BEYOND OUR CONTROL.
Our ability to make payments on and to refinance our indebtedness,
including these notes, and to fund planned capital expenditures will depend on
our ability to generate cash in the future. This, to a certain extent, is
subject to general economic, financial, competitive, legislative, regulatory and
other factors that are beyond our control.
We cannot assure you that our business will generate sufficient cash
flow from operations or that future borrowings will be available to us under our
senior credit facilities in an amount sufficient to enable us to pay our
indebtedness, including these notes, or to fund our other liquidity needs. We
may need to refinance all or a portion of our indebtedness, including these
exchange notes on or before maturity. We cannot assure you that we will be able
to refinance any of our indebtedness, including our senior credit facilities and
these exchange notes, on commercially reasonable terms or at all.
THE EXCHANGE NOTES ARE EFFECTIVELY SUBORDINATED TO OUR SECURED INDEBTEDNESS AND
CERTAIN INDEBTEDNESS OF OUR SUBSIDIARIES.
The exchange notes will be unsecured and therefore are effectively
subordinated to any of our and our subsidiaries secured indebtedness to the
extent of the value of the assets securing such indebtedness. Up to $168.0
million is available for borrowing as additional senior debt under our senior
credit facilities. The indenture permits us to incur additional secured
indebtedness provided certain conditions are met. See "Description of the
Exchange Notes -- Certain Covenants -- Incurrence of Indebtedness and Issuance
of Preferred Stock". Consequently, in the event we are the subject of a
bankruptcy, liquidation, dissolution, reorganization or similar proceeding, the
holders of any secured indebtedness will be entitled to proceed against the
collateral that secures the secured indebtedness, and the collateral may not be
available to repay debts owed to our unsecured creditors, including holders of
the notes. As a result, holders of the notes may not be repaid the principal of
and interest on the notes that they are owed. The indenture also permits our
subsidiaries to incur indebtedness under our senior credit facilities which
would be secured by the assets of such subsidiaries. The exchange notes will be
effectively subordinated to such subsidiary indebtedness.
WE MAY NOT HAVE THE ABILITY TO RAISE THE FUNDS NECESSARY TO FINANCE THE CHANGE
OF CONTROL OFFER REQUIRED BY THE INDENTURE.
Upon the occurrence of specified change of control events, we will be
required to offer to repurchase all outstanding exchange notes at 101% of the
principal amount thereof plus accrued and unpaid interest and additional
interest, if any, to the date of repurchase. The change of control events
include a sale of all or substantially all of the our assets, the approval by
our directors or our shareholders of a plan relating to the dissolution of our
company, a transaction which places the ownership of a majority of our company
within one person, and a transaction which causes a majority of our directors to
cease being the directors of our company. However, it is possible that we will
not have sufficient funds at the time of the change of control to make the
required repurchase of exchange notes or that restrictions in our senior credit
facilities will not allow such repurchases. If we are unable to make the
required repurchases, we will be in default and the holders of notes will be
allowed to take certain actions against us, including in certain circumstances
accelerating our repayment of the principle of and any accrued but unpaid
interest on the notes. See "Description of the Exchange Notes -- Repurchase at
the Option of Holders".
FEDERAL AND STATE STATUTES ALLOW COURTS, UNDER SPECIFIC CIRCUMSTANCES, TO VOID
GUARANTEES AND REQUIRE NOTE HOLDERS TO RETURN PAYMENTS RECEIVED FROM GUARANTORS.
Under U.S. and Canadian federal bankruptcy laws and comparable
provisions of state and provincial fraudulent transfer laws, a guarantee could
be voided, or claims in respect of a guarantee could be subordinated to all
other debts of that guarantor if, among other things, the guarantor, at the time
it incurred the indebtedness evidenced by its guarantee:
o incurred the debt with the intent to hinder, delay or defraud
creditors;
o received less than reasonably equivalent value or fair
consideration for the incurrence of such guarantee; and
-18-
o was insolvent or rendered insolvent by reason of such
incurrence; or
o was engaged in a business or transaction for which the
guarantor's remaining assets constituted unreasonably small
capital; or
o intended to incur, or believed that it would incur,
debts beyond its ability to pay such debts as they mature.
In addition, any payment by that guarantor pursuant to its guarantee
could be voided and required to be returned to the guarantor or to a fund for
the benefit of the creditors of the guarantor.
YOU MIGHT HAVE DIFFICULTY ENFORCING CIVIL LIABILITIES AGAINST US IN THE UNITED
STATES.
We are a corporation organized under the laws of Alberta, Canada. All
of our directors and officers and some of the experts named in this prospectus
reside principally in Canada. Because these persons are located outside the
United States it may not be possible for you to effect service of process within
the United States upon those persons. Furthermore, it may not be possible for
you to enforce against us or them, in the United States, judgments obtained in
U.S. courts, because all or a substantial portion of our assets and the assets
of these persons are located outside the United States. We have been advised by
Fraser Milner Casgrain LLP, our Canadian counsel, that there is doubt as to the
enforceability, in original actions in Canadian courts, of liabilities based
upon the U.S. federal securities laws and as to the enforceability in Canadian
courts of judgments of U.S. courts obtained in actions based upon the civil
liability provisions of the U.S. federal securities laws. Therefore, it may not
be possible to enforce those actions against us, our directors and officers or
the experts named in this prospectus.
THE ISSUANCE OF THE EXCHANGE NOTES MAY ADVERSELY AFFECT THE MARKET FOR THE
INITIAL NOTES.
If initial notes are tendered for exchange and accepted in the exchange
offer, the trading market for the untendered and tendered but unaccepted initial
notes could be adversely affected. See "The Exchange Offer" and the "Risk
Factors -- Your failure to participate in the exchange offer will have adverse
consequences".
YOUR FAILURE TO PARTICIPATE IN THE EXCHANGE OFFER WILL HAVE ADVERSE
CONSEQUENCES.
The initial notes were not registered under the Securities Act or under
the securities laws of any state and you may not resell them, offer them for
resale or otherwise transfer them unless they are subsequently registered or
resold under an exemption from the registration requirements of the Securities
Act and applicable state securities laws. If you do not exchange your initial
notes for exchange notes pursuant to this exchange offer, or if you do not
properly tender your initial notes in this exchange offer, you will not be able
to resell, offer to resell or otherwise transfer the initial notes unless they
are registered under the Securities Act or unless you resell them, offer to
resell or otherwise transfer them under an exemption from the registration
requirements of, or in a transaction not subject to, the Securities Act. In
addition, you may no longer be able to obligate us to register the initial notes
under the Securities Act.
SOME PERSONS WHO PARTICIPATE IN THE EXCHANGE OFFER MUST DELIVER A PROSPECTUS IN
CONNECTION WITH RESALES OF THE EXCHANGE NOTES.
In some instances described in this prospectus under "Plan of
Distribution", you will remain obligated to comply with the registration and
prospectus delivery requirements of the Securities Act to transfer your exchange
notes. In these cases, if you transfer any exchange note without delivering a
prospectus meeting the requirements of the Securities Act or without an
exemption from registration of your exchange notes under the Securities Act, you
may incur liability under the Securities Act. We do not and will not assume, or
indemnify you against, this liability.
ENFORCEABILITY OF CIVIL LIABILITIES AGAINST FOREIGN PERSONS
We are a corporation organized under the laws of Alberta. All of our
directors and officers and some of the experts named in this prospectus reside
principally in Canada. Because these persons are located outside the United
States, it may
-19-
not be possible for you to effect service of process within the United States
upon those persons. Furthermore, it may not be possible for you to enforce
against us or them, in the United States, judgments obtained in U.S. courts,
because all or a substantial portion of our assets and the assets of these
persons are located outside the United States. We have been advised by Fraser
Milner Casgrain LLP, our Canadian counsel, that there is doubt as to the
enforceability, in original actions in Canadian courts, of liabilities based
upon the U.S. federal securities laws and as to the enforceability in Canadian
courts of judgments of U.S. courts obtained in actions based upon the civil
liability provisions of the U.S. federal securities laws. Therefore, it may not
be possible to enforce those actions against us, our directors and officers or
the experts named in this prospectus.
CURRENCY TRANSLATION
UNLESS OTHERWISE INDICATED, ALL REFERENCES TO "$" IN THIS PROSPECTUS
REFER TO CANADIAN DOLLARS AND ALL REFERENCES TO "US$" REFER TO UNITED STATES
DOLLARS.
The following table lists, for each period presented, the high and low
exchange rates, the average of the exchange rates on the last day of each month
during the period indicated and the exchange rates at the end of the period for
one Canadian dollar, expressed in United States dollars, based on the noon
buying rate in New York City for cable transfers in Canadian dollars as
certified for customs purposes by the Federal Reserve Bank of New York. On
October 16, 2002, the inverse of the noon buying rate in New York City for
cable transfers of Canadian dollars was Cdn$1.00 = US$0.6313.
YEAR ENDED DECEMBER 31,
---------------------------------------------------------------
1997 1998 1999 2000 2001
---------- --------- ---------- ---------- ----------
High for the period...... 0.7487 0.7105 0.6925 0.6969 0.6697
Low for the period....... 0.6945 0.6341 0.6535 0.6410 0.6244
End of period............ 0.6999 0.6504 0.6925 0.6669 0.6279
Average for the period... 0.7198 0.6714 0.6740 0.6725 0.6444
FORWARD-LOOKING STATEMENTS
This prospectus contains forward-looking statements within the meaning
of the U.S. federal securities laws. These statements are subject to certain
risks and uncertainties and may be based on assumptions that could cause actual
results to differ materially from those included in the forward-looking
statements. The words "believe", "expect", "intend", "estimate", "anticipate"
and similar expressions, as well as future or conditional verbs such as "will",
"should", "would" and "could" often identify forward-looking statements.
With respect to forward-looking statements contained in this
prospectus, we have made assumptions regarding, among other things:
o future crude oil and natural gas prices;
o the cost of expanding our property holdings;
o our ability to obtain equipment in a timely manner to meet our
demand;
o our ability to market crude oil and natural gas successfully
to current and new customers;
o the impact of increasing competition; and
o our ability to obtain financing on acceptable terms.
The information contained in this prospectus, including the information
provided under the heading "Risk Factors", identifies factors that could affect
our operating results and performance. We urge you to carefully consider those
factors.
-20-
Our forward-looking statements are expressly qualified in their
entirety by this cautionary statement. Our forward-looking statements are only
made as of the date of this prospectus and we undertake no obligation to
publicly update these forward-looking statements to reflect new information,
subsequent events or otherwise unless such new information causes such
statements to become materially different or misleading.
USE OF PROCEEDS
We will not receive any cash proceeds from the issuance of the exchange
notes in exchange for the outstanding initial notes. We are making this exchange
solely to satisfy our obligations under the registration rights agreement
entered into in connection with the offering of the initial notes. In
consideration for issuing the exchange notes, we will receive initial notes in
the same aggregate principal amount.
The net proceeds to us from the offering of the initial notes were
US$156.3 million ($245.5 million based upon the noon buying rate on May 8, 2002
of US$1.00 = $1.5708), after deducting the initial purchaser's discount and
offering expenses. We used the proceeds from the offering to repay off our
outstanding debt under our senior credit facilities, which was $236.5 million at
the close of the offering of initial notes. The remaining net proceeds of
approximately US$5.7 million were used for general corporate purposes.
Our senior credit facilities bear interest at our lender's prime rate
or at the banker's acceptance rate or the London Interbank Offered Rate
(referred to as LIBOR) plus a margin based on our ratio of total consolidated
debt to cash flow that was set at the close of the offering of initial notes at
0.125%, 1.125% and 1.125%, respectively. The senior credit facilities mature on
July 9, 2003.
CAPITALIZATION
The following table sets forth our actual capitalization as of June 30,
2002.
You should read this table together with "Management's Discussion and
Analysis of Financial Condition and Results of Operations", "Selected Historical
Consolidated Financial Data" and the financial information beginning on page
F-1.
The initial notes have been converted to Canadian dollars at the noon
buying rate on June 28, 2002, which was US$1.00 = $1.5187.
AS OF JUNE
30, 2002
---------------
(DOLLARS IN
THOUSANDS)
Cash and cash equivalents............ $ 640
===============
Long-term debt:
Senior credit facilities(1)...... $ -
Capital lease obligations 394
Notes offered.................... 250,586
---------------
Total long-term debt.......... 250,980
Shareholders' equity................. 233,170
---------------
Total capitalization $ 484,150
===============
- -----------
(1) Prior to the offering of the initial notes, our senior credit
facilities provided for total borrowings of up to $240.0 million. Upon
the completion of the offering of initial notes, we repaid
substantially all amounts outstanding under our senior credit
facilities, the size of the facilities was reduced and approximately
$168.0 million is currently available for borrowings under such
facilities, subject to the conditions contained therein. You should
refer to the section of this prospectus entitled "Description of Other
Indebtedness -- Senior Credit Facilities".
-21-
SELECTED HISTORICAL CONSOLIDATED FINANCIAL DATA
The following table provides our selected financial data for the five
years ended December 31, 2001 and for the six-month periods ended June 30, 2001
and 2002. The financial data for each of the years in the five-year period ended
December 31, 2001 have been derived from our audited consolidated financial
statements for those periods, which were audited by Grant Thornton LLP,
independent accountants. The financial data for the six-month periods ended June
30, 2001 and 2002 have been derived from our unaudited consolidated financial
statements for those periods. The unaudited financial statements have been
prepared on the same basis as our audited financial statements. We believe that
the information presented in our unaudited financial statements contain all
adjustments necessary for a fair presentation of the financial information
presented (consisting only of normal recurring adjustments). The historical data
for the interim period is not necessarily indicative of the results that may be
expected for our full year of operations. You should read our audited financial
statements and the related notes included elsewhere in this prospectus.
In some respects, Canadian generally accepted accounting principles
differ from United States generally accepted accounting principles. For a
discussion of the principal differences between Canadian and United States
generally accepted accounting principles, you should read Note 17 to our
consolidated financial statements included in this prospectus.
YEAR ENDED DECEMBER 31, SIX MONTHS ENDED
JUNE 30,
------------------------------------------------------------- ---------------------
1997 1998 1999 2000 2001 2001 2002
--------- --------- --------- ---------- --------- --------- --------
(Dollars in thousands, except ratios) (unaudited)
CANADIAN GAAP
STATEMENT OF EARNINGS:
Revenue:
Oil and natural gas revenues $ 17,674 $ 30,545 $ 97,016 $ 213,376 $ 244,970 $ 153,612 $ 96,566
Royalties, net of Alberta
Royalty Tax Credits...... (2,453) (2,790) (16,105) (44,695) (55,919) (36,072) (21,142)
---------- ---------- ---------- ---------- --------- --------- ----------
Net revenue.............. 15,221 27,755 80,911 168,681 189,051 117,540 75,424
---------- ---------- ---------- ---------- --------- --------- ----------
Expenses:
Operating.................. 3,787 7,476 20,521 31,571 40,222 18,508 21,855
General and administrative. 903 1,517 4,222 5,915 6,302 3,692 4,316
Interest................... 270 1,023 6,939 12,772 12,863 6,284 6,560
Unrealized foreign exchange
gain -- -- -- -- -- -- (8,465)
Depletion and depreciation. 3,896 6,671 20,160 41,767 50,450 23,789 26,427
---------- ---------- ---------- ---------- --------- --------- ----------
Total expenses........... 8,856 16,687 51,842 92,025 109,837 52,273 50,693
---------- ---------- ---------- ---------- --------- --------- ----------
Earnings before income taxes 6,365 11,068 29,069 76,656 79,214 65,267 24,731
Income taxes............... 2,639 4,464 11,981 36,597 23,578 17,772 10,233
---------- ---------- ---------- ---------- --------- --------- ----------
Net earnings............... $ 3,726 $ 6,604 $ 17,088 $ 40,059 $ 55,636 $ 47,495 $ 14,498
========== ========== ========== ========== ========= ========= =========
CASH FLOW DATA:
Cash provided (used) by:
Operating activities........... $ 8,426 $ 12,378 $ 37,829 $ 104,187 $ 121,068 $ 92,449 $ 51,102
Investing activities........... (90,818) (77,682) (111,033) (119,069) (176,066) (78,237) (69,654)
Financing activities........... 80,546 65,304 58,144 29,942 60,050 (12,870) 14,140
OTHER FINANCIAL DATA:
EBITDA(1)...................... $ 10,530 $ 18,762 $ 56,168 $ 131,195 $ 142,527 $ 95,340 $ 57,718
Ratio of EBITDA to interest expense 39.0x 18.3x 8.1x 10.3x 11.1x 15.2x 8.8x
Ratio of earnings to fixed
charges(2)................. 24.6x 11.8x 5.2x 7.0x 7.2x 11.4x 4.8x
BALANCE SHEET DATA:
Total assets................... $ 122,176 $ 212,083 $ 349,367 $ 524,272 $ 693,973 $ 569,815 $ 717,496
Long-term debt................. 41,769 93,616 159,714 183,376 230,000 182,000 250,586
Shareholders' equity........... 67,026 81,267 116,702 157,796 217,860 197,169 233,170
U.S. GAAP
Total Assets................... $ 124,188 $ 268,262 $ 416,271 $ 522,913 $ 692,591 $ 568,211 $ 717,710
Net earnings................... 3,668 2,033 7,345 32,881 46,921 47,495 14,498
EBITDA(1)...................... 10,519 18,688 54,702 126,711 142,527 95,340 57,718
Ratio of EBITDA to interest expense 39.0x 18.3x 7.9x 9.9x 11.1x 15.2x 8.8x
Ratio of earnings to fixed
charges(2)................. 24.2x 11.1x 3.9x 6.7x 7.2x 11.4x 4.8x
- ----------
(1) EBITDA is calculated as earnings before extraordinary items, excluding
interest expense and other debt expenses, income tax, depletion,
depreciation and amortization. EBITDA is not a measure of cash flow as
determined by Canadian or United States generally accepted accounting
principles. Certain items excluded from EBITDA are significant
components in understanding and assessing a company's financial
performance, such as a
-22-
company's cost of capital and tax structure, as well as historic costs
of depreciable assets, none of which are components of EBITDA. We have
included information concerning EBITDA because EBITDA is a measure used
by certain investors in determining a company's historical ability to
service its indebtedness. However, although we use EBITDA to monitor
our ability to service our indebtedness, viewing EBITDA as the sole
indicator of our ability to service indebtedness should be done with
caution, as we might be required to conserve funds or to allocate funds
to business or legal purposes other than servicing our indebtedness.
EBITDA should not be considered as an alternative to, or more
meaningful than, net income or cash flow as determined in accordance
with Canadian or United States generally accepted accounting principles
or as an indicator of our operating performance or liquidity. EBITDA is
not necessarily comparable to a similarly titled measure of another
company.
(2) For purposes of computing the ratio of earnings to fixed charges,
earnings consist of earnings before income taxes and fixed charges.
Fixed charges consist of interest and amortization of debt issuance
costs.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
YOU SHOULD READ THE FOLLOWING DISCUSSION AND ANALYSIS ALONG WITH OUR
AUDITED AND UNAUDITED FINANCIAL STATEMENTS AND THE RELATED NOTES APPEARING
ELSEWHERE IN THIS PROSPECTUS. THIS DISCUSSION AND ANALYSIS CONTAINS
FORWARD-LOOKING STATEMENTS THAT INVOLVE RISKS AND UNCERTAINTIES.
APPLICATION OF CRITICAL ACCOUNTING POLICIES
Our consolidated financial statements have been prepared in accordance
with the accounting principles generally accepted in Canada which, in most
respects, conform to accounting principles generally accepted in the United
States of America. The significant difference in these principles, as they apply
to our statement of earnings, balance sheets and statements of cash flow are
detailed in Note 17 of our consolidated financial statements attached hereto.
The application of generally accepted accounting principles involves
certain assumptions, judgements and estimates that affect reported amounts of
assets, liabilities, revenues and expenses. The basis for these estimates is
historical experience and various other assumptions that we believe to be
reasonable. These estimates are the basis for making judgements about the
carrying value of assets and liabilities. Actual results could differ from these
estimates under different assumptions or conditions. Thus, the application of
these principles can produce varying results from company to company.
We follow the full cost method of accounting for our petroleum and
natural gas operations. Under this accounting method, all costs related to the
exploration for and development of petroleum and natural gas reserves are
capitalized. Capitalized costs, as well as the estimated future expenditures to
develop proved reserves, are depleted using the unit-of-production method based
on estimated proved oil and gas reserves.
In applying the full cost method, we calculate a ceiling test whereby
the carrying value of petroleum and natural gas properties and production
equipment, net of recorded future income taxes and the accumulated provision for
site restoration and abandonment costs, is compared annually to an estimate of
future net cash flow from the production of proved reserves. Net cash flow is
estimated using year end prices, less estimated future general and
administrative expenses, financing costs and income taxes. Should this
comparison indicate an excess carrying value, the excess is charged against
earnings as additional depletion and depreciation.
For further details on our accounting policies and discussion of new
accounting pronouncements, see Notes 2, 3 and 17 of the Notes to our
Consolidated Financial Statements beginning on page F-6.
OVERVIEW
We are an independent public company actively engaged in the
exploration, development and production of natural gas, natural gas liquids and
crude oil in Western Canada. Our activities are concentrated in four core
geographic areas in Alberta. We have obtained our reserves through a combination
of strategic acquisitions and exploration and development activities. We
commenced operations in July 1993. Since 1997, we have acquired three oil and
natural gas companies: J.M. Huber Canada Limited in December 1998 for $91.4
million, Coparex Canada Ltd. in December 1999 for $74.6 million and Hornet
Energy Ltd. in July 2001 for $42.0 million.
-23-
We have established our current operating base through a combination of
a program of full-cycle exploration and strategic acquisitions. This involves:
o establishing core geographic operating areas through strategic
acquisitions;
o developing significant operational and technical expertise
through exploration and development activities;
o acquiring strategic control over infrastructure; and
o reinvesting operating cash-flow to further
consolidate our position in each of our core areas and to
further grow our inventory of drilling prospects.
As of June 30, 2002, we held working interests in 826,591 (635,371 net)
acres of undeveloped land and we held working interests in 1,056 gross (437.2
net) producing wells in western Canada.
Historically, the majority of our proved reserves and production has
been natural gas, with crude oil and natural gas liquids comprising a smaller
portion of our total production. A summary of our production and net revenue is
provided in the table below.
SIX MONTHS ENDED
YEAR ENDED DECEMBER 31, JUNE 30,
------------------------------------ -----------------------
1999 2000 2001 2001 2002
---------- ---------- ---------- ---------- ----------
PRODUCTION:
Natural gas (mmcf/d)........................... 54.3 68.4 77.8 73.6 85.5
Natural gas liquids (bbls/d)................... 1,268 1,443 1,386 1,186 1,622
Crude oil (bbls/d)............................. 2,303 3,374 3,617 3,562 3,327
NET REVENUE:
Natural gas (thousands of dollars)............. $ 52,008 $ 113,649 $ 135,547 $ 89,110 $ 50,490
Crude oil and natural gas liquids(thousands of
dollars)....................................... 28,903 55,032 53,504 28,430 24,934
---------- --------- --------- --------- --------
$ 80,911 $ 168,681 $ 189,051 $ 117,540 $ 75,424
========== ========= ========= ========= ========
A summary of our proved reserves as at certain dates is provided in the
table below:
YEAR ENDED DECEMBER 31,
------------------------------------
1999 2000 2001
--------- --------- ---------
PROVED RESERVES:
Natural gas (mmcf)...................... 181,759 223,761 262,448
Crude oil and natural gas
liquids (mbbls)...................... 10,682 9,423 9,777
Natural gas equivalent (mmcfe).......... 245,851 280,302 321,110
Over the past three fiscal years, our financial performance and the
period to period comparability of our performance has been affected by:
o production growth of 42% from 1999 to 2001;
o the acquisitions of J.M. Huber, Coparex and Hornet;
o borrowing to fund our growth; and
o crude oil, natural gas liquids and natural gas sales price
volatility.
Of these factors, the volatility of commodity prices, particularly
natural gas prices, has had the most significant impact on our financial
performance. The following tables sets forth the average prices realized by us,
net of royalties, both before and after hedging, on sales of natural gas, crude
oil and natural gas liquids for the periods indicated:
-24-
SIX MONTHS ENDED
PRICES BEFORE HEDGING: YEAR ENDED DECEMBER 31, JUNE 30,
- ---------------------------------------- ------------------------------------ -----------------------
1999 2000 2001 2001 2002
------ ------ ------- ------- --------
Natural gas ($/mcf).................... 2.62 4.54 4.64 6.61 3.25
Natural gas liquids ($/bbl)............ 26.69 40.02 32.55 36.45 32.37
Crude oil ($/bbl)...................... 16.27 25.12 20.80 22.95 18.38
SIX MONTHS ENDED
PRICES AFTER HEDGING: YEAR ENDED DECEMBER 31, JUNE 30,
- ---------------------------------------- ------------------------------------ -----------------------
1999 2000 2001 2001 2002
------ ------ ------- ------- --------
Natural gas ($/mcf).................... 2.62 4.54 4.77 6.69 3.26
Natural gas liquids ($/bbl)............ 16.27 25.12 20.80 22.95 18.38
Crude oil ($/bbl)...................... 25.43 33.82 32.55 36.45 32.44
From time-to-time, we enter into hedge transactions to manage
fluctuations in commodity prices. Currently, we have fixed the price on
approximately 22% of our current 2002 production. Additionally, our financial
policy is such that when necessary, commodity hedging contracts are utilized to
support the economics of both corporate and property acquisitions. Oil and gas
revenues for 2001 included gains of $3.7 million (2000 - loss of $7.7 million)
on such transactions.
Finding and development costs are the costs of adding proved reserves
and include the costs of undeveloped land, seismic, drilling, completion, tie-in
and construction of field facilities as well as costs of acquiring proved
reserves. Our average finding and development costs on a proved reserve basis
were $10.60 per boe in fiscal 1999, $10.17 per boe in fiscal 2000 and $14.25 per
boe in fiscal 2001. Finding and development costs increased in fiscal 2001 due
to the acquisition of Hornet combined with increased expenditures relating to
land and seismic. The purchase price of the Hornet acquisition was approximately
$29.1 million in cash plus the assumption of $10.9 million in debt, a working
capital deficiency of $1.5 million and transaction costs of $0.5 million. We
funded the cash portion of the Hornet acquisition out of working capital.
Finding and development costs increased in fiscal 1999 primarily as a result of
the acquisition of Coparex. Additionally, finding and development costs in
fiscal 1999 were impacted by our joint venture arrangements in our southern
Alberta area, where we earned a 50% interest in 3,200 to 3,840 acres of joint
venture lands by incurring 100% of costs to the casing point. The increase in
fiscal 2000 was partially attributable to higher field costs which was a result
of the increased level of industry activity, but was mainly due to our capital
program in fiscal 2000, which was skewed proportionately higher to upfront
capital intensive activities, such as land, seismic and facilities spending. Our
three-year average finding and development costs to December 31, 2001 were
$11.75 per boe. Our five-year average finding and development costs to December
31, 2001 were $9.25 per boe.
Our netback, which is our gross revenue less royalties, operating costs
and general and administrative expenses, is expressed as the netback per boe.
SIX MONTHS ENDED
YEAR ENDED DECEMBER 31, JUNE 30,
------------------------------------- ----------------------
1999 2000 2001 2001 2002
-------- ---------- ---------- ---------- ----------
Revenue.................................... $ 21.05 $ 35.95 $ 37.34 $ 49.90 $ 27.80
Royalties, net ARTC........................ (3.49) (7.53) (8.52) (11.72) (6.09)
-------- ---------- ---------- ---------- ----------
Net revenue............................ 17.56 28.42 28.82 38.18 21.71
Operating costs............................ (4.45) (5.32) (6.13) (6.01) (6.29)
General and administrative expenses........ (0.92) (1.00) (0.96) (1.20) (1.24)
-------- ---------- ---------- ---------- ----------
Netback................................ $ 12.19 $ 22.10 $ 21.73 $ 30.97 $ 14.18
======== ========== ========== ========== ==========
SIX MONTHS ENDED JUNE 30, 2002 COMPARED TO SIX MONTHS ENDED JUNE 30, 2001.
PRODUCTION. For the first six months of fiscal 2002, our natural gas
production averaged 85.5 mmcf/d, an increase of 16% from the same period in
fiscal 2001. For the first six months of fiscal 2002, our natural gas liquids
production increased by 37% to 1,622 bbls/d from 1,186 bbls/d for the same
period in fiscal 2001. For the first six months of 2002, our crude oil
production averaged 3,327 bbls/d, a 7% decrease from 3,562 bbls/d for the same
period in fiscal 2001. On a barrel of oil equivalent basis, production for the
first six months of fiscal 2002 averaged 19,193 boe/d, a 13% increase as
compared with 17,009 boe/d for the same period in fiscal 2001. Natural gas
represented 74% of our production mix during the first six months of fiscal
2002.
Our average natural gas price of $3.26 per mcf for the first six months
of fiscal 2002 represented a 51% decrease over the same period in fiscal 2001.
Our average crude oil price of $32.44 per barrel in the first six months of
fiscal 2002
-25-
represented a 11% decrease over the same period in fiscal 2001. Our average
natural gas liquids price was $18.38 per barrel for the first six months of
fiscal 2002 represented a 20% decrease over the same period in fiscal 2001. The
AECO spot price averaged $3.68 per GJ for the first six months of fiscal 2002
compared to $8.52 per GJ for the same period in fiscal 2001.
REVENUE. For the first six months of fiscal 2002, our gross revenue
decreased by 37% to $96.6 million, as compared to $153.6 million during the
first six months of fiscal 2001. This decrease was attributable to substantially
lower commodity prices in fiscal 2002. The West Texas Intermediate oil benchmark
price and the AECO natural gas price index both decreased substantially from the
first six months of fiscal 2001, down 16% and 57%, respectively, which was
offset marginally by higher production volumes. The 10% increase in gross
production volumes contributed approximately $8.6 million to the change in gross
revenue. The 43% decrease in average commodity prices affected approximately
$65.6 million of the decrease in gross revenue.
ROYALTIES. As a result of lower commodity prices in the first six
months of fiscal 2002, our royalty commitments, after royalty credits, decreased
to $21.1 million from $36.1 million during the same period in fiscal 2001. Our
average royalty rate on production was 21.9% for the first six months of fiscal
2002, as compared to 23.5% for the first six months of fiscal 2001.
OPERATING COSTS. Our operating costs increased to $21.9 million in the
first six months of fiscal 2002 from $18.5 million in the same period in fiscal
2001. This increase was primarily due to higher production levels. For the first
six months of fiscal 2002, operating costs were $6.29 per boe, a 5% increase
over the operating costs of $6.01 per boe for the same period in fiscal 2001.
GENERAL AND ADMINISTRATIVE EXPENSES. Our general and administrative
expenses increased to $4.3 million for the first six months of fiscal 2002, from
$3.7 million for the same period in fiscal 2001. On a barrel of oil equivalent
basis, general and administrative expenses were $1.24 for the first six months
of fiscal 2002, an increase of 3% from $1.20 during the same period in fiscal
2001.
INTEREST EXPENSE. For the first six months of 2002, our interest
expense increased to $6.6 million from $6.3 million during the same period in
fiscal 2001. This marginal increase reflects higher debt servicing costs
associated with our initial notes.
DEPLETION AND DEPRECIATION. Our depletion and depreciation expenses,
which include a provision for the future costs of abandonment and restoration,
were $26.4 million for the first six months of fiscal 2002, an 11% increase over
the $23.8 million in the same period in fiscal 2001. On a barrel of oil
equivalent basis, depletion and depreciation costs were $7.61 per boe for the
first six months of fiscal 2002, as compared to $7.73 per boe for the same
period in fiscal 2001.
INCOME TAXES. Our tax expense of $0.9 million for the first six months
of 2002 consisted of a Large Corporation Tax, as compared to $0.5 million Large
Corporation Tax expense for the same period in 2001. Future income taxes for the
first six months of 2002 were $9.3 million, a decrease of 46% for the same
period in 2001.
NET EARNINGS. For all of the reasons specified above, net earnings for
the first six months of fiscal 2002 decreased by 69% to $14.5 million from $47.5
million realized in the same period last year.
YEAR ENDED DECEMBER 31, 2001 COMPARED TO YEAR ENDED DECEMBER 31, 2000.
PRODUCTION. For fiscal 2001, our natural gas production averaged 77.8
mmcf/d, an increase of 14% from fiscal 2000. For fiscal 2001, our natural gas
liquids production decreased by 4% to 1,386 bbls/d from 1,443 bbls/d for fiscal
2000. For fiscal 2001, our crude oil production averaged 3,617 bbls/d, a 7%
increase from 3,374 bbls/d for fiscal 2000. On a barrel of oil equivalent basis,
production for fiscal 2001 averaged 17,974 boe/d, an 11% increase as compared
with 16,219 boe/d for fiscal 2000. Natural gas represented 72% of our production
mix during fiscal 2001.
Our average natural gas price of $4.77 per mcf for fiscal 2001
represented a 5% increase over fiscal 2000. Our average crude oil price of
$32.55 per barrel in fiscal 2001 represented a 4% decrease over fiscal 2000. Our
average natural gas liquids price was $20.80 per barrel for fiscal 2001
represented an 17% decrease over fiscal 2000. The AECO spot price averaged $5.97
per GJ for fiscal 2001 compared to $5.55 per GJ for fiscal 2000.
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REVENUE. For fiscal 2001, our gross revenue increased by 15% to $245.0
million, as compared to $213.4 million during fiscal 2000. This increase was
attributable to higher production volumes, stronger commodity prices and the
acquisition of Hornet Energy Ltd. The 14% increase in gross production volumes
contributed approximately $29.6 million of the incremental gross revenue. The 4%
increase in average commodity prices contributed approximately $2.0 million of
the increase in gross revenue.
ROYALTIES. As a result of strong commodity prices and higher production
volumes in fiscal 2001, our royalty commitments, after royalty credits,
increased to $55.9 million from $44.7 million during fiscal 2000. Our average
royalty rate on production was 22.8% for fiscal 2001, as compared to 20.9% for
fiscal 2000.
OPERATING COSTS. Our operating costs increased to $40.2 million in
fiscal 2001 from $31.6 million in fiscal 2000. This increase was attributable to
higher production levels, a significant increase in our energy costs and
increases in the costs of goods and services associated with high levels of
upstream activity in our industry. For fiscal 2001, operating costs were $6.13
per boe, a 15% increase over the operating costs of $5.32 per boe for fiscal
2000.
GENERAL AND ADMINISTRATIVE EXPENSES. Our general and administrative
expenses increased to $6.3 million for fiscal 2001, from $5.9 million for fiscal
2000. The increase was attributable to the higher level of staffing necessitated
by our increased level of activity. These expenses represented 2.6% of gross
revenues. On a barrel of oil equivalent basis, general and administrative costs
were $0.96 for 2001, a decrease of 4% from $1.00 during fiscal 2000.
INTEREST EXPENSE. For fiscal 2001, our interest expense was $12.9
million, which is consistent with the $12.8 million during fiscal 2000. A lower
average cost of borrowing in 2001 was offset by higher bank debt balances for
the year.
DEPLETION AND DEPRECIATION. Our depletion and depreciation expenses,
which include a provision for the future costs of abandonment and restoration,
were $50.5 million for fiscal 2001, an increase of 21% from $41.8 million in
fiscal 2000. This increase resulted from higher production levels and increased
finding and development costs for new reserves additions. On a barrel of oil
equivalent basis, depletion and depreciation costs were $7.69 per boe for fiscal
2001, as compared to $7.04 per boe for fiscal 2000.
INCOME TAXES. Our tax expense of $1.3 million for 2001 consisted of a
Large Corporation Tax and was 44% higher than the $0.9 million for fiscal 2000.
Future income taxes for fiscal 2001 were $22.2 million, an decrease of 38% from
fiscal 2000.
Effective April 1, 2001, the Alberta government decreased the
provincial income tax rate from 15.5% to 13.5%. This decrease had the immediate
effect of reducing our previously recorded future income tax liability,
resulting in a recovery of future income taxes which has been recognized in the
second quarter of fiscal 2001.
NET EARNINGS. For all of the reasons specified above, net earnings for
fiscal 2001 increased by 39% to $55.6 million from $40.1 million realized in
fiscal 2000.
YEAR ENDED DECEMBER 31, 2000 COMPARED TO YEAR ENDED DECEMBER 31, 1999
PRODUCTION. For fiscal 2000, our natural gas production averaged 68.4
mmcf/d, an increase of 26% from fiscal 1999. For fiscal 2000, our natural gas
liquids production increased by 14% to 1,443 bbls/d from 1,268 bbls/d during
fiscal 1999. For fiscal 2000, our crude oil production averaged 3,374 bbls/d, a
47% increase from 2,303 bbls/d for fiscal 1999. On a barrel of oil equivalent
basis, production for fiscal 2000 averaged 16,219 boe/d, a 28% increase as
compared with 12,627 boe/d for fiscal 1999. Natural gas represented 70% of our
production mix during fiscal 2000.
Our average natural gas price of $4.54 per mcf for fiscal 2000
represented a 73% increase over the same period in fiscal 1999. Our average
crude oil price of $33.82 per barrel in fiscal 2000 represented a 33% increase
over the same period in fiscal 1999. Our average natural gas liquids price of
$25.12 per barrel for fiscal 2000 represented a 54% increase over the same
period in fiscal 1999. The AECO spot price averaged $5.55 per GJ during fiscal
2000 compared to $2.93 per GJ in fiscal 1999.
-27-
REVENUE. Our gross revenue totalled $213.4 million in fiscal 2000, an
increase of 120% from $97.0 million in fiscal 1999. This increase was
attributable to a combination of higher production of natural gas, crude oil and
natural gas liquids, which accounted for 30% of the increase, and much stronger
realized commodity prices, which accounted for the remaining 70% of the
increase.
ROYALTIES. Our royalty commitments, after royalty credits, increased in
fiscal 2000 to a total of $44.7 million, up 178% from $16.1 million in fiscal
1999. This increase was attributable to a combination of higher production
volumes and the effect of the sliding scale royalty structure in Alberta, which
imposes higher royalty rates at higher product prices. Our average royalty rate
on our combined production was 20.9% in fiscal 2000, compared to 16.6% in fiscal
1999.
OPERATING COSTS. Our operating costs increased to $31.6 million in
fiscal 2000 from $20.5 million in fiscal 1999, largely as a result of increases
in our production attributable to higher initial costs associated with new
production and to general increases in costs of goods and services associated
with the industry's high level of field activity. On a barrel of crude oil
equivalent basis, operating costs increased to $5.32 per boe in fiscal 2000, an
increase of 20% from the $4.45 per boe in fiscal 1999.
GENERAL AND ADMINISTRATIVE EXPENSES. Our general and administrative
expenses increased 40% to $5.9 million in fiscal 2000 from $4.2 million in
fiscal 1999. This increase was attributable to higher levels of staffing
required by our increased level of activity. On a barrel of oil equivalent
basis, general and administrative costs were $1.00 in fiscal 2000, an increase
of 9% from $0.92 in fiscal 1999. In fiscal 2000 these expenses represented 2.8%
of gross revenues.
INTEREST EXPENSE. During fiscal 2000, we incurred an interest rate of
approximately 7.0% on our average outstanding bank debt, resulting in a total
interest expense of $12.8 million, up from $6.9 million in fiscal 1999. The
increase was attributable to both a higher average interest rate and a higher
average outstanding bank debt.
DEPLETION AND DEPRECIATION. Our depletion and depreciation expenses
increased to $41.8 million in fiscal 2000 from $20.2 million in fiscal 1999. On
a barrel of oil equivalent basis, depletion and depreciation amounted to $7.04
per boe in fiscal 2000, compared to $4.37 per boe in fiscal 1999. The change in
accounting policy to account for future income taxes payable discussed below
resulted in an increase in the carrying value of our assets of $68.1 million,
and in turn generated an incremental increase in the annual depletion and
depreciation rate of approximately $1.40 per boe. The remaining increase
resulted from higher production levels and increased finding and development
costs for new reserve additions.
INCOME TAXES. Our tax expense of $0.9 million for fiscal 2000 consisted
of a Large Corporation Tax and was 347% higher than the $0.2 million for fiscal
1999. Future income taxes for fiscal 2000 were $35.7 million, an increase of
203% for the same period in 1999.
Effective January 1, 2000, we adopted the new recommendations of the
Canadian Institute of Chartered Accountants with respect to accounting for
future income taxes. Under the new recommendations the liability method of tax
allocation is used, which is based upon the difference between financial and tax
bases of assets and liabilities. Previously, the deferral method was used, which
is based upon differences between the timing of reporting income and expenses
for financial and income tax purposes.
We have adopted this change in accounting policy retroactively, without
restating our financial statements of prior periods. As a result, we recorded a
reduction in retained earnings of $0.4 million, an increase in property and
equipment of $68.1 million and an increase in the future income tax liability of
$68.5 million, as at January 1, 2000. The adjustments were mainly the result of
future tax costs relating to acquisitions where the tax base acquired was less
than the purchase price, and of the tax consequence of the issuance of
flow-through share issues.
NET EARNINGS. For all of the reasons specified above, net earnings
increased by 134% from $17.1 million in fiscal 1999 to $40.1 million in fiscal
2000.
LIQUIDITY AND CAPITAL RESOURCES
CASH FLOWS. Our cash flow from operating activities (which refers to
cash flow from operations after considering changes in non-cash operating
working capital), for the first six months of fiscal 2002 decreased by 45% to
$51.1 million,
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compared to $92.4 million for the first six months of fiscal 2001, primarily as
a result of lower commodity prices. Adjustments to our $14.5 million net
earnings for the first six months of 2002, to reconcile it to net cash flow from
operating activities, include $26.4 million in depletion and depreciation, $9.3
million in future income taxes, $0.3 million in amortization of deferred
financing charges, $8.5 million in unrealized foreign exchange gain and $9.1
million in changes in non-cash operating working capital.
Our cash flow from operating activities for fiscal 2001 increased by
16% to $121.1 million, compared to $104.2 million for fiscal 2000. Adjustments
to our $55.6 million net earnings for fiscal 2001, to reconcile it to net cash
flow from operating activities, include $50.5 million in depletion and
depreciation, $22.2 million in future income taxes and $7.3 million in changes
in non-cash operating working capital.
We generated cash flow from operating activities of $104.2 million in
fiscal 2000, an increase of 176% from $37.8 million in fiscal 1999. Adjustments
to our $40.1 million net earnings for fiscal 2000 to reconcile it to net cash
flow from operating activities included $41.8 million in depletion and
depreciation, $35.7 million in future income taxes and $13.3 million in changes
in non-cash operating working capital.
In fiscal 1999, we generated cash flow from operating activities of
$37.8 million, an increase of 205% from $12.4 million in fiscal 1998.
Adjustments to our $17.1 million of net earnings for fiscal 1999, to reconcile
it to net cash flow from operating activities, included $20.2 million in
depletion and depreciation, $11.8 million in future income taxes and $5.2
million in changes in non-cash operating working capital.
We continually reinvest internally generated cash flow from operating
activities into capital expenditures in order to fund the growth of our
exploration and development projects and to further consolidate our undeveloped
land base. On a monthly basis, our cash management policy is designed to balance
exploration and development capital expenditures with our cash flow from
operating activities. However, due to the timing of the occurrence of our
capital expenditures, there are occasions when we may disclose a positive ending
cash balance for a respective reporting period, with such cash being reinvested
into capital expenditures in subsequent reporting periods.
Our net cash used in investing activities for the first six months of
fiscal 2002 was $69.7 million, a decrease of $8.5 million from the first six
months of fiscal 2001. Our principal uses of cash for the first six months of
2002 included $41.4 million in oil and natural gas property expenditures. Our
net cash used in investing activities for fiscal 2001 was $176.1 million, an
increase of $57.0 million from fiscal 2000. Our principal uses of cash for
fiscal 2001 included $148.0 million in oil and natural gas property expenditures
and $29.7 million in cash acquisition expenses for our Hornet acquisition. Our
net cash used in investing activities during fiscal 2000 was $119.1 million, a
decrease of $16.9 million from fiscal 1999. Our principal uses of cash during
fiscal 2000 included $118.2 million in oil and natural gas property expenditures
and $0.3 million in cash acquisition expenses for our new property acquisitions.
Our net cash used in investing activities during fiscal 1999 was $111.0 million,
an increase of $33.3 million in fiscal 1998. Our principal uses of cash during
fiscal 1999 included $71.2 million in oil and natural gas property expenditures
and $49.8 million in cash acquisition expenses for our acquisition of Coparex.
In mid-2001, we renegotiated our senior credit facilities with a
syndicate of Canadian financial institutions resulting in an increase to $240
million in our credit facilities from $192 million at the beginning of the year.
Upon completion of the offering, we repaid all amounts outstanding under our
senior credit facilities, the size of our senior credit facilities was reduced
and approximately $168.0 million is currently available for borrowing under
these facilities.
Borrowings under our senior credit facilities are limited by a
borrowing base amount that was initially established by and is periodically
redetermined by the lenders. This borrowing base amount is the lenders' estimate
of the present value of the future net cash flow from certain of our petroleum
and natural gas properties. Our current borrowing base comprises our senior
credit facilities, which currently consist of a $158.0 million revolving credit
facility and a $10.0 million working capital facility, aggregating to $168.0
million. At June 30, 2002, we had no outstanding borrowings under our working
capital facility. Our senior credit facilities bear interest at our lenders'
prime rate or at the bankers' acceptance rate or LIBOR plus a margin based on
our ratio of total consolidated debt to cash flow that is currently set at
0.625%, 1.625% and 1.625%, respectively. On June 30, 2002, the actual interest
rate on our senior credit facilities was 4.875%. These facilities are secured by
a charge against all of our assets.
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In March 2002, we obtained regulatory approval from The Toronto Stock
Exchange to renew our share buy-back program to buy back up to approximately 5.4
million of our outstanding common shares. The buy back program was renewed for a
12-month period, which commenced on March 8, 2002 and ends on March 7, 2003
(unless terminated earlier by us). The Toronto Stock Exchange rules allow us to
buy back up to the greater of (i) 5% of our issued and outstanding common
shares, excluding any shares held by or on behalf of us on the date of
acceptance of the notice of our issuer bid to The Toronto Stock Exchange or (ii)
10% of the public float of such shares. The public float means the number of
issued and outstanding common shares, less the number of shares controlled by
our senior officers, directors, principal shareholders and the number of common
shares that are pooled, escrowed or non-transferable. Our management
continuously monitors the price of our common shares and decides when it is
appropriate for us to buy back such shares. For the year ended December 31,
2001, we had repurchased 4,206,000 common shares under this buy back program for
$17.8 million. We have funded our repurchases of common shares from cash
generated from operations and drawings under our senior credit facilities.
Net capital expenditures for the first six months of fiscal 2002
totalled $41.5 million, a decrease of 47% from the total $78.3 million for the
first six months of fiscal 2001. A general decrease in activities, including
drilling, seismic and corporate and property acquisitions, accounted for the
lower expenditures. Net capital expenditures for fiscal 2001 totalled $190.4
million, an increase of 60% from the total of $118.8 million for the fiscal
2000. During fiscal 2001, our drilling program continued to focus on deeper
targets, which resulted in a higher average drilling cost per well. During the
year, our drilling program was successful in adding a total of 12.2 million boe
of proved reserves. We continue to invest significantly in undeveloped land and
seismic, which accounted for 14% of our total capital expenditures during this
period, in order to enhance our exploration and development prospects.
Capital expenditures in fiscal 2000 totalled $118.8 million, as
compared to $106.2 million in fiscal 1999. Our capital expenditures in fiscal
2000 were consistent with our strategy for long-term growth, as we made
significant investments in undeveloped land, seismic, production facilities and
exploration drilling necessary for continued value creation. In comparison to
fiscal 1999, capital expenditures incurred on property, undeveloped land and
seismic increased by 81%, expenditures on production equipment and facilities
increased by 131% and our capital investments in exploration, exploitation and
development projects across our operating areas increased by 47%. Exploratory
drilling and completion expenses totalled approximately $45.7 million in fiscal
2000, 68% of the total $66.7 million expended on exploration, exploitation and
development. During that year, our drilling program succeeded in adding 11.5
million boe of proved reserves. Our capital expenditures totalled $69.9 million
in fiscal 1998. The table below sets out our capital expenditures by category
over the past three years, the first three months of fiscal 2001 and the first
three months of fiscal 2002.
YEAR ENDED DECEMBER 31, SIX MONTHS ENDED
JUNE 30,
--------------------------------------------- --------------------------
1999 2000 2001 2001 2002
------------ ---------- ------------- ---------- ----------
(THOUSANDS OF DOLLARS) (unaudited)
Property, lease and seismic expenditures... $ 12,859 $ 23,241 $ 31,450 $ 28,463 $ 8,384
Exploration, development and exploitation.. 45,359 66,695 84,658 36,009 23,102
Production equipment and facilities........ 12,090 27,901 34,447 13,752 9,906
Other...................................... 1,415 684 10,243 69 99
----------- ---------- ----------- ----------- -----------
Total exploration and development
expenditures............................ 71,723 118,521 160,798 78,293 41,491
Acquisitions............................... 49,833 241 29,669 -- --
Dispositions............................... (15,351) -- -- -- --
----------- ---------- ----------- ----------- -----------
Net capital expenditures............... $ 106,205 $ 118,762 $ 190,467 $ 78,293 $ 41,491
=========== ========== =========== =========== ===========
In the past we have partially grown through acquisitions and we
regularly evaluate opportunities to acquire properties or companies. If we
decide in the future to make a significant acquisition for cash, we might be
required to raise capital via debt and/or equity financings in order to complete
the acquisition.
The purchase price of the Hornet acquisition was approximately $29.1
million in cash plus the assumption of $10.9 million in debt, a working capital
deficiency of $1.5 million and transaction costs of $0.5 million. We funded the
cash portion of the Hornet acquisition out of working capital.
We believe that funds generated from our operations, together with
borrowings under our senior credit facilities, will be sufficient to finance our
current operations and planned capital expenditures for the next three years. We
anticipate that our annual capital expenditures over the next few years will
increase somewhat from our expenditures in fiscal 2001.
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Management determines its capital expenditure program based on the annual
budget, including budgeted cash flow from operations, and closely monitors
changes throughout the year. Our 2002 capital expenditure program is focused in
our core areas and is based on a conservative pricing scenario, in that our
budgeted commodity price assumptions for both oil and natural gas are
substantially lower than actual prices realized during the prior year, 23% and
30%, respectively. In fiscal 2001, the West Texas Intermediate oil benchmark
price ("WTI") averaged US$25.91 per barrel and the NYMEX natural gas price
averaged US$4.05 per mcf. Our original 2002 budget outlined a plan to drill a
minimum of 70 to 75 wells and to incur capital expenditures of $100 million,
based upon average commodity price assumptions of WTI at US$20.00 per barrel of
oil and US$2.85 NYMEX per mcf of natural gas. Given the recent increase in
commodity prices (currently the WTI oil price is approximately US$29.00 per
barrel and the NYMEX natural gas price is approximately US$3.80 per mcf), we
anticipate generating higher cash flow from operations in 2002 than originally
budgeted. As a result, we are planning to increase our capital expenditures
program this year and incur approximately $115 million in capital expenditures,
consistent with this anticipated increase in cash flow from operations.
Currently, we intend to allocate approximately 35% of our capital expenditures
in fiscal 2002 to exploration activities and approximately 65% to development
activities. Currently, we expect to spend 60% of our capital expenditures in our
southern Alberta core area. The timing of most of our capital expenditures is
discretionary, and we have no material long-term capital expenditure
commitments.
It is likely that in the future we will be required to raise additional
capital via debt and/or equity financings in order to fully realize our
strategic goals and business plans. Our ability to raise additional capital will
depend upon a number of factors, such as general economic and market conditions,
that are beyond our control. If we are unable to obtain additional financing or
to obtain it on favorable terms, we might be required to forego attractive
business opportunities.
We believe our working capital, including the amounts available to us
from our working capital credit facility, is sufficient to sustain our
operations. However, our ability to make payments on and to refinance our
indebtedness, including the notes, and to fund planned capital expenditures will
depend on our ability to generate cash in the future. This, to a certain extent,
is subject to general economic, financial, competitive, legislative, regulatory
and other factors that are beyond our control. We cannot assure you that our
business will generate sufficient cash flow from operations or that future
borrowings will be available to us under our senior credit facilities in an
amount sufficient to enable us to pay our indebtedness, including these notes,
or to fund our other liquidity needs. We may need to refinance all or a portion
of our indebtedness, including these notes on or before maturity. We cannot
assure you that we will be able to refinance any of our indebtedness, including
our senior credit facilities and the notes, on commercially reasonable terms or
at all. See "Risk Factors".
HEDGING POLICY
MARKET RISK. We are exposed to a variety of market risks, including
changes in commodity prices, foreign currency exchange rates and interest rates.
We use various risk management activities to mitigate the effects of these
market risks. We do not use derivative instruments for speculative or trading
purposes.
FOREIGN CURRENCY EXCHANGE RISK. Our financial results are exposed to
fluctuations in the exchange rate between the Canadian dollar and the U.S.
dollar. Crude oil, and to a large extent, natural gas prices, are based upon
reference prices denominated in U.S. dollars, while the majority of our expenses
are denominated in Canadian dollars.
The amounts we received from the offering of the initial notes were in
U.S. dollars and our payment of interest on and principal of the notes will be
made in U.S. dollars. An increase or decrease of $0.10 per US$1.00 would
increase or reduce, respectively, our semiannual payments of interest on the
notes by approximately $817,000 and our payment of the principal of the notes by
$16.5 million.
From time to time, we may enter into agreements to fix the exchange
rate of Canadian dollars to U.S. dollars. We do so in order to offset the risk
of the reduction in our revenues that would occur if the Canadian dollar
increases in value compared to the U.S. dollar. Conversely, we may enter into
agreements to fix the exchange rate to protect the principal and interest
payments on our U.S. dollar denominated liabilities.
INTEREST RATE RISK. We are exposed to changes in interest rates,
because our senior credit facilities bear interest at our lenders' prime lending
rate, or at the banker's acceptance rate, or at the London Interbank Offered
Rate (referred to as LIBOR) plus a margin based on our ratio of total
consolidated debt to cash flow. Thus, our cost of borrowing fluctuates and the
applicable rate on any borrowings under this facility may be sensitive to
changes in our lender's prime rate, the banker's
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acceptance rate and the LIBOR rate. The fixed interest rate nature of our US$165
million senior notes, for the most part, mitigates this exposure. There are
currently no amounts outstanding on our credit facilities.
The majority of our long-term debt has a fixed interest rate and we
periodically use interest rate swaps to manage our debt serving costs.
COMMODITY PRICE RISK. Our financial results can be significantly
affected by the prices received for our crude oil and natural gas production, as
commodity prices fluctuate widely in response to changing market forces. We
expect this pricing volatility to continue.
From time to time, we seek to reduce our exposure to commodity price
risk by entering into long-term production contracts and commodity hedging
contracts (in which we agree to sell a fixed amount of oil or natural gas at a
specified date in the future), to hedge our commodity price risk. We recognize
our realized gains or losses from our hedging activities as crude oil and
natural gas production revenue, when the associated production occurs.
During fiscal 2000, approximately 39% of our natural gas production was
committed to aggregators and received a price lower than AECO (spot market
price). In addition, we sold 549,000 barrels of crude oil at a price of US$21.75
per barrel for delivery in 2000. Our average crude oil price of $33.92 per
barrel, realized for the 2000 fiscal year, is net of a hedging opportunity cost
of $13.94 per barrel relating to the 549,000 barrels of production hedged.
Additionally, in January 2000, we entered into an agreement to sell 7.1 mmcf/d
of natural gas pursuant to contracts at the then market price of $3.55 per mcf.
In total, these contracts had an opportunity cost of $7.7 million for fiscal
2000.
None of our fiscal 2001 crude oil production was hedged. With respect
to natural gas, we contracted 9.5 mmcf/d of gas, from November 1, 2000 through
March 31, 2001, under a costless collar arrangement, having a floor of $5.80 per
mcf and a ceiling of $9.54 per mcf. A costless collar is a hedging arrangement,
purchased at no cost to us, whereby we will receive a price within a price
collar or range for oil and natural gas production. Additionally, we contracted
5.7 mmcf/d from April 1, 2001 through to October 31, 2001, under a costless
collar arrangement, having a floor price of $6.85 per mcf and a ceiling of $8.63
per mcf. In July, 2001 with the Hornet acquisition, we acquired a contract to
sell 4,000 GJ/d of natural gas to January 31, 2002 at an AECO fixed price of
$4.89 per GJ. In total, these contracts produced a gain of $3.7 million that was
included in oil and gas revenues for the year.
Currently for fiscal 2002 we have hedged approximately 22% of our
current production. The table below sets forth our forward sales contracts and
other hedging arrangements for 2002 and 2003, that were outstanding as at June
30, 2002, and shows the unrecognized gain or loss on each such arrangement as if
the crude oil or natural gas had been sold at the market price on June 30, 2002:
HEDGING TRANSACTION PERIOD AMOUNT PRICE RANGE (DOLLARS IN THOUSANDS)
UNRECOGNIZED (GAIN) OR
LOSS AS AT JUNE 30, 2002
- --------------------------- ------------------------ ----------------- -------------------- ------------------------
Natural Gas Collar April 2002 - October 15,000 GJ/d @ $3.83/GJ-$5.45/GJ $ (818)
2002 AECO
Natural Gas Fixed Price May 2002 - October 2002 5,000 GJ/d @ $4.50/GJ $ (683)
Contract AECO
Crude Oil Collar May 2002 - December 1,500 bbls/d US $23.83/bbl - $ -
2002 US $28.00/bbl
Crude Oil Fixed Price May 2002 - December 500 bbls/d US $24.40/bbl $ 111
Contract 2002
Natural Gas Collar November 2002 - March 5,000 GJ/d @ $4.50/GJ - $7.85/GJ $ -
2003 AECO
The table below sets forth forward sales contracts and other hedging
arrangements for 2002 and 2003, that are currently outstanding and were entered
into by us subsequent to June 30, 2002.
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HEDGING TRANSACTION PERIOD AMOUNT PRICE RANGE
- ----------------------------- --------------------------- -------------------- ------------------------------
Natural Gas Collar November 2002 - March 2003 20,000 GJ/d @ AECO $4.00/GJ - $6.55/GJ
Crude Oil Collar January 2003 - December 500 bbls/d US$23.50/bbl - US$27.00/bbl
2003
Crude Oil Fixed Price January 2003 - December 500 bbls/d US$25.00/bbl
Contract 2003
No other hedging contracts are in place for the year 2003.
RECENT ACCOUNTING PRONOUNCEMENTS
On July 20, 2001, the Financial Accounting Standards Board ("FASB")
issued Statement of Financial Accounting Standards ("SFAS") 141, BUSINESS
COMBINATIONS, and SFAS 142, GOODWILL AND INTANGIBLE ASSETS. SFAS 141 is
effective for all business combinations completed after June 30, 2001. SFAS 142
is effective for fiscal years beginning after December 15, 2001; however,
certain provisions of this statement apply to goodwill and other intangible
assets acquired between July 1, 2001 and the effective date of SFAS 142. Major
provisions of these statements and their effective dates for us are as follows:
o All business combinations initiated after June 30,
2001 must use the purchase method of accounting. The pooling
of interest method of accounting is prohibited except for
transactions initiated before July 1, 2001.
o Intangible assets acquired in a business combination
must be recorded separately from goodwill if they arise from
contractual or other legal rights or are separable from the
acquired entity and can be sold, transferred, licensed, rented
or exchanged, either individually or as part of a related
contract, asset or liability.
o Goodwill, as well as intangible assets with
indefinite lives, acquired after June 30, 2001, will not be
amortized. Effective January 1, 2002, or the first day of the
fiscal year of SFAS 142 implementation, all previously
recognized goodwill and intangible assets with indefinite
lives will no longer be subject to amortization.
o Effective January 1, 2002, or the first day of the
fiscal year of SFAS 142 implementation, goodwill and
intangible assets with indefinite lives will be tested for
impairment annually and whenever there is an impairment
indicator.
o All acquired goodwill must be assigned to reporting
units for purposes of impairment testing and segment
reporting.
Management's assessment is that these statements do not have a material
impact on our financial position or results of operations.
In July, 2001, the FASB issued SFAS No. 143, ACCOUNTING FOR ASSET
RETIREMENT OBLIGATIONS. This statement addresses financial accounting and
reporting for obligations associated with the retirement of tangible long-lived
assets and the associated asset retirement costs. This statement applies to all
entities. It applies to legal obligations associated with the retirement of
long-lived assets that result from the acquisition, construction, development
and (or) the normal operation of a long-lived asset, except for certain
obligations of lessees. This statement is effective for financial statements
issued for fiscal years beginning after June 15, 2002. We are evaluating the
impact of the adoption of this standard and we have not yet determined the
effect of adoption on our financial position and results of operations.
In August, 2001, the FASB issued SFAS No. 144, ACCOUNTING FOR THE
IMPAIRMENT OR DISPOSAL OF LONG-LIVED ASSETS. This statement addresses financial
accounting and reporting for the impairment or disposal of long-lived assets and
supersedes FASB Statement No. 121, ACCOUNTING FOR THE Impairment OF LONG-LIVED
ASSETS AND FOR LONG-LIVED ASSETS TO BE DISPOSED OF. The provisions of the
statement are effective for financial statements issued for fiscal years
beginning after December 15, 2001. Management's assessment is that these
statements do not have a material impact on our financial position or results of
operations.
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In July 2002, the FASB issued SFAS No. 146, ACCOUNTING FOR COSTS
ASSOCIATED WITH EXIT OR DISPOSAL ACTIVITIES. SFAS 146 nullifies EITF 94-3,
LIABILITY RECOGNITION FOR CERTAIN EMPLOYEE TERMINATION BENEFITS AND OTHER COSTS
TO EXIT AN ACTIVITY (including Certain Costs Incurred in a Restructuring). SFAS
146 requires the recognition of a liability for costs associated with exit or
disposal activities when a liability is incurred; that is, the costs meet the
definition of a liability in accordance with Concepts Statement 6, ELEMENTS OF
FINANCIAL STATEMENTS. The statement also provides guidance on the required
disclosures of exit and disposal activities. SFAS 146 is effective for exit or
disposal activities initiated after December 31, 2002.
BUSINESS
THE COMPANY
We are an independent public company actively engaged in the
exploration, development and production of natural gas, natural gas liquids and
crude oil in western Canada. We have established our current operational base
through a combination of a program of full-cycle exploration and strategic
acquisitions. This involves:
o establishing core geographic operating areas through strategic
acquisitions;
o developing significant operational and technical expertise
through exploration and development activities;
o acquiring strategic control over infrastructure; and
o reinvesting operating cash-flow to further
consolidate our position in each of our core areas and to
further grow our inventory of drilling prospects.
We began operations in 1993 with a small technical team and a large
seismic database. Through a series of acquisitions and continued drilling
success, we have established total proved reserves of 321 bcfe as of December
31, 2001. Approximately 82% of our total proved reserves are natural gas and
approximately 89% of our total proved reserves are proved developed. As of June
30, 2002, we held working interests in 826,591 (635,371 net) acres of
undeveloped land and we held working interests in 1,056 gross (437.2 net)
producing wells in western Canada.
We currently focus our operations in four geographic areas:
o SOUTHERN ALBERTA-- ESTABLISHED IN 1993: We have one of the
largest land positions in the area, with more than 452,488 net
acres (330,001 net undeveloped acres) of gas-prone lands.
Concentrated in and around our net acreage, there are
approximately, 1,800,000 acres or 2,850 sections of land. We
own approximately 25% of these lands, which represents the
largest percentage of land ownership among oil and gas
companies operating within the area. These lands are primarily
gas-prone, with 64% of producing wells within the area being
natural gas wells. We operate substantially all of our
production and have long-term access to necessary processing
facilities in this area. We believe that our land ownership
position in this area will provide us with a multi-year
inventory of exploration and development prospects. This area
represented 69% of our proved reserves as of December 31,
2001, 52% of our net undeveloped land as of June 30, 2002, 53%
of our production for the year ended December 31, 2001 and 55%
of our production for the six months ended June 30, 2002.
o WEST CENTRAL ALBERTA -- ESTABLISHED IN 1998: This
area has significant natural gas and light oil production. We
plan to increase our long-life, high-quality, light oil
production through a variety of exploitation techniques and to
pursue multi-zone gas exploration targets. This area
represented 17% of our proved reserves as of December 31,
2001, 18% of our net undeveloped land as of June 30, 2002, 26%
of our production for the year ended December 31, 2001 and 24%
of our production for the six months ended June 30, 2002.
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o PEACE RIVER ARCH-- ESTABLISHED IN 1998: This north-central
Alberta core area offers us a range of opportunities,
including lower-risk exploitation, secondary recovery efforts
and pure natural gas exploration. Our light oil development
program, which consists of secondary recovery through water
flooding of the reservoir and infill drilling, provides us
with predictable ongoing production and an extension of the
area's reserve life. We plan to expand and consolidate our
operations in this core area by acquiring additional land and
increasing control of operatorship and infrastructure. This
area represented 13% of our proved reserves as of December 31,
2001, 10% of our net undeveloped land as of June 30, 2002, 18%
of our production for the year ended December 31, 2001 and 19%
of our production for the six months ended June 30, 2002.
o NORTHERN ALBERTA-- ESTABLISHED IN 1996: Within the
Rainbow/Zama area in northern Alberta, we have a large
undeveloped land base consisting of more than 96,000 net acres
that we believe provides us with multi-zone exploration
opportunities. This area is relatively under-explored due to
its remoteness. Industry interest, however, has heightened
with increased drilling and infrastructure activity on lands
adjacent to ours. Since 1996, drilling activity and
infrastructure construction has increased considerably in the
Rainbow/Zama area. In 1996, a total of 63 wells were drilled
by the oil and gas industry, as compared to approximately 225
wells in fiscal 2001. Moreover, a major natural gas pipeline
was installed in fiscal 2000 which transports gas through our
main block of lands. More recently, two other oil and gas
companies have installed natural gas gathering pipelines in
the area. This area represented 1% of our proved reserves as
of December 31, 2001, 15% of our net undeveloped land as of
June 30, 2002, 3% of our production for the year ended
December 31, 2001 and 2% of our production for the six months
ended June 30, 2002.
In addition to our four core areas discussed above, we have 5% of our
net undeveloped land in minor properties outside of our four geographic core
areas. These lands are located in northeastern British Columbia, northeastern
Saskatchewan and southern Manitoba. These minor properties were acquired
primarily as a result of acquisitions of corporations whose primary assets were
in one or more of our core areas. Currently, less than 1% of our production
comes from these minor properties.
BUSINESS STRATEGY
Our strategy is to grow our reserves and increase our production in our
four core geographic areas and other areas where we have technical expertise.
Our senior management team has significant technical and operational expertise
with an average of 20 years of experience in one or more of our core areas. Our
senior management team has demonstrated its ability to execute our strategy
while exercising financial discipline. Through effective leadership, our senior
management team has enabled us to deliver strong growth in both the size of
reserves and the quantity of our production while preserving and strengthening
our financial position. Since 1999, our proved reserves and production have
grown on a compounded annual rate basis of 14% and 19%, respectively, while
EBITDA has increased from $56.2 million in fiscal 1999 to $142.5 million in
fiscal 2001. Our total EBITDA over this three year period was $329.9 million and
our interest expense over this period was $32.6 million, ratio of EBITDA to
interest expense of 10.1 times. Our current senior management team has overseen
this growth in reserves, production, and EBITDA while maintaining a high ratio
of EBITDA to interest expense.
CONCENTRATE ON FOUR CORE GEOGRAPHIC AREAS. We currently operate in four
core geographic areas which provides us with a balanced portfolio of exploration
and development prospects. The natural gas and light oil development projects in
our portfolio include lower decline reserves. Our portfolio of lower decline
reserves is reflected in our high proved reserve life index of 8.2 years for
fiscal 2001. Our reserves decline at a lower rate which will allow us to
generate a steady stream of production over the next several years. The cash
flow from these projects is used to fund our on-going, multi-zone, deep gas
exploration program.
FOCUS ON NATURAL GAS. We have gained considerable technical expertise
and achieved significant success in exploring for deeper and larger natural gas
reservoirs. In 2001, our average well depth was approximately 1,790 meters,
which is significantly deeper than the Alberta oil and gas industry average well
depth of approximately 1,000 meters. Notwithstanding our increased focus on
drilling for deeper gas reservoirs, we were able to achieve a drilling success
rate of 76% in 2001, as compared to our drilling success rate of 61% in 1998. We
plan to continue to focus on finding and developing long-life natural gas
reserves. Our proved reserves as of December 31, 2001 of 321 bcfe were
approximately 82% natural gas with an estimated reserve life of 8.2 years at
that date.
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PURSUE FULL-CYCLE EXPLORATION COMPLEMENTED BY SELECTIVE ACQUISITIONS.
We plan to continue to reinvest internally generated cash flow to fund the
growth of our exploration prospects and development projects and to further
consolidate our undeveloped land base to maintain a growing inventory of
drilling prospects in our core geographic areas. Since January 1, 1997, we have
replaced 327% of our aggregate production with proved reserve additions, growing
our existing proved reserve base from 48 bcfe at December 31, 1996 to 321 bcfe
at December 31, 2001, at an average cost of $9.25 per boe. We have also
successfully completed and integrated a series of strategic acquisitions to grow
our proved reserves and production base and enhance our technical expertise in
our core areas. Depending on commodity price cycles, we may defer exploration
projects and enhance our operations and prospects through strategic
acquisitions.
CONTROL OF INFRASTRUCTURE AND OPERATORSHIP. We believe that control
over gathering and processing infrastructure and operatorship of drilling
programs will continue to be critical to the success of our full-cycle
exploration program. We currently own or have access to all critical
infrastructure in each of our three primary producing areas. We operate
approximately 92% of our existing production and, as of June 30, 2002 we had a
77% average working interest in our undeveloped lands. This position allows us
to exercise discretion in determining the timing and methodology of our ongoing
exploration and development programs. We will continue to consolidate our
position in our core areas to maximize operating efficiencies and maintain
control over our ongoing capital programs.
MAINTAIN A LARGE PORTFOLIO OF UNDEVELOPED LAND. We have assembled a
significant portfolio of undeveloped land (working interests in 826,591 (635,371
net) acres of undeveloped land, as of June 30, 2002) and complementary seismic
data in our core areas. We believe that our existing portfolio of undeveloped
land is sufficient to produce at least three years of internally generated
exploration and development prospects. Our extensive internal prospect inventory
is based on the large portfolio of undeveloped land that we hold for drilling
activities. With 635,371 net acres, or approximately 1,000 sections of
undeveloped land, we can drill approximately 1,000 wells (each well is located
on approximately 1 section of land). Assuming that only half of these lands are
prospective for oil and natural gas, approximately 500 wells could be drilled,
which would provide us with sufficient land for exploration and development
activities for the next three to five years.
MAINTAIN FINANCIAL FLEXIBILITY. We are committed to maintaining
financial flexibility to allow us to pursue our full-cycle exploration program
in periods of low commodity prices. We also intend to maintain the flexibility
to respond to opportunities for strategic acquisitions as they arise. We have
historically funded our capital program through internally generated cash flow
and have financed acquisitions through bank debt, the issuance of common stock,
or a combination thereof.
SEASONALITY OF THE OIL AND GAS INDUSTRY
The exploration for and development of oil and gas reserves is
dependant on access to areas where operations are to be conducted. Oil and gas
industry operations in Western Canada are affected by road bans imposed from
time to time, during the break-up and thaw period in the spring. Road bans are
also imposed due to snow, mud and rock slides and periods of high water which
can restrict access to our well sites and production facility sites.
Additionally, demand for crude oil and natural gas varies seasonally.
Demand for natural gas is greatest in the winter months to meet peak heating
demand, which demand for gasoline and the types of crude oil most used to
produce it is higher in summer months.
SUBSIDIARIES
Our wholly owned corporate subsidiaries are identified in the chart
below.
[GRAPHIC OMITTED]
Compton Petroleum Corporation
-----------------------------
100% 100% 100%
---- ---- ----
------------------ ------------------- -------------------
Hornet Energy Ltd. 867791 Alberta Ltd. 899776 Alberta Ltd.
(a Canadian (an Alberta (an Alberta
Corporation) Corporation) Corporation)
------------------ ------------------- -------------------
-36-
Effective January 31, 2001, a general partnership called Compton
Petroleum was formed under the laws of Alberta, between us and our wholly owned
subsidiary 867791 Alberta Ltd. On July 16, 2001, the partnership agreement was
amended to include Hornet Energy Ltd. Each partner has contributed a majority of
its assets to the partnership. The majority of our operations are carried out
through the partnership. We are the general partner of the partnership and have
a 90.9% interest. Hornet Energy Ltd. and 867791 Alberta Ltd. are both limited
partners and have a 5.3% and 3.8% interest, respectively.
RECENT DEVELOPMENTS
Currently for fiscal 2002 we have hedged approximately 22% of our
current production. With respect to natural gas, we contracted 15,000 GJ/d at
AECO from April 2002 through October 2002 a costless collar arrangement having a
floor of $3.83 per GJ and a ceiling of $5.45 per GJ. Additionally, we sold 5,000
GJ/d at AECO from May 2002 to October 2002 at a fixed price of $4.50 per GJ. For
crude oil, we have sold 500 bbls/d from May 2002 to December 2002 at a fixed
price of US$24.40 per barrel. Additionally, we contracted 1,500 bbls/d from May
2002 to December 2002 under a costless collar arrangement having a floor price
of US$23.83 per barrel and a ceiling of US$28.00 per barrel. We also have
contracted 5,000 GJ/d of natural gas at AECO from November 1, 2002 to March 31,
2003 under costless collar arrangements having a floor of $4.50 per GJ and a
ceiling of $7.85 per GJ. Additionally, we contracted 20,000 GJ/d at AECO from
November 1, 2002 to March 31, 2003 under a costless collar arrangement having a
floor of $4.00 per GJ and a ceiling of $6.55 per GJ.
For fiscal 2003, with respect to crude oil, we contracted 500 bbls/d
from January 2003 to December 2003 under a costless collar arrangement having a
floor price of US$23.50 per barrel and a ceiling of US$27.00 per barrel. We have
also sold 500 bbls/d from January 2003 to December 2003 at a fixed price of
US$25.00 per barrel. No other hedging contracts are in place for fiscal 2003.
Our average daily production for the first six months of 2002 was
19,193 boe/d, an increase of 13% over the 17,009 boe/d for the comparable period
in 2001. Commodity prices realized during the period, however, were
significantly lower than the historically high prices realized during the first
six months of 2001. Both the West Texas Intermediate oil benchmark price and the
AECO natural gas price index decreased substantially from the first six months
of 2001, down 16% and 57%, respectively. This dramatic drop in commodity prices
had an adverse impact on our first six months 2002 earnings and cash flow.
PRINCIPAL PROPERTIES
The following table summarizes the net daily production from our four
core operating areas for the six-month period ended June 30, 2002:
NATURAL
CRUDE OIL GAS LIQUIDS NATURAL GAS TOTAL
------------ ------------ ------------ ----------
(BBLS/D) (BBLS/D) (MMCF/D) (BOE/D)
Southern Alberta........... 117 996 57.2 10,633
West Central Alberta....... 1,535 355 16.3 4,600
Peace River Arch........... 1,573 238 10.8 3,620
Northern Alberta........... 102 33 1.2 340
------------ ------------ ------------ ----------
Total.................. 3,327 1,622 85.5 19,193
============ ============ ============ ==========
The following table sets forth our percentage of revenue for natural
gas, crude oil and natural gas liquids for each of our principal properties
during each of the years ended December 31, 2000, December 31, 2001 and for the
six-month period ended June 30, 2002.
YEAR ENDED DECEMBER 30, 2000
-------------------------------------------
NATURAL GAS CRUDE OIL NATURAL
GAS LIQUIDS
------------ ----------- ------------
Southern Alberta.......... 53% 14% 64%
West-Central Alberta...... 24 65 25
Peace River Arch.......... 22 19 11
Northern Alberta.......... 1 2 0
------------ ----------- ------------
Total................. 100% 100% 100%
============ =========== ============
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YEAR ENDED DECEMBER 31, 2001
-------------------------------------------
NATURAL GAS CRUDE OIL NATURAL
GAS LIQUIDS
------------ ----------- ------------
Southern Alberta.......... 65% 3% 69%
West-Central Alberta...... 20 49 21
Peace River Arch.......... 13 41 7
Northern Alberta.......... 2 7 3
------------ ----------- ------------
Total................. 100% 100% 100%
============ =========== ============
SIX MONTH PERIOD ENDED JUNE 30, 2002
-------------------------------------------
NATURAL GAS CRUDE OIL NATURAL
GAS LIQUIDS
------------ ----------- ------------
Southern Alberta.......... 67% 4% 61%
West-Central Alberta...... 19 46 22
Peace River Arch.......... 13 47 15
Northern Alberta.......... 1 3 2
------------ ----------- ------------
Total................. 100% 100% 100%
============ =========== ============
SOUTHERN ALBERTA
Our southern Alberta properties cover an extensive area commencing from
Calgary's southern city limit and running 150 kilometres south through the
Gladys, Okotoks-Mazeppa and Hooker areas to the Keho Lake area. In 1993, we
commenced operations in the Gladys area, where we are now one of the largest
landowners and where we operate the majority of our producing wells. We have
significantly expanded our land and production base in the Okotoks-Mazeppa,
Hooker and Keho Lake areas through property and facility acquisitions, purchases
of land from the government and private owners acquisition of interests in
properties produced by other companies and exploration activities. In
particular, we have developed a very extensive Basal Quartz play at Hooker. The
Basal Quartz play is an incised valley system containing Cretaceous sandstone
reservoir rock that we believe extends over at least 60 kilometers and holds
large quantities of liquids-rich, low decline natural gas reserves at 2,400 to
3,400 meter depths. In the fall of 2000, we acquired an additional 39,047 acres
at Aphrodites area, which is to the south of Hooker.
As of June 30, 2002, we had working interests in 569,038 gross (452,488
net) acres of land in the southern Alberta area at an average working interest
of 80%. In the Foothills, an extension of the southern Alberta core area, we
have acquired 100% working interests in 47,930 gross (47,930 net) acres of land
on the Tsuu T'ina First Nation Reservation immediately west of Calgary. As well,
we have working interests in 6,002 gross (4,202 net) acres of land 50 kilometres
northwest of Calgary with an average working interest of 70%.
We have a 100% working interest in a 3.2 mmcf/d natural gas plant at
Keho Lake, and an 8.2% working interest in a 40 mmcf/d natural gas plant at
Vulcan. We have a 100% working interest in three crude oil batteries at Keho
Lake, Gladys and Connemara. As well, we have significant working interests in
strategic gathering and compression systems, including a 100% interest at
Centron, an 80% interest at High River and a 93% interest at Brant.
Our southern Alberta properties will continue to be a key focus for our
exploration, exploitation and development program. Since inception, we have
focused on this core area and we have secured a large land base, substantial
seismic information, ownership or access to infrastructure and processing
capacity, high working interests and operatorship. Having established long-term
access to necessary infrastructure in this area, combined with a multi-year
inventory of exploration and development prospects, we believe that we are well
positioned to explore, exploit and develop our southern Alberta properties to
their full potential. We have focused on exploiting and developing multiple
natural gas bearing reservoirs in this area, particularly in the Basal Quartz,
Crossfield, Belly River, Ellerslie and Turner Valley formations.
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WEST-CENTRAL ALBERTA
As of June 30, 2002, we had working interests in 406,774 gross (178,705
net) acres of land in the west central Alberta area with a 44% working interest.
We have working interests in 55,040 gross (43,315 net) acres of land,
with an average working interest of 79%, in the Bigoray, Pembina, Tomahawk and
Rosevear areas, approximately 100 kilometres west of Edmonton. Production occurs
from six light crude oil pools, namely the Nisku D, E and F pools, the Cardium B
pool, the Pekisko F pool and from a new Ostracod natural gas discovery. We sold
our 15.4% working interest in the 39 mmcf/d Bigoray Gas Plant for $4.2 million
and entered into an agreement to receive preferential long-term processing fees
that were 17% lower than the processing fees charged to other companies
processing gas at the plant. We have retained a 100% interest in an crude oil
battery and compressor station. At Bigoray, we completed the expansion of its
fluid handling capability, increasing this capability to 25,000 bbls/d from
6,000 bbls/d. The west-central Alberta area provides us with excellent
development drilling opportunities and adds an important balance to our
portfolio of exploration areas.
We are pursuing significant additional exploration and exploitation
activities in our working interests in another 351,734 gross (135,390 net) acres
of land, with an overall working interest of 38%, in other parts of central
Alberta, including Halkirk, Garrington and Gilby to the south and east of
Bigoray.
PEACE RIVER ARCH, NORTH-CENTRAL ALBERTA
We have working interests in 155,840 gross (95,918 net) acres of land
approximately 20 to 30 kilometres north of Grande Prairie, as of June 30, 2002
with a 62% working interest.
At Cecil, we own various working interests in 39,040 gross (18,881 net)
acres of land, with a 48% average working interest in the aggregate. Production
from the property is primarily crude oil and natural gas from the Cecil Charlie
Lake "A", "L & M", "R" and "S" pools. Kiskatinaw crude oil production also
became important in 2001. We own a 40% working interest and a 83% working
interest in two central crude oil batteries and a 40% working interest in a
solution gas plant servicing production at South Cecil. We also own a 40%
working interest in a central battery at North Cecil and we own working
interests ranging from 13.9% to 19.5% in the various functional units of the
North Cecil Gas Plant. This third party operated natural gas plant was placed on
stream in April 1998 and is currently capable of processing 50 mmcf/d.
At Worsley, we own working interests in 8,640 gross (7,093 net) acres
of land, a 82% working interest, primarily prospective for crude oil and natural
gas from the Charlie Lake formation. We also own a 95.3% working interest in a 4
mmcf/d solution gas plant and an 80% working interest in an crude oil battery.
At Clayhurst, natural gas production is obtained from four Compton
operated wells. Natural gas is delivered through a 11.4 kilometre sales line
which is 100% owned by us and which provides us with strategic control over a
large region that is geographically isolated by river gorges. Our land position
consisting of 18,080 gross (12,544 net) acres at an average working interest of
69% of undrilled land in this area is proximate to a natural gas gathering
system and processing facility which is leased by us. An amine unit was
installed in 2000 to allow for sour gas production.
In the Progress, Saddlehills, Sexsmith and Howard areas, we hold a
21.7% working interest in the Progress Halfway Unit, which contains 14 producing
natural gas wells. Production in the area also occurs from the Doe Creek,
Bluesky, Gething, Cadomin, Charlie Lake and Montney formations. We have a 4.96%
working interest in the 147 mmcf/d Progress Gas Plant and a 4.4% working
interest in the 31 mmcf/d Teepee Creek Gas Plant, both of which are located in
this area.
The Peace River Arch area is highly competitive and offers multizone
potential for both exploration and development opportunities. Specifically, we
believe that our Cecil and Worsley crude oil properties offer excellent
development opportunities, while our Clayhurst and area natural gas property has
multizone exploration potential.
WEST RAINBOW AND ZAMA, NORTHERN ALBERTA/BRITISH COLUMBIA
We own working interests in 137,775 gross (101,653 net) acres of land
in the West Rainbow and Zama areas of northern Alberta and British Columbia, as
of June 30, 2002, with a 74% working interest.
-39-
We acquired the exploration lands in West Rainbow to find and develop
natural gas reserves in an area characterized by multiple potential reservoirs,
including the Cretaceous Bluesky, Mississippian zones and the Devonian, Jean
Marie, Sulphur Point, Slave Point and Keg River formations. We also have
production and exploitation opportunities on our lands to the north at Zama.
OTHER UNDEVELOPED LAND
In addition to our four core areas discussed above, we have 5% of our
net undeveloped land in minor properties outside of our four geographic core
areas. These lands are located in northeastern British Columbia, northeastern
Saskatchewan and southern Manitoba. These minor properties were acquired
primarily as a result of acquisitions of corporations whose primary assets were
in one or more of our core areas. Currently, less than 1% of our production
comes from these minor properties.
RESERVES SUMMARY
Reserve calculations involve the estimate of future net recoverable
reserves of crude oil, natural gas liquids and natural gas and the timing and
amount of future net revenue to be received therefrom. Such estimates are not
precise and are based on assumptions regarding a variety of factors, many of
which are variable and uncertain. See "Risk Factors -- Risks Related to our
Business".
The following table summarizes our undeveloped land and our natural
gas, crude oil and natural gas liquids reserves as at the dates indicated and
the present value attributable to the reserves as of those dates, discounted at
10%. The reserve information as of December 31, 2001 was prepared by Outtrim
Szabo Associates Ltd. The reserve information as of December 31, 1999 and 2000
was prepared by or reviewed by Outtrim Szabo Associates Ltd.
In connection with Outtrim Szabo Associates Ltd.'s reserve evaluation,
we provided them with land data, well information, geological information,
reservoir studies, estimates of on-stream dates, contract information, current
hydrocarbon product prices, operating cost data, capital budget forecasts,
financial data and future operating plans. Outtrim also obtained other
engineering, geological or economic data required by them from public records,
other operators and their non-confidential files. Outtrim did not independently
verify the factual information that we provided to them or that they obtained
from other sources and did not conduct a field inspection.
HISTORICAL
------------------------------------------
AS OF DECEMBER 31,
------------------------------------------
1999 2000 2001
------------ ------------ ------------
PROVED RESERVES:
Natural gas (mmcf).................. 181,759 223,761 262,448
Crude oil & natural gas liquids (mbbls) 10,682 9,423 9,777
Natural gas equivalent (mmcfe).... 245,851 280,302 321,110
% natural gas..................... 74% 80% 82%
% proved developed................ 85% 85% 89%
Estimated reserve life (in years)(1) 8.9 7.9 8.2
Annual reserve replacement ratio(2). 268% 197% 204%
Recycle ratio(3).................... 1.2x 2.2x 1.5x
PV-10 (thousands of dollars)(4)..... $ 393,448 $ 1,227,443 $ 465,619
Standardized measure of discounted
future net cash flows (thousands in
dollars)............................ $ 271,486 $ 709,869 $ 317,461
UNDEVELOPED LAND
Gross undeveloped land (thousands of
acres)............................ 707 808 962
Working interest percentage......... 71% 76% 73%
- ----------
(1) Reserve life is calculated by dividing our proved reserves at year end
by our annual production in that year.
(2) The annual reserve replacement ratio is a percentage determined by
dividing our estimated proved reserves added during a year from
exploitation, development and exploration activities, acquisition of
proved reserves and revisions of previous estimates, excluding property
sales, by our annual production in that year.
(3) The recycle ratio is a multiple determined by dividing our netback per
boe by our finding and development costs per boe in that year. Netback
per boe is calculated by dividing our annual net revenues generated
from producing oil and natural gas volumes, net of operating costs and
administrative
-40-
expenses by our annual production in that year. Finding and development
costs per boe is calculated by dividing our estimated finding and
development costs associated with our estimated proved reserves added
during the year by our estimated proved reserves added in that year
from exploitation, development and exploration activities, acquisition
of proved reserves and revisions of previous estimates, excluding
property sales.
(4) PV-10 is the present value of our estimated future net cash flows
before income taxes, discounted at 10% per year, calculated using
constant pricing. The prices used in 1999 were $2.88 per mcf of natural
gas, $36.64 per barrel of crude oil and $30.88 per barrel of natural
gas liquids. The prices used in 2000 were $9.69 per mcf of natural gas,
$39.33 per barrel of crude oil and $37.57 per barrel of natural gas
liquids. The prices used in 2001 were $3.68 per mcf of natural gas,
$32.63 per barrel of crude oil and $22.98 per barrel of natural gas
liquids. PV-10 is not necessarily indicative of actual future cash
flows.
STANDARDIZED MEASURE
The Standardized Measure of Discounted Future Net Cash Flows and
Changes Therein Relating to Proven Oil and Natural Gas Reserves (the
"Standardized Measure") does not purport to present the fair market value of our
crude oil and natural gas properties. An estimate of such value should consider,
among other factors, anticipated future prices of crude oil and natural gas, the
probability of recoveries in excess of existing proved reserves and acreage
prospects, and perhaps different discount rates. It should be noted that
estimates or reserve quantities, especially from new discoveries, are inherently
imprecise and subject to substantial revisions.
Under the Standardized Measure, future cash inflows were estimated by
applying year-end prices, adjusted for contracts currently in place to deliver
production to the estimated future production of year-end proved reserves.
Future cash inflows were reduced by estimated future production and development
costs, based on year-end costs, to determine pre-tax cash inflows. Future taxes
were computed by applying the statutory tax rate to the excess of pre-tax cash
inflows over our tax basis in the associated proved crude oil and natural gas
properties. Tax credits and net operating loss carry forwards were also
considered in the future income tax calculation.
The following table shows the present value of our estimated future
cash flow, after income taxes, from our proved crude oil and natural gas
reserves, discounted at 10%, using constant pricing, as calculated by us in
accordance with the SFAS 69 accounting standard:
DECEMBER 31,
------------------------------------
1999 2000 2001
--------- ---------- ---------
(DOLLARS IN THOUSANDS)
Standardized measure of discounted
future net cash flows................ $ 271,486 $ 709,869 $ 317,461
PRODUCTION COSTS
The following table shows our production costs for the periods
indicated:
SIX MONTHS ENDED
YEARS ENDED DECEMBER 31, JUNE 30,
------------------------------------- -------------------------
1999 2000 2001 2001 2002
---------- --------- ---------- ---------- ------------
Crude oil and natural gas liquids ($/bbl) 5.42 7.66 8.25 8.22 8.41
Natural gas ($/mcf).................... 0.68 0.72 0.89 0.86 0.93
Total ($/boe)...................... 4.45 5.32 6.13 6.01 6.29
DRILLING ACTIVITY
The number of gross and net exploratory and development wells we
drilled during the periods indicated is shown below:
EXPLORATORY WELLS
GROSS NET
-------------------------------------- ----------------------------------------
PRODUCTIVE NON-PRODUCTIVE TOTAL PRODUCTIVE NON-PRODUCTIVE TOTAL
------------ ----------- ------- ------------ ------------ ----------
1999............................... 23 16 39 17.1 15.0 32.1
2000............................... 33 23 56 27.1 18.0 45.1
2001............................... 31 15 46 24.0 13.0 37.0
January 1 - June 30, 2002.......... 10 3 13 7.5 2.3 9.8
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DEVELOPMENT WELLS
GROSS NET
-------------------------------------- ----------------------------------------
PRODUCTIVE NON-PRODUCTIVE TOTAL PRODUCTIVE NON-PRODUCTIVE TOTAL
------------ ----------- ------- ------------ ------------ ----------
1999............................... 37 7 44 33.4 5.0 38.4
2000............................... 34 6 40 29.0 4.2 33.2
2001............................... 41 8 49 28.1 5.7 33.8
January 1 - June 30, 2002.......... 24 2 26 14.4 1.0 15.4
PRODUCTIVE WELLS
The following table shows our gross and net interests in productive
crude oil, natural gas and service wells as of June 30, 2002. Productive wells
are producing wells and wells capable of production:
GROSS NET
--------- --------
Crude oil wells............ 470 173.2
Natural gas wells.......... 586 264.0
Service wells.............. - -
--------- --------
Total.................. 1,056 437.2
========= ========
LAND
The following table provides information about the amount of developed
and undeveloped land we owned as of June 30, 2002.
GROSS NET
--------- --------
Developed land (acres)..... 519,115 224,990
Undeveloped land (acres)... 826,591 635,371
--------- --------
Total.................. 1,345,706 860,361
========= ========
MARKETING
We sell our natural gas in a variety of markets to marketers,
distributors and end users. Our natural gas production is sold under a
combination of longer term contracts with aggregators and short term 30 day AECO
indexed contracts. During 2001, approximately 40% of our natural gas production
was sold to aggregators. In southern Alberta, a maximum 30 mmcf/d of natural gas
production is committed to Pan-Alberta Gas Ltd., of which 7 mmcf/d is contracted
until the year 2013 and 23 mmcf/d is contracted until September 2002. Production
volumes in excess of 30 mmcf/d from lands now dedicated to Pan-Alberta Gas Ltd.
are non-contracted. Additionally, production from certain lands in southern
Alberta, currently producing approximately 7 mmcf/d, are contracted to
TransCanada Gas Services Ltd. until the year 2012. Various other minor contracts
with Pan-Alberta Gas Ltd. and TransCanada Gas Services Ltd. are for the life of
the reserves from the lands dedicated.
Crude oil and natural gas liquids are sold under various short term
contracts which track the Edmonton par price. We sell crude oil and natural gas
liquids primarily to refineries and marketers of crude oil and natural gas
liquids.
From time to time, we may enter into hedging arrangements to mitigate
commodity price risk and take advantage of opportunistic pricing. In accordance
with our policy, hedging programs will not exceed 50% of non-contracted
production.
SEISMIC
We own rights to copy and utilize large seismic databases. The rights
to utilize non-proprietary seismic databases have been obtained by us primarily
through purchases of copies of such databases. The third parties who own the
proprietary rights broker or sell database copies to other oil and gas industry
players as well. We also own exclusive proprietary rights of seismic data, that
we have shot and processed directly on lands within areas of interest. These
databases include conventional two-dimensional seismic covering over 90,000
kilometres of land and three dimensional seismic data shot over 2,200 square
kilometres of land primarily in areas throughout Alberta. Additionally, we have
rights to use 6,500
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square kilometres of seismic covering areas in southern Manitoba. Our
exploration team uses these large seismic databases in our exploration and
acquisition decisions.
COMPETITION
The oil and natural gas industry is very competitive. Competition is
particularly intense in the acquisition of prospective oil and natural gas
properties and oil and natural gas reserves. Our competitive position depends on
our geological, geophysical and engineering expertise, our financial resources,
our ability to develop our properties and our ability to select, acquire and
develop proved reserves. We compete with a substantial number of other companies
which have larger technical staffs and greater financial and operational
resources. Many such companies not only engage in the acquisition, exploration,
development and production of oil and natural gas reserves, but also conduct
refining operations and market refined products.
We also compete with other oil and natural gas companies and other
industries supplying energy and fuel in the marketing and sale of oil and
natural gas to transporters, distributors and end users, including industrial,
commercial and individual consumers. We also compete with other oil and natural
gas companies in attempting to secure drilling rigs and other equipment
necessary for drilling and completion of wells. Such equipment may be in short
supply from time to time. Finally, companies not previously investing in oil and
natural gas may choose to acquire reserves to establish a firm supply or simply
as an investment. Such companies will also provide competition for us.
REGULATION
The oil and natural gas industry in Canada is subject to extensive
controls and regulations imposed by various levels of government. We do not
expect that any of these controls or regulations will affect our operations in a
manner materially different than they would affect other oil and natural gas
companies of similar size.
Crude oil and natural gas located in Alberta is owned predominantly by
the provincial government. The provincial government grants rights to explore
for and produce oil and natural gas under leases, licenses and permits with
terms generally varying from two years to five years and on conditions contained
in provincial legislation. Leases, licenses and permits may be continued
indefinitely by producing under the lease, license or permit. Some of the oil
and natural gas located in Alberta is privately owned and rights to explore for
and produce oil and natural gas are granted by the mineral owners on negotiated
terms and conditions.
In Canada, producers of oil negotiate sales contracts directly with oil
purchasers, with the result that the market determines the price of oil. The
price depends in part on oil quality, prices of competing fuels, distance to
market and the value of refined products. Oil exports may be made under export
contracts having terms not exceeding one year in the case of oil other than
heavy oil, so long as an order approving any such export has been obtained from
the National Energy Board. Any oil export to be made pursuant to a contract of
longer duration requires an exporter to obtain an export licence from the
National Energy Board and the issue of a license requires the approval of the
Canadian federal government. The term of the license may not exceed 25 years.
In Canada, the price of natural gas sold in interprovincial and
international trade is determined by negotiation between buyers and sellers.
Natural gas exported from Canada is subject to regulation by the Government of
Canada through the National Energy Board. Producers and exporters are free to
negotiate prices and other terms with purchasers, provided that the export
contracts must continue to meet criteria prescribed by the National Energy
Board. Natural gas exports for a term of two years or less, or for 2 to 20 years
in quantities not more than 30,000 cubic metres (1.1 million cubic feet) per day
may be made under a National Energy Board order and exports for a longer
duration or larger volumes may be made under a National Energy Board license and
Canadian federal government approval.
The Alberta provincial government also regulates the removal of natural
gas from the province for consumption elsewhere. It does so based on such
factors as reserve availability, transportation arrangements and market
considerations.
In addition to federal regulations, each province has legislation and
regulations which govern land tenure, royalties, production rates, environmental
protection and other matters. The royalty regime is a significant factor in the
profitability of oil and natural gas production. Royalties payable on production
from lands other than government lands are determined by
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negotiations between the mineral owner and the lessee. Royalties on government
land are determined by government regulation and are generally calculated as a
percentage of the value of gross production, and the rate of royalties payable
generally depends upon prescribed reference prices, well productivity,
geographical location, field discovery date and the type or quality of the
petroleum product produced. In general, royalty rates are sensitive to sales
prices, as higher prices attract higher royalty rates. Similarly, higher
productivity wells and wells producing a higher grade of crude oil and natural
gas are subject to higher royalty rates.
The complex royalty structure for oil and gas reserves in the province
of Alberta is designed to provide permanent incentives for exploring and
developing such reserves and includes the following policies: (i) the first
wells drilled in new oil pools discovered on or after October 1, 1992 receive a
permanent one year oil royalty holiday, subject to a $1,000,000 per well cap and
a reduced royalty rate thereafter; (ii) the base royalty rates on pre-October 1,
1992 production of oil and gas is reduced; (iii) royalty holidays and reduced
royalties apply to reactivated and low productivity wells, and to vertical oil
wells which require horizontal re-entry; (iv) separate par pricing for light
medium and heavy oil; and (v) a royalty formula which is sensitive to price
fluctuations.
Alberta's Third Tier Royalty applies to oil pools discovered after
September 30, 1992 with a base rate of 10% and a rate cap of 25%. The new oil
royalty reserved to the Alberta government has a base rate of 10% and a rate cap
of 30% and for old oil a base rate of 10% and a rate cap of 35%.
The royalty reserve to the Alberta government, subject to various
incentives, is between 15% and 30%, in the case of new gas, and between 15% and
35%, in the case of old gas, depending upon a prescribed or corporate average
reference price. Natural gas produced from qualifying exploratory natural gas
wells spudded or deepened after July 31, 1985 and before June 1, 1988 continues
to be eligible for a royalty exemption for a period of 12 months, or such later
time that the value of the extended royalty quantity equals a prescribed maximum
amount. Natural gas produced from qualifying intervals in eligible natural gas
wells spudded or deepened to a depth below 2,500 metres is also subject to a
royalty exemption, the amount of which depends upon the depth of the well.
From time to time the governments of Canada and Alberta have
established incentive programs which have included royalty rate deductions,
royalty holidays and tax credits for the purpose of encouraging oil and natural
gas exploration or enhanced recovery projects.
In Alberta, a producer of oil or natural gas is entitled to a credit
against certain royalties payable to the Alberta government by virtue of the
Alberta Royalty Tax Credit Program. The Alberta Royalty Tax Credit Program is
based on a price sensitive formula and ranges between 75%, for prices for oil at
or below $100 per cubic metre, to 25%, for prices above $210 per cubic metre. In
general, the Alberta Royalty Tax Credit rate is applied to a maximum of
$2,000,000 of government royalties payable for each producer or associated group
of producers. Government royalties on production from producing properties
acquired from corporations claiming maximum entitlement to the Alberta Royalty
Tax Credit will generally not be eligible for the Alberta Royalty Tax Credit.
The rate is established quarterly based on the average "par price", as
determined by the Alberta Department of Energy for the previous quarterly
period. The "par price" is the gas reference price established by the Alberta
Department of Energy for determining Alberta government gas royalties. It is
essentially the weighted average price of both contractual and spot gas sold
within the province of Alberta during the month adjusted to reflect
intra-Alberta transportation, a marketing fee, and any pipeline loss. The impact
of the Alberta Royalty Tax Credit on us in fiscal 2001 was $0.5 million.
The North American Free Trade Agreement ("NAFTA") among the governments
of Canada, the United States and Mexico became effective on January 1, 1994.
NAFTA carries forward most of the material energy terms that are contained in
the Canada-U.S. Free Trade Agreement. Subject to the General Agreement on
Tariffs and Trade, Canada continues to remain free to determine whether exports
of energy resources to the United States or Mexico will be allowed, so long as
any export restrictions do not:
o reduce the proportion of energy resources exported relative to
total supply (based upon the proportion prevailing in the most
recent 36 month period or another representative period agreed
upon by the parties);
o impose an export price higher than the domestic price (subject
to an exception that applies to some measures that only
restrict the value of exports); or
-44-
o disrupt normal channels of supply.
All three countries are prohibited from imposing minimum or maximum
export or import price requirements, with some limited exceptions.
ENVIRONMENTAL
The oil and natural gas industry is governed by environmental
regulation under Canadian federal and provincial laws, rules and regulations
which restrict and prohibit the release or emission, and regulate the storage
and transportation, of various substances produced or utilized in association
with oil and natural gas industry operations. In addition, applicable
environmental laws require that well and facility sites be abandoned and
reclaimed, to the satisfaction of provincial authorities, in order to prevent
pollution from former operations. Also, environmental laws may impose upon
"responsible persons" remediation obligations on property designated as a
contaminated site. Responsible persons include persons responsible for the
substance causing the contamination, persons who caused the release of the
substance and any present or past owner, tenant or other person in possession of
the site. A breach of environmental laws may result in the imposition of fines
and penalties, and imprisonment for directors and officers, in addition to the
costs of abandonment and reclamation.
The primary environmental statute in Alberta is the ENVIRONMENTAL
PROTECTION AND ENHANCEMENT Act. This Act is administered and enforced by Alberta
Environment. Certain environmental aspects of the oil and natural gas industry
are also regulated by the Alberta Energy & Utilities Board (the "EUB") under
various statutes, regulations, guides and codes of practice. Both Alberta
Environment and the EUB have significant powers and ranges of enforcement
actions available to force compliance with environmental regulations.
We have established guidelines and management systems to ensure
compliance with environmental laws, rules and regulations. We have designated a
compliance officer whose responsibility is to monitor regulatory requirements
and their impact on us and to implement appropriate compliance procedures. We
also employ an environmental manager whose responsibilities include ensuring
that our operations are carried out in accordance with applicable environmental
guidelines and implementing adequate safety precautions. The existence of these
positions cannot, however, guarantee total compliance with environmental laws,
rules and regulations.
As part of our environmental management program, we are in the process
of undertaking environmental remediation at a number of sites. We have budgeted
approximately $665,000 for these efforts during 2002. The actions to be taken
are in accordance with current regulatory requirements and are not the result of
any governmental agency order or directive.
We record a provision or accrual for environmental remediation on a
monthly basis. This provision is included in our depletion and depreciation, and
amounted to approximately $310,000 for the six month period ended June 30, 2002.
EMPLOYEES
As of June 30, 2002, we had 72 employees in our Calgary office and 25
employees at field locations. In addition, as of June 30, 2002, we employed 3
individuals on a full-time contract basis. None of our employees are represented
by a union and we consider our relations with our employees to be good.
LEGAL PROCEEDINGS
We are a party to various legal actions in the ordinary course of
business. In our opinion, none of these actions, either individually or in the
aggregate, will have a material adverse effect on our financial condition or
operating results.
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MANAGEMENT
The following table sets forth the name and position held of each of
our directors and executive officers:
NAME OF DIRECTOR OR OFFICER AGE POSITION HELD ADDRESS
- ----------------------------- ------- ------------------------------- ------------------------
Mel F. Belich, Q.C......... 54 Director, Chairman Calgary, Alberta, Canada
Irvine J. Koop, P. Eng.... 56 Director Calgary, Alberta, Canada
Jeffrey T. Smith, P. Geol. 54 Director Calgary, Alberta, Canada
John W. Preston............ 55 Director Calgary, Alberta, Canada
Ernest G. Sapieha, C.A..... 51 Director, President and Calgary, Alberta, Canada
Chief Executive Officer of
the Corporation
Norman G. Knecht, C.A...... 58 Vice-President, Finance and Calgary, Alberta, Canada
Chief Financial Officer of
the Corporation
Murray J. Stodalka, P. Eng 41 Vice-President, Engineering Calgary, Alberta, Canada
and Operations of
the Corporation
Kim N. Davies, P.Geoph..... 46 Vice-President, Exploration Calgary, Alberta, Canada
of the Corporation
Tim G. Millar, LLB......... 55 Corporate Secretary of the Calgary, Alberta, Canada
Corporation
MEL F. BELICH, Q.C. has been one of our directors since 1993 and was
appointed Chairman of our board of directors in 2001. Mr. Belich graduated from
the University of Calgary in 1970 with a Bachelor of Arts degree. He obtained
his law degree from the University of Dalhousie in 1974. In 1999, Mr. Belich
completed the Harvard University Executive Management Program. Prior to 1994,
Mr. Belich was a senior partner in the law firm of Milner Fenerty (now Fraser
Milner Casgrain LLP), where he held a series of senior management and counsel
positions during his 20 years with that firm. He was appointed Queen's Counsel
in 1996. Mr. Belich is currently Group Vice President-- International, Enbridge
Inc., a position he has held since September 1, 2000. He has also been Chairman
of Enbridge International Inc. and Chairman of Enbridge Technology Inc. since
May 1, 1999. Mr. Belich is also a director of numerous Enbridge affiliates,
including Enbridge Pipelines (Athabasca) Inc., Enbridge Consumers Energy Inc.,
and Enbridge Services Inc. Prior to his current assignment, Mr. Belich was
Senior Vice President responsible for Enbridge's International and Corporate Law
groups. Mr. Belich is a member of the Institute of Americas, the Calgary,
Alberta, Canadian and International Bar Associations, and is a member of a
number of senior legal counsel associations, labour and transportation law
associations in Canada and the United States.
IRVINE J. KOOP, P. ENG. has been one of our directors since 1996. Mr.
Koop graduated from the University of Manitoba in 1968 with a Bachelor of
Science degree in mechanical engineering. He completed the Wharton Business
School Program from the University of Pennsylvania in 1991. From November 1999
until his retirement in April 2001, Mr. Koop was Executive Vice-President and
President and Chief Executive Officer, Pipelines and Midstream, Westcoast Energy
Inc. (an energy products and services company). Prior thereto, from 1996 to
1999, he was President, Pipeline and Field Services Division of Westcoast Energy
Inc. Prior to 1996, Mr. Koop has served in various engineering and senior
management positions in several major resource and energy companies. Mr. Koop is
also a director of NAL Energy (a conventional oil and gas company), and a
director and past chair of the Canadian Energy Research Institute. Mr. Koop is a
member of the Association of Petroleum Engineers, Geologists, Geophysicists of
Alberta, and the Canadian Institute of Mining and Minerals.
JEFFREY T. SMITH, P. GEOL. has been one of our directors since 1999.
Mr. Smith graduated from the University of Ottawa in 1970 with a Bachelor of
Science in Geology (with Honors). Mr. Smith has been an independent businessman
since 1997. Before that time, Mr. Smith was Chief Operating Officer of Northstar
Energy Corporation from 1995 to 1997. Prior thereto, Mr. Smith held numerous
senior management positions with Northstar. Mr. Smith is an independent
businessman and is currently a director of Seque Energy Corp. (a private crude
oil and gas company), Rosetta Exploration (a public crude oil and gas
exploration company), and Provident Energy Trust (a public crude oil and gas
royalty trust) and Resolute Energy Corp. (a private crude oil and gas company).
Mr. Smith is a member of the Association of Petroleum Engineers, Geologists,
Geophysicists of Alberta, and the Canadian Society of Petroleum Geologists.
JOHN W. PRESTON has been one of our directors since 1993. Mr. Preston
graduated from Centennial College in Toronto, Ontario in 1969, with a business
degree in marketing. Mr. Preston is an Account Executive with Sun Microsystems
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of Canada Inc. (a computer company), a position he has held since 1992. Prior
thereto, Mr. Preston held equivalent management positions at AT&T Canada, AES
Data Inc. Canada and IBM Canada.
ERNEST G. SAPIEHA, C.A. has been President and Chief Executive Officer
of Compton since our incorporation in 1992. Mr. Sapieha has more than 20 years
of experience in the petroleum industry. He graduated from the University of
Saskatchewan in 1974 with a Bachelor of Commerce degree and received his
Chartered Accountant designation in 1976. Since then, Mr. Sapieha has had a
broad range of experience, serving in various senior positions with major
accounting firms and large energy and resource companies with publicly trading
shares. In 1986, Mr. Sapieha became a managing director of Petroleum Capital
Corporation, a corporation involved in the formation, investment, financing and
management of public crude oil and natural gas companies, drilling funds, and
joint ventures, including Central Explorers Inc. and Triumph Energy Corporation.
In 1992, Mr. Sapieha founded the Compton Resource Corporation 1992/1993 Oil and
Gas Investment Fund. In 1993, Mr. Sapieha founded Compton Petroleum Corporation.
NORMAN G. KNECHT, C.A. was appointed our Vice-President, Finance and
Chief Financial Officer in 1997. Mr. Knecht has more than 25 years of experience
in public accounting. Mr. Knecht graduated from the University of Alberta in
1969 with a Bachelor of Education degree and received his Chartered Accountant
designation in 1972. Mr. Knecht worked and served as a partner in national
accounting firms until 1982 when he joined Doane Raymond as a general audit
partner. He continued in this capacity, primarily serving junior public
corporations in the resource industries, until joining us in November 1997.
MURRAY J. STODALKA, P.ENG. was appointed our Vice-President,
Engineering and Operations in 1996. Mr. Stodalka has more than 19 years of
experience in the crude oil and natural gas industry. He graduated from the
University of Saskatchewan in 1982 with a Bachelor of Science degree in
mechanical engineering and was subsequently employed in various senior
engineering positions by major Canadian and United States resource companies.
From 1993 to 1996, Mr. Stodalka was a Senior Production and Exploitation
Engineer for Pennzoil Canada Inc. Mr. Stodalka joined us in 1996.
KIM N. DAVIES, P. GEOPH. was appointed Vice-President, Exploration of
Compton in 1996. Ms. Davies has more than 20 years of experience in the crude
oil and natural gas industry. She graduated from the University of Calgary in
1980 with a Bachelor of Science degree in physics. Ms. Davies was employed from
1981 to 1992 in various geophysical positions by Petro-Canada, where she gained
experience in both international and domestic exploration and development. For
the period between 1993 to 1996, Ms. Davies was employed with Pennzoil Canada
Inc. as Senior Geophysicist and value creation team leader. Ms. Davies joined us
in 1996.
TIM G. MILLAR, LLB. was appointed the Corporate Secretary of Compton in
1996. Mr. Millar graduated from the University of Alberta in 1967 with a
Bachelor of Arts degree with a major in history and a minor in economics. Mr.
Millar then received his law degree from the University of Alberta in 1970. Mr.
Millar is a senior partner of the Fraser Milner Casgrain LLP law firm and is
currently the manager of Fraser Milner Casgrain LLP's Commercial Practice
Section. Mr. Millar has been with Fraser Milner Casgrain LLP (or its
predecessors) since 1970. His expertise is in the commercial area of resources
law and he practices principally in the area of oil and gas law, including
matters involving acquisitions and dispositions of oil and gas assets. Mr.
Millar currently serves as a director of Hallmark Tubulars Ltd. Mr. Millar is a
member of the Law Society of Alberta, the Calgary Bar Association, the Natural
Resources Subsection of the Canadian Bar Association and the Petroleum Joint
Venture Association.
COMPENSATION OF EXECUTIVE OFFICERS
The following table sets forth the compensation for our Chief Executive
Officer and each of our three other most highly compensated officers (measured
by base salary and bonus) for the financial years ended December 31, 1999, 2000
and 2001.
LONG TERM COMPENSATION
ANNUAL COMPENSATION AWARDS
-------------------------------- -----------------------------
NAME AND PRINCIPAL POSITION YEAR SALARY BONUS SECURITIES UNDER OPTIONS
GRANTED
($) ($) (#)
- -------------------------------- -------- ---------------- ------------ ------------------------------
Ernest G. Sapieha 2001 295,000 150,000 60,000
President and CEO 2000 225,000 80,000 100,000
1999 175,000 80,000 150,000
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LONG TERM COMPENSATION
ANNUAL COMPENSATION AWARDS
-------------------------------- -----------------------------
NAME AND PRINCIPAL POSITION YEAR SALARY BONUS SECURITIES UNDER OPTIONS
GRANTED
($) ($) (#)
- -------------------------------- -------- ---------------- ------------ ------------------------------
Norman G. Knecht 2001 195,000 95,000 30,000
Vice-President, Finance and 2000 170,000 50,000 50,000
Chief Financial Officer 1999 140,000 50,000 50,000
Murray J. Stodalka 2001 195,000 95,000 30,000
Vice-President, 2000 170,000 50,000 50,000
Engineering and Operations 1999 140,000 50,000 50,000
Kim N. Davies 2001 185,000 85,000 30,000
Vice-President, Exploration 2000 160,000 40,000 50,000
1999 140,000 50,000 50,000
COMPENSATION OF DIRECTORS
During the 2001 fiscal year, each of our directors, excluding Ernest G.
Sapieha who is also an officer of Compton, received an annual fee of $25,000 as
compensation for acting as a director and attendance at board meetings.
Additionally, each of the directors, excluding Ernest G. Sapieha received a fee
of $1,000 per meeting for attendance at Board meetings to an aggregate annual
maximum of $20,000. The Chairman of the Board of our Company receives an annual
fee of $20,000 as compensation for acting as Chairman of the Board. Each
chairman of the three committees of the board receives an additional annual fee
of $7,500 as compensation for acting as the chairman of the committee.
Additionally, each of the directors, excluding Ernest G. Sapieha, received
options during our 2001 fiscal year to acquire 25,000 common shares at $3.83 per
share as compensation for acting as a director.
STOCK OPTION PLAN
Our stock option plan provides that options will be granted to our
directors, officers, employees and consultants and for such number of common
shares as the board determines in its discretion, at an exercise price equal to
the closing price of the common shares on the TSE on the trading day immediately
preceding the date on which the option is granted. The board may determine the
manner, time and rate of exercise of an option. Options granted under the stock
option plan, subject to limited exceptions, must be exercised while the optionee
remains employed as a director, officer, employee or consultant. The options are
not transferable or assignable. The number of options granted reflects
competitive practice and is based on the market value of the common shares on
the date of the grant. As of June 30, 2002, there were 14,500,000 common shares
reserved for issuance under the plan. As of June 30, 2002, there were options
outstanding to purchase 9,910,954 common shares.
The total number of common shares reserved for issuance to any one
person under the plan must not exceed 5% of our outstanding common shares on a
non-diluted basis. Furthermore, the aggregate number of common shares reserved
for issuance under options granted to our directors, officers, 10% shareholders
and each of their affiliates and associates, may not exceed 10% of our
outstanding common shares (on a non-diluted basis). The issuance of common
shares to our directors, officers, 10% shareholders and each of their affiliates
and associates under the plan and any other share compensation arrangements,
within a one year period, may not exceed 10% of our outstanding common shares
(on a non-diluted basis), and the issuance of common shares to any one officer,
director, 10% shareholder or their affiliates and associates under the plan and
any other share compensation arrangements, within a one year period, may not
exceed 5% of our outstanding common shares (on a non-diluted basis).
OPTION GRANTS DURING THE MOST RECENTLY COMPLETED FINANCIAL YEAR
The following table sets forth the options granted to our directors,
the Chief Executive Officer and our three other most highly compensated officers
for our most recently completed fiscal year.
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MARKET VALUE OF
SECURITY
% OF TOTAL UNDERLYING
OPTIONS OPTIONS EXERCISE OPTIONS ON DATE
GRANTED(1) GRANTED DURING PRICE OF GRANT
NAME (#) YEAR ($/SECURITY) ($/SECURITY) EXPIRY DATE
- --------------------- ------------ ---------------- ------------ ------------------ -----------------
Mel F. Belich....... 25,000 0.6 3.83 3.83 July 23, 2011
Irvine J. Koop...... 25,000 0.6 3.83 3.83 July 23, 2011
John W. Preston..... 25,000 0.6 3.83 3.83 July 23, 2011
Jeffrey T. Smith.... 25,000 0.6 3.83 3.83 July 23, 2011
Ernest G. Sapieha... 60,000 1.6 3.83 3.83 July 23, 2011
Norman G. Knecht.... 30,000 0.8 3.83 3.83 July 23, 2011
Murray J. Stodalka.. 30,000 0.8 3.83 3.83 July 23, 2011
Kim N. Davies....... 30,000 0.8 3.83 3.83 July 23, 2011
- ----------
(1) All securities under option are common shares.
AGGREGATED OPTION EXERCISES DURING THE MOST RECENTLY COMPLETED FINANCIAL YEAR
AND FINANCIAL YEAR-END OPTION VALUES
The following table sets forth details of all options exercised by our
Chief Executive Officer and our three other most highly compensated officers in
our most recently completed financial year. The table also details, as at
December 31, 2001, the number of exercisable and unexercisable options that were
unexercised and also the value of such options where they were in-the-money.
VALUE OF UNEXERCISED
UNEXERCISED OPTIONS AT IN-THE-MONEY OPTIONS AT
SECURITIES AGGREGATE FY-END FY-END
ACQUIRED VALUE (#) ($)
ON EXERCISE REALIZED ------------------------------ -----------------------------
NAME (#) ($) EXERCISABLE UNEXERCISABLE EXERCISABLE UNEXERCISABLE
- -------------------------- ------------ ------------ ------------ -------------- ----------- --------------
Ernest G. Sapieha.... -- -- 1,218,333 126,667 4,099,417 164,533
Norman G. Knecht..... -- -- 650,000 80,000 1,880,667 113,933
Murray J. Stodalka... -- -- 650,000 80,000 2,205,667 113,933
Kim N. Davies........ -- -- 650,000 80,000 2,165,667 113,933
As at December 31, 2001, the closing price of our common shares on the
TSE was $4.20 per share.
EMPLOYMENT CONTRACTS
As at December 31, 2001, we had entered into employment contracts with
each of our four executive officers. The contracts provide for compensation to
the executives for loss of office in the event of change of control of Compton,
as defined in those contracts. Such compensation is the aggregate of twice the
executive's current salary and benefits and twice the amount of the executive's
last bonus, if any.
Our stock option plan provides that in the event an executive ceases to
be employed by us, for any reason (excluding termination for cause, death or
disability) the executive can exercise their options within 30 days of such
termination. In the event of termination for cause, the executive's options
expire immediately upon delivery of the notice of termination. In the event of
disability or death, an executive's options expire one year after cessation of
employment.
RELATED PARTY TRANSACTIONS
Murray J. Stodalka, our Vice-President, Engineering and Operations, is
currently indebted to us in the amount of $150,000 arising from an interest-free
loan made to him in 1996 for the purpose of purchasing 300,000 common shares.
The loan is repayable on demand or on the date on which he ceases to be employed
by us, whichever is earlier. Mr. Stodalka has pledged the shares acquired with
the loan as security for the indebtedness and we have agreed that his liability
in respect of the loans will be limited to the pledged shares. The amount
outstanding with respect to this loan on September 1, 2002 was $150,000.
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SECURITY OWNERSHIP OF BENEFICIAL OWNERS AND MANAGEMENT
The following table contains information provided to us by our
shareholders, or contained in our share ownership records, with respect to
beneficial ownership of our common shares as of September 1, 2002:
o each named executive officer;
o each director; and
o all directors and executive officers as a group.
Each person has sole voting and investment power with respect to the
shares listed.
SHARES BENEFICIALLY
OWNED
-------------------------
NAME NUMBER %
- ----------------------------------------------- ------------ ---------
Mel F. Belich, Q.C........................ 1,814,616 1.60
Irvine J. Koop, P. Eng................... 459,000 0.40
John W. Preston........................... 2,030,246 1.80
Ernest G. Sapieha, C.A.................... 6,684,861 5.90
Jeffrey T. Smith, P. Geol................ 36,000 0.03
Norman G. Knecht, C.A..................... 39,850 0.03
Murray J. Stodalka, P. Eng............... 391,068 0.34
Kim N. Davies, P.Geoph.................... 252,726 0.22
------------ ---------
All directors and executive officers as a
group (8 persons)...................... 11,708,367 10.32
============ =========
PRINCIPAL SHAREHOLDERS
To our knowledge, the only persons who beneficially own, directly or
indirectly, or exercise control or direction over more than 5% of our issued and
outstanding common shares are Mr. Ernest G. Sapieha, who owns 5.90% of our
outstanding common shares and Centennial Energy Partners L.L.C. ("Centennial")
of 900 Third Avenue, New York, New York, U.S.A., which itself and through
Centennial Energy Partners, L.P., Tercentennial Energy Partners L.P.,
Quadrennial Partners L.P., Xandu Partners and Pumpkin Foundation owns 11,795,400
Common Shares, representing approximately 10.40% of our outstanding common
shares Mr. Peter Seldin, the principal of Centennial, has voting and investment
decision-making power at Centennial.
STOCK OPTION GRANTS TO DIRECTORS
The following table provides information relating to stock options held
by our directors as of June 30, 2002.
NUMBER OF
COMMON SHARES
UNDERLYING EXERCISE
NAME OPTIONS GRANTED DATE OF GRANT PRICE EXPIRATION DATE
- ---------------------- ----------------- ----------------------- ----------- -------------------
Mel F. Belich..... 500,000 September 13, 1996 $0.60 September 13, 2006
35,000 September 28, 1998 1.45 September 28, 2008
50,000 June 29, 1999 1.83 June 29, 2009
50,000 August 22, 2000 2.30 August 22, 2010
25,000 July 23, 2001 3.83 July 23, 2011
25,000 June 4, 2002 4.10 June 4, 2012
Irvine J. Koop.... 450,000 January 6, 1997 $0.80 January 6, 2007
35,000 September 28, 1998 1.45 September 28, 2008
50,000 June 29, 1999 1.83 June 29, 2009
50,000 August 22, 2000 2.30 August 22, 2010
25,000 July 23, 2001 3.83 July 23, 2011
25,000 June 4, 2002 4.10 June 4, 2012
Jeffrey T. Smith.. 200,000 June 29, 1999 $1.83 June 29, 2009
50,000 August 22, 2000 2.30 August 22, 2010
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NUMBER OF
COMMON SHARES
UNDERLYING EXERCISE
NAME OPTIONS GRANTED DATE OF GRANT PRICE EXPIRATION DATE
- ---------------------- ----------------- ----------------------- ----------- -------------------
25,000 July 23, 2001 3.83 July 23, 2011
25,000 June 4, 2002 4.10 June 4, 2012
John W. Preston... 500,000 September 13, 1996 $0.60 September 13, 2006
35,000 September 28, 1998 1.45 September 28, 2008
50,000 June 29, 1999 1.83 June 29, 2009
50,000 August 22, 2000 2.30 August 22, 2010
25,000 July 23, 2001 3.83 July 23, 2011
25,000 June 4, 2002 4.10 June 4, 2012
Ernest G. Sapieha. 1,000,000 September 13, 1996 $0.60 September 13, 2006
35,000 September 28, 1998 1.45 September 28, 2008
50,000 June 29, 1999 1.83 June 29, 2009
100,000 June 29, 1999 1.83 June 29, 2009
50,000 August 22, 2000 2.30 August 22, 2010
50,000 August 22, 2000 2.30 August 22, 2010
60,000 July 23, 2001 3.83 July 23, 2011
60,000 June 4, 2002 4.10 June 4, 2012
DESCRIPTION OF OTHER INDEBTEDNESS
SENIOR CREDIT FACILITIES
PRODUCTION FACILITY. We currently have a $158.0 million extendible
revolving credit facility with a Canadian chartered bank, as administrative
agent and arranger, and a syndicate of lenders. The production facility is
available for general corporate purposes. The revolving period may be extended
by the lenders on a year to year basis and, if not otherwise extended, the
production facility will mature on July 9, 2003 at which time this facility must
be repaid in full.
WORKING CAPITAL FACILITY. We currently have a $10 million extendible
revolving working capital facility with a Canadian chartered bank. The working
capital facility is available for ongoing working capital purposes. The
revolving period may be extended by the lender on a year to year basis and, if
not otherwise extended, the working capital facility will mature on July 9,
2003, at which time this facility must be repaid in full. As of June 30, 2002,
we had no outstanding borrowings under this facility.
Under our senior credit facilities, the amount of our permitted
borrowing base was initially established by and is periodically redetermined by
the lenders. Permitted borrowings under our senior credit facilities are not to
exceed the amount of our net borrowing base which is based upon our borrowing
base, less a deduction on account of debt service on the notes. Upon completion
of the initial offering, we repaid substantially all amounts outstanding under
our senior credit facilities, and the amount of our net borrowing base under
these facilities was reduced to, and currently still is, $168.0 million, subject
to the conditions contained therein. Amounts outstanding under our senior credit
facilities will bear interest at a rate dependent on the type of accommodation
provided, including prime rate or U.S. base rate loans, bankers' acceptances or
LIBOR loans, plus a margin based on our ratio of total consolidated debt to cash
flow, that is currently set at 0.625%, 1.625% and 1.625%, respectively.
Our senior credit facilities have customary covenants including, but
not limited to, covenants with respect to:
o creating additional liens or security interests;
o transferring or selling of assets;
o entering into mergers and amalgamations;
o incurring additional debt;
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o providing additional guarantees; and
o entering into swaps and derivatives contracts.
Our senior credit facilities are secured by a fixed and floating charge
and security interest over all of our undertakings, properties and assets and by
a pledge of all shares we hold in 867791 Alberta Ltd. and Hornet Energy Ltd.,
and are guaranteed by each of our borrowing base subsidiaries and 899776 Alberta
Ltd. As of the date of this prospectus, our borrowing base subsidiaries are
867791 Alberta Ltd., Compton Petroleum and Hornet Energy Ltd. The guarantees are
secured by a fixed and floating charge and security interest on all of the
undertakings, properties and assets of each of our borrowing base subsidiaries
and a floating charge and security interest on all of the undertakings,
properties and assets of 899776 Alberta Ltd.
Under the terms of our senior credit facilities, if we experience a
change of control, the lenders may elect to terminate their commitments and our
ability to request additional funding, and the lenders may declare all amounts
outstanding to be immediately due and payable. Unless the lenders under the
senior credit facilities agree to waive their rights to be immediately repaid,
we will be obligated to immediately repay all principal then outstanding, and
all accrued and unpaid interest and fees, if any, under the senior credit
facilities.
The foregoing is a summary of the material provisions of our senior
credit facilities. It does not restate the agreements in their entirety. We urge
you to read the credit agreements, because they, and not this description, set
forth the full terms of the senior credit facilities. The credit agreements were
filed as exhibits to our Registration Statement, of which this prospectus forms
a part. See "Where You Can Find More Information".
THE EXCHANGE OFFER
TERMS OF THE EXCHANGE OFFER
We are offering to exchange our exchange notes for a like aggregate
principal amount of our initial notes.
The exchange notes that we propose to issue in this exchange offer will
be substantially identical to our initial notes except that, unlike our initial
notes, the exchange notes will have no transfer restrictions or registration
rights. You should read the description of the exchange notes in the section in
this prospectus entitled "Description of the Exchange Notes".
We reserve the right in our sole discretion to purchase or make offers
for any initial notes that remain outstanding following the expiration or
termination of this exchange offer and, to the extent permitted by applicable
law, to purchase initial notes in the open market or privately negotiated
transactions, one or more additional tender or exchange offers or otherwise. The
terms and prices of these purchases or offers could differ significantly from
the terms of this exchange offer. In addition, nothing in this exchange offer
will prevent us from exercising our right to discharge our obligations on the
initial notes by depositing certain securities with the trustee and otherwise.
EXPIRATION DATE; EXTENSIONS; AMENDMENTS; TERMINATION
This exchange offer will expire at 5:00 p.m., New York City time, on ,
2002, unless we extend it in our reasonable discretion. The expiration date of
this exchange offer will be at least 20 business days after the commencement of
the exchange offer in accordance with Rule 14e-l(a) under the SECURITIES
EXCHANGE ACT OF 1934 (the "Exchange Act").
We expressly reserve the right to delay acceptance of any initial
notes, extend or terminate this exchange offer and not accept any initial notes
that we have not previously accepted if any of the conditions described below
under "--Conditions to the Exchange Offer" have not been satisfied or waived by
us. We will notify the exchange agent of any extension by oral notice promptly
confirmed in writing or by written notice. We will also notify the holders of
the initial notes by mailing an announcement or by a press release or other
public announcement before 9:00 a.m., New York City time, on the next business
day after the previously scheduled expiration date unless applicable laws
require us to do otherwise.
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We also expressly reserve the right to amend the terms of this exchange
offer in any manner. If we make any material change, we will promptly disclose
this change in a manner reasonably calculated to inform the holders of our
initial notes of the change including providing public announcement or giving
oral or written notice to these holders. A material change in the terms of this
exchange offer could include a change in the timing of the exchange offer, a
change in the exchange agent and other similar changes in the terms of this
exchange offer. If we make any material change to this exchange offer, we will
disclose this change by means of a post-effective amendment to the registration
statement which includes this prospectus and will distribute an amended or
supplemented prospectus to each registered holder of initial notes. In addition,
we will extend this exchange offer for an additional five to ten business days
as required by the Exchange Act, depending on the significance of the amendment,
if the exchange offer would otherwise expire during that period. We will
promptly notify the exchange agent by oral notice, promptly confirmed in
writing, or written notice of any delay in acceptance, extension, termination or
amendment of this exchange offer.
PROCEDURES FOR TENDERING INITIAL NOTES
PROPER EXECUTION AND DELIVERY OF LETTERS OF TRANSMITTAL
To tender your initial notes in this exchange offer, you must use one
of the three alternative procedures described below:
(1) BOOK-ENTRY DELIVERY PROCEDURE: Send a timely confirmation of a
book-entry transfer of your initial notes, if this procedure
is available, into the exchange agent's account at The
Depository Trust Company in accordance with the procedures for
book-entry transfer described under "-- Book-Entry Delivery
Procedure" below, on or before 5:00 p.m., New York City time,
on the expiration date.
(2) REGULAR DELIVERY PROCEDURE: Complete, sign and date the letter
of transmittal, or a facsimile of the letter of transmittal.
Have the signatures on the letter of transmittal guaranteed if
required by the letter of transmittal. Mail or otherwise
deliver the letter of transmittal or the facsimile together
with the certificates representing the initial notes being
tendered and any other required documents to the exchange
agent on or before 5:00 p.m., New York City time, on the
expiration date.
(3) GUARANTEED DELIVERY PROCEDURE: If time will not permit you to
complete your tender by using the procedures described in (1)
or (2) above before the expiration date and this procedure is
available, comply with the guaranteed delivery procedures
described under "--Guaranteed Delivery Procedure" below.
The method of delivery of the initial notes, the letter of transmittal
and all other required documents is at your election and risk. Instead of
delivery by mail, we recommend that you use an overnight or hand-delivery
service. If you choose the mail, we recommend that you use registered mail,
properly insured, with return receipt requested. IN ALL CASES, YOU SHOULD ALLOW
SUFFICIENT TIME TO ASSURE TIMELY DELIVERY. You should not send any letters of
transmittal or initial notes to us. You must deliver all documents to the
exchange agent at its address provided below. You may also request your broker,
dealer, commercial bank, trust company or nominee to tender your initial notes
on your behalf.
Only a holder of initial notes may tender initial notes in this
exchange offer. A holder is any person in whose name initial notes are
registered on our books or any other person who has obtained a properly
completed bond power from the registered holder.
If you are the beneficial owner of initial notes that are registered in
the name of a broker, dealer, commercial bank, trust company or other nominee
and you wish to tender your notes, you must contact that registered holder
promptly and instruct that registered holder to tender your notes on your
behalf. If you wish to tender your initial notes on your own behalf, you must,
before completing and executing the letter of transmittal and delivering your
initial notes, either make appropriate arrangements to register the ownership of
these notes in your name or obtain a properly completed bond power from the
registered holder. The transfer of registered ownership may take considerable
time.
You must have any signatures on a letter of transmittal or a notice of
withdrawal guaranteed by:
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(1) a member firm of a registered national securities exchange or
of the National Association of Securities Dealers, Inc.;
(2) a commercial bank or trust company having an office or
correspondent in the United States; or
(3) an eligible guarantor institution within the meaning of Rule
17Ad-15 under the Exchange Act, UNLESS the initial notes are
tendered:
(a) by a registered holder or by a participant in
The Depository Trust Company whose name appears on a
security position listing as the owner, who has not
completed the box entitled "Special Issuance
Instructions" or "Special Delivery Instructions" on
the letter of transmittal and only if the exchange
notes are being issued directly to this registered
holder or deposited into this participant's account
at The Depository Trust Company; or
(b) for the account of a member firm of a registered
national securities exchange or of the National
Association of Securities Dealers, Inc., a commercial
bank or trust company having an office or
correspondent in the United States or an eligible
guarantor institution within the meaning of Rule
l7Ad-l5 under the Exchange Act.
If the letter of transmittal or any bond powers are signed by:
(1) the recordholder(s) of the initial notes tendered: the
signature must correspond with the name(s) written on the face
of the initial notes without alteration, enlargement or any
change whatsoever.
(2) a participant in The Depository Trust Company: the signature
must correspond with the name as it appears on the security
position listing as the holder of the initial notes.
(3) a person other than the registered holder of any initial
notes: these initial notes must be endorsed or accompanied by
bond powers and a proxy that authorize this person to tender
the initial notes on behalf of the registered holder, in
satisfactory form to us as determined in our sole discretion,
in each case, as the name of the registered holder or holders
appears on the initial notes.
(4) trustees, executors, administrators, guardians,
attorneys-in-fact, officers of corporations or others acting
in a fiduciary or representative capacity: these persons
should so indicate when signing. Unless waived by us, evidence
satisfactory to us of their authority to so act must also be
submitted with the letter of transmittal.
To effectively tender notes through The Depository Trust Company, the
financial institution that is a participant in The Depository Trust Company will
electronically transmit its acceptance through the Automatic Tender Offer
Program. The Depository Trust Company will then edit and verify the acceptance
and send an agent's message to the exchange agent for its acceptance. An agent's
message is a message transmitted by The Depository Trust Company to the exchange
agent stating that The Depository Trust Company has received an express
acknowledgment from the participant in The Depository Trust Company tendering
the notes that this participant has received and agrees to be bound by the terms
of the letter of transmittal, and that we may enforce this agreement against
this participant.
BOOK-ENTRY DELIVERY PROCEDURE
Any financial institution that is a participant in The Depository Trust
Company's systems may make book-entry deliveries of initial notes by causing The
Depository Trust Company to transfer these initial notes into the exchange
agent's account at The Depository Trust Company in accordance with The
Depository Trust Company's procedures for transfer. To effectively tender notes
through The Depository Trust Company, the financial institution that is a
participant in The Depository Trust Company will electronically transmit its
acceptance through the Automatic Tender Offer Program. The Depository Trust
Company will then edit and verify the acceptance and send an agent's message to
the exchange agent for its acceptance. An agent's message is a message
transmitted by The Depository Trust Company to the exchange agent stating that
The Depository Trust Company has received an express acknowledgment from the
participant in The Depository Trust Company tendering the initial notes that
this participation has received and agrees to be bound by the terms of the
letter of
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transmittal, and that we may enforce this agreement against this
participant. The exchange agent will make a request to establish an account for
the initial notes at The Depository Trust Company for purposes of the exchange
offer within two business days after the date of this prospectus.
A delivery of initial notes through a book-entry transfer into the
exchange agent's account at The Depository Trust Company will only be effective
if an agent's message or the letter of transmittal or a facsimile of the letter
of transmittal with any required signature guarantees and any other required
documents is transmitted to and received by the exchange agent at the address
indicated below under "-- Exchange Agent" on or before the expiration date
unless the guaranteed delivery procedures described below are complied with.
DELIVERY OF DOCUMENTS TO THE DEPOSITORY TRUST COMPANY DOES NOT CONSTITUTE
DELIVERY TO THE EXCHANGE AGENT.
GUARANTEED DELIVERY PROCEDURE
If you are a registered holder of initial notes and desire to tender
your notes, and (1) these notes are not immediately available, (2) time will not
permit your notes or other required documents to reach the exchange agent before
the expiration date or (3) the procedures for book-entry transfer cannot be
completed on a timely basis and an agent's message delivered, you may still
tender in this exchange offer if:
(1) you tender through a member firm of a registered national
securities exchange or of the National Association of
Securities Dealers, Inc., a commercial bank or trust company
having an office or correspondent in the United States, or an
eligible guarantor institution within the meaning of Rule
17Ad-15 under the Exchange Act;
(2) on or before the expiration date, the exchange agent receives
a properly completed and duly executed letter of transmittal
or facsimile of the letter of transmittal, and a notice of
guaranteed delivery, substantially in the form provided by us,
with your name and address as holder of the initial notes and
the amount of notes tendered, stating that the tender is being
made by that letter and notice and guaranteeing that within
three New York Stock Exchange trading days after the
expiration date the certificates for all the initial notes
tendered, in proper form for transfer, or a book-entry
confirmation with an agent's message, as the case may be, and
any other documents required by the letter of transmittal will
be deposited by the eligible institution with the exchange
agent; and
(3) the certificates for all your tendered initial notes in proper
form for transfer or a book-entry confirmation as the case may
be, and all other documents required by the letter of
transmittal are received by the exchange agent within three
New York Stock Exchange trading days after the expiration
date.
ACCEPTANCE OF INITIAL NOTES FOR EXCHANGE; DELIVERY OF EXCHANGE NOTES
Your tender of initial notes will constitute an agreement between you
and us governed by the terms and conditions provided in this prospectus and in
the related letter of transmittal.
We will be deemed to have received your tender as of the date when your
duly signed letter of transmittal accompanied by your initial notes tendered, or
a timely confirmation of a book-entry transfer of these notes into the exchange
agent's account at The Depository Trust Company with an agent's message, or a
notice of guaranteed delivery from an eligible institution is received by the
exchange agent.
All questions as to the validity, form, eligibility, including time of
receipt, acceptance and withdrawal of tenders will be determined by us in our
sole discretion. Our determination will be final and binding.
We reserve the absolute right to reject any and all initial notes not
properly tendered or any initial notes which, if accepted, would, in our opinion
or our counsel's opinion, be unlawful. We also reserve the absolute right to
waive any conditions of this exchange offer or irregularities or defects in
tender as to particular notes. Our interpretation of the terms and conditions of
this exchange offer, including the instructions in the letter of transmittal,
will be final and binding on all parties. Unless waived, any defects or
irregularities in connection with tenders of initial notes must be cured within
such time as we shall determine. We, the exchange agent or any other person will
be under no duty to give notification of defects or
-55-
irregularities with respect to tenders of initial notes. We and the exchange
agent or any other person will incur no liability for any failure to give
notification of these defects or irregularities. Tenders of initial notes will
not be deemed to have been made until such irregularities have been cured or
waived. The exchange agent will return without cost to their holders any initial
notes that are not properly tendered and as to which the defects or
irregularities have not been cured or waived as promptly as practicable
following the expiration date.
If all the conditions to the exchange offer are satisfied or waived on
the expiration date, we will accept all initial notes properly tendered and will
issue the exchange notes promptly thereafter. Please refer to the section of
this prospectus entitled "-- Conditions to the Exchange Offer" below. For
purposes of this exchange offer, initial notes will be deemed to have been
accepted as validly tendered for exchange when, as and if we give oral or
written notice of acceptance to the exchange agent.
We will issue the exchange notes in exchange for the initial notes
tendered pursuant to a notice of guaranteed delivery by an eligible institution
only against delivery to the exchange agent of the letter of transmittal, the
tendered initial notes and any other required documents, or the receipt by the
exchange agent of a timely confirmation of a book-entry transfer of initial
notes into the exchange agent's account at The Depository Trust Company with an
agent's message, in each case, in form satisfactory to us and the exchange
agent.
If any tendered initial notes are not accepted for any reason provided
by the terms and conditions of this exchange offer or if initial notes are
submitted for a greater principal amount than the holder desires to exchange,
the unaccepted or non-exchanged initial notes will be returned without expense
to the tendering holder, or, in the case of initial notes tendered by book-entry
transfer procedures described above, will be credited to an account maintained
with the book-entry transfer facility, as promptly as practicable after
withdrawal, rejection of tender or the expiration or termination of the exchange
offer.
By tendering into this exchange offer, you will irrevocably appoint our
designees as your attorney-in-fact and proxy with full power of substitution and
resubstitution to the full extent of your rights on the notes tendered. This
proxy will be considered coupled with an interest in the tendered notes. This
appointment will be effective only when, and to the extent that we accept your
notes in this exchange offer. All prior proxies on these notes will then be
revoked and you will not be entitled to give any subsequent proxy. Any proxy
that you may give subsequently will not be deemed effective. Our designees will
be empowered to exercise all voting and other rights of the holders as they may
deem proper at any meeting of note holders or otherwise. The initial notes will
be validly tendered only if we are able to exercise full voting rights on the
notes, including voting at any meeting of the note holders, and full rights to
consent to any action taken by the note holders.
WITHDRAWAL OF TENDERS
Except as otherwise provided in this prospectus, you may withdraw
tenders of initial notes at any time before 5:00 p.m., New York City time, on
the expiration date.
For a withdrawal to be effective, you must send a written or facsimile
transmission notice of withdrawal to the exchange agent before 5:00 p.m., New
York City time, on the expiration date at the address provided below under
"--Exchange Agent" and before acceptance of your tendered notes for exchange by
us.
Any notice of withdrawal must:
(1) specify the name of the person having tendered the initial
notes to be withdrawn;
(2) identify the notes to be withdrawn, including, if applicable,
the registration number or numbers and total principal amount
of these notes;
(3) be signed by the person having tendered the initial notes to
be withdrawn in the same manner as the original signature on
the letter of transmittal by which these notes were tendered,
including any required signature guarantees, or be accompanied
by documents of transfer sufficient to permit the trustee for
the initial notes to register the transfer of these notes into
the name of the person having made the original tender and
withdrawing the tender;
-56-
(4) specify the name in which any of these initial notes are to be
registered, if this name is different from that of the person
having tendered the initial notes to be withdrawn; and
(5) if applicable because the initial notes have been tendered
through the book-entry procedure, specify the name and number
of the participant's account at The Depository Trust Company
to be credited, if different than that of the person having
tendered the initial notes to be withdrawn.
We will determine all questions as to the validity, form and
eligibility, including time of receipt, of all notices of withdrawal and our
determination will be final and binding on all parties. Initial notes that are
withdrawn will be deemed not to have been validly tendered for exchange in this
exchange offer.
The exchange agent will return without cost to their holders all
initial notes that have been tendered for exchange and are not exchanged for any
reason, as promptly as practicable after withdrawal, rejection of tender or
expiration or termination of this exchange offer.
You may retender properly withdrawn initial notes in this exchange
offer by following one of the procedures described under "-- Procedures for
Tendering Initial Notes" above at any time on or before the expiration date.
CONDITIONS TO THE EXCHANGE OFFER
We will complete this exchange offer only if:
(1) there is no change in the laws and regulations which, in our
judgment, would reasonably be expected to impair our ability
to proceed with this exchange offer;
(2) there is no change in the current interpretation of the staff
of the Commission which permits resales of the exchange notes;
(3) there is no stop order issued by the Commission or any state
securities authority suspending the effectiveness of the
registration statement which includes this prospectus or the
qualification of the indenture for our exchange notes under
the TRUST INDENTURE ACT OF 1939 and there are no proceedings
initiated or, to our knowledge, threatened for that purpose;
(4) there is no action or proceeding instituted or threatened in
any court or before any governmental agency or body that in
our judgment would reasonably be expected to prohibit, prevent
or otherwise impair our ability to proceed with this exchange
offer; and
(5) we obtain all governmental approvals that we deem in our sole
discretion necessary to complete this exchange offer.
These conditions are for our sole benefit. We may assert any one of
these conditions regardless of the circumstances giving rise to it and may also
waive any one of them, in whole or in part, at any time and from time to time,
if we determine in our reasonable discretion that it has not been satisfied,
subject to applicable law. We will not be deemed to have waived our rights to
assert or waive these conditions if we fail at any time to exercise any of them.
Each of these rights will be deemed an ongoing right which we may assert at any
time and from time to time.
If we determine that we may terminate this exchange offer because any
of these conditions is not satisfied, we may:
(1) refuse to accept and return to their holders any initial notes
that have been tendered;
(2) extend the exchange offer and retain all notes tendered before
the expiration date, subject to the rights of the holders of
these notes to withdraw their tenders; or
-57-
(3) waive any condition that has not been satisfied and accept all
properly tendered notes that have not been withdrawn or
otherwise amend the terms of this exchange offer in any
respect as provided under the section in this prospectus
entitled "-- Expiration Date; Extensions; Amendments;
Termination".
ACCOUNTING TREATMENT
We will record the exchange notes at the same carrying value as the
initial notes as reflected in our accounting records on the date of the
exchange. Accordingly, we will not recognize any gain or loss for accounting
purposes. We will amortize the costs of the exchange offer and the unamortized
expenses related to the issuance of the exchange notes over the term of the
exchange notes.
EXCHANGE AGENT
We have appointed The Bank of Nova Scotia Trust Company of New York as
exchange agent for this exchange offer. You should direct all questions and
requests for assistance on the procedures for tendering and all requests for
additional copies of this prospectus or the letter of transmittal to the
exchange agent as follows:
By mail:
The Bank of Nova Scotia
Trust Company of New York
1 Liberty Plaza
23rd Floor
New York, NY 10006
Attention: Exchanges
By hand/overnight delivery:
Facsimile Transmission: (212) 225-5436
Confirm by Telephone: (212) 225-5427
Attention: Exchanges
FEES AND EXPENSES
We will bear the expenses of soliciting tenders in this exchange offer,
including fees and expenses of the exchange agent and trustee and accounting,
legal, printing and related fees and expenses.
We will not make any payments to brokers, dealers or other persons
soliciting acceptances of this exchange offer. However, we will pay the exchange
agent reasonable and customary fees for its services and will reimburse the
exchange agent for its reasonable out-of-pocket expenses in connection with this
exchange offer. We will also pay brokerage houses and other custodians, nominees
and fiduciaries their reasonable out-of-pocket expenses for forwarding copies of
the prospectus, letters of transmittal and related documents to the beneficial
owners of the initial notes and for handling or forwarding tenders for exchange
to their customers.
We will pay all transfer taxes, if any, applicable to the exchange of
initial notes in accordance with this exchange offer. However, tendering holders
will pay the amount of any transfer taxes, whether imposed on the registered
holder or any other persons, if:
(1) certificates representing exchange notes or initial notes for
principal amounts not tendered or accepted for exchange are to
be delivered to, or are to be registered or issued in the name
of, any person other than the registered holder of the notes
tendered;
(2) tendered initial notes are registered in the name of any
person other than the person signing the letter of
transmittal; or
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(3) a transfer tax is payable for any reason other than the
exchange of the initial notes in this exchange offer.
If you do not submit satisfactory evidence of the payment of any of
these taxes or of any exemption from this payment with the letter of
transmittal, we will bill you directly the amount of these transfer taxes.
YOUR FAILURE TO PARTICIPATE IN THE EXCHANGE OFFER WILL HAVE ADVERSE CONSEQUENCES
The initial notes were not registered under the Securities Act or under
the securities laws of any state and you may not resell them, offer them for
resale or otherwise transfer them unless they are subsequently registered or
resold under an exemption from the registration requirements of the Securities
Act and applicable state securities laws. If you do not exchange your initial
notes for exchange notes in accordance with this exchange offer, or if you do
not properly tender your initial notes in this exchange offer, you will not be
able to resell, offer to resell or otherwise transfer the initial notes unless
they are registered under the Securities Act or unless you resell them, offer to
resell or otherwise transfer them under an exemption from the registration
requirements of, or in a transaction not subject to, the Securities Act. In
addition, you will not necessarily be able to obligate us to register the
initial notes under the Securities Act.
DELIVERY OF PROSPECTUS
Each broker-dealer that receives exchange notes for its own account in
exchange for initial notes, where such initial notes were acquired by such
broker-dealer as a result of market-making activities or other trading
activities, must acknowledge that it will deliver a prospectus in connection
with any resale of such exchange notes. See "Plan of Distribution".
DESCRIPTION OF THE EXCHANGE NOTES
You can find the definitions of terms used in this description under
the subheading "Definitions". In this description, the word "Compton" refers
only to Compton Petroleum Corporation and not to any of its subsidiaries.
Compton will issue the exchange notes under an indenture among itself,
the Guarantors and The Bank of Nova Scotia Trust Company of New York, as
trustee. See "Notice to Investors". The terms of the notes include those stated
in the indenture and those made part of the indenture by reference to the TRUST
INDENTURE ACT OF 1939, as amended.
The following description is a summary of the material provisions of
the indenture. It does not restate the agreement in its entirety. We urge you to
read the indenture because it, and not this description, defines your rights as
holders of the exchange notes. Copies of the indenture are available as set
forth below under "-- Additional Information". Capitalized terms used in this
description but not defined below under "-- Definitions" have the meanings
assigned to them in the indenture. References to "US$" are to United States
dollars and to "Cdn$" are to Canadian dollars.
The registered Holder of a note will be treated as the owner of it for
all purposes. Only registered Holders will have rights under the indenture.
BRIEF DESCRIPTION OF THE EXCHANGE NOTES AND THE GUARANTEES
THE NOTES
The notes:
o are general unsecured obligations of Compton;
o are equal in right of payment to all existing and future
unsecured senior Indebtedness of Compton;
o are senior in right of payment with any permitted future
subordinated Indebtedness of Compton;
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o are unconditionally guaranteed by the Guarantors; and
o are effectively subordinated to all secured Indebtedness of
Compton and the Guarantors, including the Credit Facilities
which are secured by substantially all of the assets of
Compton and the Guarantors.
THE GUARANTEES
The notes are fully and unconditionally guaranteed on an unsecured
senior basis by all of Compton's Subsidiaries and will be guaranteed by all of
Compton's future Restricted Subsidiaries. Should a future Restricted Subsidiary
of ours guarantee the notes, this guarantee will constitute a new issuance of
securities under the Securities Act, and will require us to register such
issuance under the Securities Act or effect such issuance under an exemption
from registration.
Each guarantee of the notes:
o is a general senior unsecured obligation of the Guarantor;
o is equal in right of payment to all existing and future
unsecured senior Indebtedness of that Guarantor; and
o is senior in right of payment with any permitted future senior
subordinated Indebtedness of that Guarantor.
As of the date of the indenture, all of our subsidiaries will be
"Restricted Subsidiaries". However, under the circumstances described below
under the subheading "-- Certain Covenants -- Designation of Restricted and
Unrestricted Subsidiaries", we will be permitted to designate certain of our
subsidiaries as "Unrestricted Subsidiaries". Our Unrestricted Subsidiaries will
not be subject to many of the restrictive covenants in the indenture. Our
Unrestricted Subsidiaries will not guarantee the notes.
PRINCIPAL, MATURITY AND INTEREST
Compton may issue an unlimited principal amount of notes under the
indenture and up to US$165 million will be issued in the exchange notes. Compton
may issue additional notes from time to time after this exchange offer. Any
offering of additional notes is subject to the covenant described below under
the caption "-- Certain Covenants --Incurrence of Indebtedness and Issuance of
Preferred Stock". The initial notes, the exchange notes and any additional notes
subsequently issued under the indenture will be treated as a single class for
all purposes under the indenture, including, without limitation, waivers,
amendments, redemptions and offers to purchase. Compton will issue notes in
denominations of US$1,000 and integral multiples of US$1,000. The notes will
mature on May 15, 2009.
Interest on the notes will accrue at the rate of 9.90% per annum and
will be payable semi-annually in arrears on May 15 and November 15, commencing
on November 15, 2002. Compton will make each interest payment to the Holders of
record on the immediately preceding May 1 and November 1.
Interest on the notes will accrue from the date of original issuance
or, if interest has already been paid, from the date it was most recently paid.
Interest will be computed on the basis of a 360-day year comprised of twelve
30-day months.
METHODS OF RECEIVING PAYMENTS ON THE NOTES
If a Holder has given wire transfer instructions to Compton in writing,
Compton will pay all principal, interest and premium and Additional Interest, if
any, on that Holder's notes in accordance with those instructions. All other
payments on notes will be made at the office or agency of the paying agent and
registrar within the City and State of New York unless Compton elects to make
interest payments by check mailed to the Holders at their address set forth in
the register of Holders.
PAYING AGENT AND REGISTRAR FOR THE NOTES
The trustee will initially act as paying agent and registrar. Compton
may change the paying agent or registrar without prior notice to the Holders of
the notes, and Compton or any of its Subsidiaries may act as paying agent or
registrar.
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TRANSFER AND EXCHANGE
A Holder may transfer or exchange notes in accordance with the
indenture. The registrar and the trustee may require a Holder, among other
things, to furnish appropriate endorsements and transfer documents in connection
with a transfer of notes. Holders will be required to pay all taxes due on
transfer. Compton is not required to transfer or exchange any note selected for
redemption. Also, Compton is not required to transfer or exchange any note for a
period of 15 days before a selection of notes to be redeemed.
SUBSIDIARY GUARANTEES
The notes will be guaranteed by each of Compton's current and future
Restricted Subsidiaries. Should a future Restricted Subsidiary of ours guarantee
the notes, this guarantee will constitute a new issuance of securities under the
Securities Act, and will require us to register such issuance under the
Securities Act or effect such issuance under an exemption from registration. The
Subsidiary Guarantees will be joint and several unsecured obligations of the
Guarantors. The obligations of each Guarantor under its Subsidiary Guarantee
will be limited as necessary to prevent that Subsidiary Guarantee from
constituting a fraudulent conveyance under applicable law. See "Risk Factors --
Federal and State statutes allow courts, under specific circumstances, to void
guarantees and require noteholders to return payments received from guarantors".
A Guarantor may not sell or otherwise dispose of all or substantially
all of its assets to, or consolidate, amalgamate or merge with or into (whether
or not such Guarantor is the surviving Person (a person being any individual,
corporation, partnership, joint venture, association, joint stock company,
trust, unincorporated organization, limited liability company, government,
government body or agency, or other entity), another Person, other than Compton
or another Guarantor, unless:
(1) immediately after giving effect to that transaction, no
Default or Event of Default exists; and
(2) either:
(a) the Person acquiring the property in any such sale or
disposition or the Person formed by or surviving any
such consolidation or merger assumes all the
obligations of that Guarantor under the indenture,
its Subsidiary Guarantee and the registration rights
agreement pursuant to a supplemental indenture
reasonably satisfactory to the trustee; or
(b) the Net Proceeds of such sale or other disposition
are applied in accordance with the applicable
provisions of the indenture.
The Subsidiary Guarantee of a Guarantor will be released:
(1) in connection with any sale or other disposition of all or
substantially all of the assets of that Guarantor (including
by way of merger or consolidation) to a Person that is not
(either before or after giving effect to such transaction) a
Subsidiary of Compton, if the sale or other disposition
complies with the "Asset Sale" provisions of the indenture; or
(2) in connection with any sale of all of the Capital Stock of a
Guarantor to a Person that is not (either before or after
giving effect to such transaction) a Subsidiary of Compton, if
the sale complies with the "Asset Sale" provisions of the
indenture; or
(3) if Compton designates any Restricted Subsidiary that is a
Guarantor as an Unrestricted Subsidiary in accordance with the
applicable provisions of the indenture.
See "--Repurchase at the Option of Holders-- Asset Sales".
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OPTIONAL REDEMPTION
At any time prior to May 15, 2005, Compton may on any one or more
occasions redeem up to 35% of the aggregate principal amount of notes issued
under the indenture at a redemption price of 109.90% of the principal amount,
plus accrued and unpaid interest and Additional Interest, if any, to the
redemption date, with the net cash proceeds of one or more Equity Offerings;
PROVIDED that:
(1) at least 65% of the aggregate principal amount of notes issued
under the indenture remains outstanding immediately after the
occurrence of such redemption (excluding notes held by Compton
and its Subsidiaries); and
(2) the redemption occurs within 60 days of the date of the
closing of such Equity Offering.
If Compton becomes obligated to pay any Additional Amounts as a result
of a change in the laws or regulations of Canada or any Canadian taxing
authority, or a change in any official position regarding the application or
interpretation thereof, which is publicly announced or becomes effective on or
after the date of the indenture, Compton may, at its option, redeem the notes,
in whole but not in part, upon not less than 30 nor more than 60 days' notice,
at a redemption price equal to 100% of the principal amount thereof, plus
accrued and unpaid interest and Additional Interest, if any, to the redemption
date.
Except pursuant to the preceding paragraphs, the notes will not be
redeemable at Compton's option prior to May 15, 2006.
After May 15, 2006, Compton may redeem all or a part of the notes upon
not less than 30 nor more than 60 days' notice, at the redemption prices
(expressed as percentages of principal amount) set forth below plus accrued and
unpaid interest and Additional Interest, if any, on the notes redeemed, to the
applicable redemption date, if redeemed during the twelve-month period beginning
on May 15 of the years indicated below:
YEAR PERCENTAGE
---------------------------- ----------------
2006.................... 104.950%
2007.................... 102.475%
2008 and thereafter..... 100.000%
MANDATORY REDEMPTION
Compton is not required to make mandatory redemption payments with
respect to the notes.
REPURCHASE AT THE OPTION OF HOLDERS
CHANGE OF CONTROL
If Compton does not make a Change of Control Offer in accordance with
the terms of the indenture, each Holder of notes will have the right to require
Compton to repurchase all or any part (equal to US$1,000 or an integral multiple
of US$1,000) of that Holder's notes pursuant to a Change of Control Offer on the
terms set forth in the indenture. In the Change of Control Offer, Compton will
offer a Change of Control Payment in cash equal to 101% of the aggregate
principal amount of notes repurchased plus accrued and unpaid interest and
Additional Interest, if any, on the notes repurchased, to the date of purchase.
Within 30 days following any Change of Control, Compton will mail a notice to
each Holder describing the transaction or transactions that constitute the
Change of Control and offering to repurchase notes on the Change of Control
Payment Date specified in the notice, which date will be no earlier than 30 days
and no later than 60 days from the date such notice is mailed, pursuant to the
procedures required by the indenture and described in such notice. Compton will
comply with the requirements of Rule 14e-1 under the Exchange Act and any other
securities laws and regulations thereunder to the extent those laws and
regulations are applicable in connection with the repurchase of the notes as a
result of a Change of Control. To the extent that the provisions of any
securities laws or regulations conflict with the Change of Control provisions of
the indenture, Compton will comply with the applicable securities laws and
regulations and will not be deemed to have breached its obligations under the
Change of Control provisions of the indenture by virtue of such conflict.
Compton's ability to make a Change of Control Offer is currently restricted by
the terms of the Credit Agreement.
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On the Change of Control Payment Date, Compton or its designated agent
will, to the extent lawful:
(1) accept for payment all notes or portions of notes properly
tendered pursuant to the Change of Control Offer;
(2) deposit with the paying agent an amount equal to the Change of
Control Payment in respect of all notes or portions of notes
properly tendered; and
(3) deliver or cause to be delivered to the trustee the
notes accepted together with an officers' certificate stating
the aggregate principal amount of notes or portions of notes
being purchased by Compton.
The paying agent will promptly mail to each Holder of notes properly
tendered the Change of Control Payment for such notes, and the trustee will
promptly authenticate and mail (or cause to be transferred by book entry) to
each Holder a new note equal in principal amount to any unpurchased portion of
the notes surrendered, if any; PROVIDED that each new note will be in a
principal amount of US$1,000 or an integral multiple of US$1,000.
Compton will publicly announce the results of the Change of Control
Offer on or as soon as practicable after the Change of Control Payment Date.
The provisions described above that require Compton to make a Change of
Control Offer following a Change of Control will be applicable whether or not
any other provisions of the indenture are applicable. Except as described above
with respect to a Change of Control, the indenture does not contain provisions
that permit the Holders of the notes to require that Compton repurchase or
redeem the notes in the event of a takeover, recapitalization or similar
transaction.
Compton will not be required to make a Change of Control Offer upon a
Change of Control if a third party makes the Change of Control Offer in the
manner, at the times and otherwise in compliance with the requirements set forth
in the indenture applicable to a Change of Control Offer made by Compton and
purchases all notes properly tendered and not withdrawn under the Change of
Control Offer.
The definition of Change of Control includes a phrase relating to the
direct or indirect sale, lease, transfer, conveyance or other disposition of
"all or substantially all" of the properties or assets of Compton and its
Restricted Subsidiaries taken as a whole. Although there is a limited body of
case law interpreting the phrase "substantially all", there is no precise
established definition of the phrase under applicable law. Accordingly, the
ability of a Holder of notes to require Compton to repurchase its notes as a
result of a sale, lease, transfer, conveyance or other disposition of less than
all of the assets of Compton and its Restricted Subsidiaries taken as a whole to
another Person or group may be uncertain.
ASSET SALES
Compton will not, and will not permit any of its Restricted
Subsidiaries to, consummate an Asset Sale unless:
(1) Compton (or the Restricted Subsidiary, as the case may be)
receives consideration at the time of the Asset Sale at least
equal to the fair market value of the assets or Equity
Interests issued or sold or otherwise disposed of;
(2) the fair market value is set forth in an officers' certificate
delivered to the trustee; and
(3) at least 75% of the consideration received in the Asset Sale
by Compton or such Restricted Subsidiary is in the form of
cash or Permitted Assets. For purposes of this provision, each
of the following will be deemed to be cash:
(a) any liabilities, as shown on Compton's or such
Restricted Subsidiary's most recent balance sheet, of
Compton or any Restricted Subsidiary (other than
contingent liabilities and liabilities that are by
their terms subordinated to the notes or any
Subsidiary Guarantee) that are assumed by the
transferee of any such assets pursuant to a customary
novation agreement that releases Compton or such
Restricted Subsidiary from further liability; and
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(b) any securities, notes or other obligations received
by Compton or any such Restricted Subsidiary from
such transferee that are contemporaneously, subject
to ordinary settlement periods, converted by Compton
or such Restricted Subsidiary into cash, to the
extent of the cash received in that conversion.
Within 365 days after the receipt of any Net Proceeds from an Asset
Sale, Compton or the applicable Restricted Subsidiary may apply those Net
Proceeds:
(1) to repay or prepay Indebtedness and Obligations meaning any
other principal, interest, penalties, fees, indemnifications,
reimbursements, damages, and other liabilities payable under
the documentation governing the Indenture that are not
subordinated to the Notes;
(2) to acquire all or substantially all of the assets of, or a
majority of the Voting Stock of, another Oil and Gas Business;
(3) to make a capital expenditure; or
(4) to acquire other long-term assets that are used or useful in
the Oil and Gas Business.
Pending the final application of any Net Proceeds, Compton may temporarily
reduce revolving credit borrowings or otherwise invest the Net Proceeds in any
manner that is not prohibited by the indenture.
Any Net Proceeds from Asset Sales that are not applied or invested as
provided in the preceding paragraph will constitute "Excess Proceeds". When the
aggregate amount of Excess Proceeds exceeds US$10.0 million, Compton will make
an Asset Sale Offer to all Holders of notes and all holders of other
Indebtedness that is PARI PASSU (i.e., that ranks equally and ratably) with the
notes containing provisions similar to those set forth in the indenture with
respect to offers to purchase or redeem with the proceeds of sales of assets to
purchase the maximum principal amount of notes and such other PARI PASSU
Indebtedness that may be purchased out of the Excess Proceeds. The offer price
in any Asset Sale Offer will be equal to 100% of principal amount plus accrued
and unpaid interest and Additional Interest, if any, to the date of purchase,
and will be payable in cash. If any Excess Proceeds remain after consummation of
an Asset Sale Offer, Compton may use those Excess Proceeds for any purpose not
otherwise prohibited by the indenture. If the aggregate principal amount of
notes and other PARI PASSU Indebtedness tendered into such Asset Sale Offer
exceeds the amount of Excess Proceeds, the trustee will select the notes and
such other PARI PASSU Indebtedness to be purchased on a pro rata basis. Upon
completion of each Asset Sale Offer, the amount of Excess Proceeds will be reset
at zero. Compton's ability to make an Asset Sale Offer is currently restricted
by the terms of the Credit Agreement.
Compton will comply with the requirements of Rule 14e-1 under the
Exchange Act and any other securities laws and regulations thereunder to the
extent those laws and regulations are applicable in connection with each
repurchase of notes pursuant to an Asset Sale Offer. To the extent that the
provisions of any securities laws or regulations conflict with the Asset Sale
provisions of the indenture, Compton will comply with the applicable securities
laws and regulations and will not be deemed to have breached its obligations
under the Asset Sale provisions of the indenture by virtue of such conflict.
The agreements governing Compton's other Indebtedness (including the
Credit Agreement) contain prohibitions of certain events, including events that
would constitute a Change of Control or an Asset Sale. In addition, the exercise
by the Holders of notes of their right to require Compton to repurchase the
notes upon a Change of Control or an Asset Sale could cause a default under
these other agreements, even if the Change of Control or Asset Sale itself does
not, due to the financial effect of such repurchase on Compton. Finally,
Compton's ability to pay cash to the Holders of notes upon a repurchase may be
limited by Compton's then existing financial resources.
SELECTION AND NOTICE
If less than all of the notes are to be redeemed at any time, the
trustee will select notes for redemption as follows:
(1) if the notes are listed on any national securities exchange,
in compliance with the requirements of the principal national
securities exchange on which the notes are listed; or
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(2) if the notes are not listed on any national securities
exchange, on a pro rata basis, by lot or by such method as the
trustee deems fair and appropriate.
No notes of US$1,000 or less can be redeemed in part. Notices of
redemption will be mailed by first class mail at least 30 but not more than 60
days before the redemption date to each Holder of notes to be redeemed at its
registered address, except that redemption notices may be mailed more than 60
days prior to a redemption date if the notice is issued in connection with a
defeasance of the notes or a satisfaction and discharge of the indenture.
Notices of redemption may not be conditional.
If any note is to be redeemed in part only, the notice of redemption
that relates to that note will state the portion of the principal amount of that
note that is to be redeemed. A new note in principal amount equal to the
unredeemed portion of the original note will be issued in the name of the Holder
of notes upon cancellation of the original note. Notes called for redemption
become due on the date fixed for redemption. On and after the redemption date,
interest ceases to accrue on notes or portions of them called for redemption.
COVENANTS
Set forth below are covenants that are contained in the indenture.
RESTRICTED PAYMENTS
Compton will not, and will not permit any of its Restricted
Subsidiaries to, directly or indirectly:
(1) declare or pay any dividend or make any other payment or
distribution on account of Compton's Equity Interests
(including, without limitation, any payment on account of such
Equity Interests in connection with any merger or
consolidation involving Compton) or to the direct or indirect
holders of Compton's Equity Interests in their capacity as
such (other than dividends or distributions payable in Equity
Interests (other than Disqualified Stock) of Compton);
(2) purchase, retract, redeem or otherwise acquire or retire for
value (including, without limitation, in connection with any
merger or consolidation involving Compton), in whole or in
part, any Equity Interests of Compton;
(3) make any payment on or with respect to, or purchase, redeem,
defease or otherwise acquire or retire for value any
Indebtedness that is subordinated to the notes or the
Subsidiary Guarantees, except a payment of interest or
principal at the Stated Maturity thereof; or
(4) make any Restricted Investment;
(all such payments and other actions set forth in these clauses (1)
through (4) above being collectively referred to as "Restricted
Payments"),
unless, at the time of and after giving effect to such Restricted Payment:
(1) no Default or Event of Default has occurred and is continuing
or would occur as a consequence of such Restricted Payment;
and
(2) Compton would, at the time of such Restricted Payment and
after giving pro forma effect thereto as if such Restricted
Payment had been made at the beginning of the applicable
four-quarter period, have been permitted to incur at least
US$1.00 of additional Indebtedness pursuant to the Fixed
Charge Coverage Ratio test set forth in the first paragraph of
the covenant described below under the caption "-- Incurrence
of Indebtedness and Issuance of Preferred Stock"; and
(3) such Restricted Payment, together with the aggregate amount of
all other Restricted Payments made by Compton and its
Restricted Subsidiaries after the date of the indenture
(excluding Restricted Payments
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permitted by clauses (2), (3) and (4) of the next succeeding
paragraph), is less than the sum, without duplication, of:
(a) 50% of the Consolidated Net Income of Compton for the
period (taken as one accounting period) from the
beginning of the first fiscal quarter during which
the indenture is dated to the end of Compton's most
recently ended fiscal quarter for which internal
financial statements are available at the time of
such Restricted Payment (or, if such Consolidated Net
Income for such period is a loss, less 100% of such
loss), PLUS
(b) 100% of the aggregate net proceeds received by
Compton (including the fair market value of any Oil
and Gas Business acquired in a stock transaction)
since the date of the indenture as a contribution to
its common equity capital or from the issue or sale
of Equity Interests of Compton (other than
Disqualified Stock) or from the issue or sale of
convertible or exchangeable Disqualified Stock or
convertible or exchangeable debt securities of
Compton that have been converted into or exchanged
for such Equity Interests (other than Equity
Interests (or Disqualified Stock or debt securities)
sold to a Subsidiary of Compton), PLUS
(c) to the extent that any Restricted Investment that was
made after the date of the indenture is sold for cash
or otherwise liquidated or repaid for cash, the
lesser of (i) the cash return of capital with respect
to such Restricted Investment (less the cost of
disposition, if any) and (ii) the initial amount of
such Restricted Investment.
So long as no Default has occurred and is continuing or would be caused thereby,
the preceding provisions will not prohibit:
(1) the payment of any dividend within 60 days after the date of
declaration of the dividend, if at the date of declaration the
dividend payment would have complied with the provisions of
the indenture;
(2) the redemption, repurchase, retirement, defeasance or other
acquisition of any subordinated Indebtedness of Compton or any
Guarantor or of any Equity Interests of Compton in exchange
for, or out of the net cash proceeds of the substantially
concurrent sale (other than to a Restricted Subsidiary of
Compton) of, Equity Interests of Compton (other than
Disqualified Stock); PROVIDED that the amount of any such net
cash proceeds that are utilized for any such redemption,
repurchase, retirement, defeasance or other acquisition will
be excluded from clause (3) (b) of the preceding paragraph;
(3) the defeasance, redemption, repurchase or other acquisition of
subordinated Indebtedness of Compton or any Guarantor with the
net cash proceeds from an incurrence of Permitted Refinancing
Indebtedness;
(4) the repurchase, redemption or other acquisition or retirement
for value of any Equity Interests of Compton or any Restricted
Subsidiary of Compton held by any member of Compton's (or any
of its Restricted Subsidiaries') management, directors or
employees pursuant to any management equity subscription
agreement, stock option agreement or similar agreement or upon
the death, disability or termination of employment of such
directors, officers or employees; PROVIDED that the aggregate
price paid for all such repurchased, redeemed, acquired or
retired Equity Interests may not exceed US$1.0 million in any
calendar year or US$5.0 million in the aggregate since the
date of the indenture;
(5) payment of ordinary dividends on Disqualified Stock issued
after the date of the indenture pursuant to the terms thereof
as in effect on the date of issuance; PROVIDED, that such
Disqualified Stock was issued in accordance with the covenant
described below under the caption "-- Incurrence of
Indebtedness and Issuance of Preferred Stock"; and
(6) the making of other Restricted Payments in an aggregate amount
not to exceed US$15.0 million since the date of the indenture.
The amount of all Restricted Payments (other than cash) will be the
fair market value on the date of the Restricted Payment of the asset(s) or
securities proposed to be transferred or issued by Compton or such Restricted
Subsidiary, as the
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case may be, pursuant to the Restricted Payment. The fair market value of any
assets or securities that are required to be valued by this covenant will be
determined by the Board of Directors whose resolution with respect thereto will
be delivered to the trustee.
INCURRENCE OF INDEBTEDNESS AND ISSUANCE OF PREFERRED STOCK
Compton will not, and will not permit any of its Restricted
Subsidiaries to, directly or indirectly, create, incur, issue, assume, guarantee
or otherwise become directly or indirectly liable, contingently or otherwise,
with respect to (in any such case, "incur") any Indebtedness (including Acquired
Debt), and Compton will not issue any Disqualified Stock and will not permit any
of its Restricted Subsidiaries to issue any shares of preferred stock; PROVIDED,
HOWEVER, that Compton may incur Indebtedness (including Acquired Debt) or issue
Disqualified Stock, and the Guarantors may incur Indebtedness or issue preferred
stock, if the Fixed Charge Coverage Ratio for Compton's most recently ended four
full fiscal quarters for which internal financial statements are available
immediately preceding the date on which such additional Indebtedness is incurred
or such Disqualified Stock is issued would have been at least 2.5 to 1,
determined on a pro forma basis (including a pro forma application of the net
proceeds therefrom), as if the additional Indebtedness had been incurred or the
preferred stock or Disqualified Stock had been issued, as the case may be, at
the beginning of such four-quarter period.
The first paragraph of this covenant will not prohibit the incurrence
of any of the following items of Indebtedness (collectively, "Permitted Debt"):
(1) the incurrence by Compton and its Restricted Subsidiaries of
additional Indebtedness and letters of credit under Credit
Facilities in an aggregate principal amount at any one time
outstanding under this clause (1) (with letters of credit
being deemed to have a principal amount equal to the maximum
potential liability of Compton and its Restricted Subsidiaries
thereunder) not to exceed the greater of:
(a) Cdn$175.0 million, LESS the aggregate amount of all
Net Proceeds of Asset Sales that have been applied by
Compton or any of its Restricted Subsidiaries since
the date of the indenture to permanently repay any
term Indebtedness under a Credit Facility pursuant to
the covenant described above under the caption "--
Repurchase at the Option of Holders-- Asset Sales"
and LESS the aggregate amount of all commitment
reductions with respect to any revolving credit
borrowings under a Credit Facility that have been
made by Compton or any of its Restricted Subsidiaries
since the date of the indenture as a result of the
application of Net Proceeds of Asset Sales pursuant
to the covenant described above under the caption
"--Repurchase at Option of Holders-- Asset Sales";
and
(b) Cdn$95.0 million plus 15% of Adjusted Consolidated
Net Tangible Assets as of the last day of the fiscal
quarter for which internal financial statements are
available and immediately preceding the date on which
such additional Indebtedness is incurred;
(2) Existing Indebtedness;
(3) the incurrence by Compton and the Guarantors of Indebtedness
represented by the notes and the related Subsidiary Guarantees
to be issued on the date of the indenture and the Exchange
Notes and the related Subsidiary Guarantees to be issued
pursuant to the registration rights agreement;
(4) the incurrence by Compton or any of the Guarantors of
Indebtedness and Obligations represented by Capital Lease
Obligations, mortgage financings or purchase money
obligations, in each case, incurred for the purpose of
financing all or any part of the purchase price or cost of
construction or improvement of property, plant or equipment
used in the business of Compton or such Guarantor, in an
aggregate principal amount, including all Permitted
Refinancing Indebtedness incurred to refund, refinance or
replace any Indebtedness incurred pursuant to this clause (4),
not to exceed US$10.0 million at any time outstanding;
(5) the incurrence by Compton or any of its Restricted
Subsidiaries of Permitted Refinancing Indebtedness in exchange
for, or the net proceeds of which are used to refund,
refinance or replace Indebtedness (other than
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intercompany Indebtedness) that was permitted by the indenture
to be incurred under the first paragraph of this covenant or
clauses (2), (3), (4), (5) or (13) of this paragraph;
(6) the incurrence by Compton or any of its Restricted
Subsidiaries of intercompany Indebtedness between or among
Compton and any of its Restricted Subsidiaries; PROVIDED,
HOWEVER, that:
(a) if Compton or any Guarantor is the obligor on such
Indebtedness, such Indebtedness must be unsecured;
and
(b) (i) any subsequent issuance or transfer of Equity
Interests that results in any such Indebtedness being
held by a Person other than Compton or a Restricted
Subsidiary of Compton and (ii) any sale or other
transfer of any such Indebtedness to a Person that is
not either Compton or a Restricted Subsidiary of
Compton; will be deemed, in each case, to constitute
an incurrence of such Indebtedness by Compton or such
Restricted Subsidiary, as the case may be, that was
not permitted by this clause (6);
(7) the incurrence by Compton or any of the Guarantors of Hedging
Obligations, PROVIDED that such Hedging Obligations were
incurred in the ordinary course of business and not for
speculative purposes;
(8) the guarantee by Compton or any of the Guarantors of
Indebtedness of Compton or a Restricted Subsidiary of Compton
that was permitted to be incurred by another provision of this
covenant;
(9) the accrual of interest, the accretion or amortization of
original issue discount, the payment of interest on any
Indebtedness in the form of additional Indebtedness with the
same terms, and the payment of dividends on Disqualified Stock
in the form of additional shares of the same class of
Disqualified Stock will not be deemed to be an incurrence of
Indebtedness or an issuance of Disqualified Stock for purposes
of this covenant; PROVIDED, in each such case, that the amount
thereof is included in Fixed Charges of Compton as accrued;
(10) the incurrence by Compton or any Guarantor of Indebtedness and
Obligations under Oil and Gas Hedging Contracts, PROVIDED that
such Contracts were entered into in the ordinary course of
business and not for speculative purposes;
(11) production imbalances arising in the ordinary course of
business;
(12) Indebtedness and Obligations in connection with one or more
standby letters of credit, Guarantees, performance or surety
bond or other reimbursement obligations, in each case, issued
in the ordinary course of business and not in connection with
the borrowing of money or the obtaining of an advance or
credit (other than advances or credit for goods and services
in the ordinary course of business and on terms and conditions
that are customary in the Oil and Gas Business, and other than
the extension of credit represented by such letter of credit,
Guarantee or performance or surety bond itself); and
(13) the incurrence by Compton or any of its Restricted
Subsidiaries of additional Indebtedness in an aggregate
principal amount (or accreted value, as applicable) at any
time outstanding, including all Permitted Refinancing
Indebtedness incurred to refund, refinance or replace any
Indebtedness incurred pursuant to this clause (13), not to
exceed US$25.0 million.
For purposes of determining compliance with this "Incurrence of
Indebtedness and Issuance of Preferred Stock" covenant, in the event that an
item of proposed Indebtedness meets the criteria of more than one of the
categories of Permitted Debt described in clauses (1) through (13) above, or is
entitled to be incurred pursuant to the first paragraph of this covenant,
Compton will be permitted to classify, or later reclassify, such item of
Indebtedness in whole or in part in any manner that complies with this covenant,
including by allocation to more than one other type of Indebtedness.
Indebtedness under Credit Facilities outstanding on the date on which notes are
first issued and authenticated under the indenture will be deemed to have been
incurred on such date in reliance on the exception provided by clause (1) of the
definition of Permitted Debt.
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Compton will not incur any additional Indebtedness (including Permitted
Debt) that is contractually subordinated in right of payment to any other
Indebtedness of Compton unless such additional Indebtedness is also
contractually subordinated in right of payment to the notes on substantially
identical terms; PROVIDED, HOWEVER, that no Indebtedness of Compton will be
deemed to be contractually subordinated in right of payment to any other
Indebtedness of Compton solely by virtue of being unsecured.
LIENS
Compton will not, and will not permit any of its Restricted
Subsidiaries to, directly or indirectly, create, incur, assume or otherwise
cause or suffer to exist or become effective any Lien of any kind securing
Indebtedness or trade payables (other than Permitted Liens) upon or with respect
to any of their property or assets, now owned or hereafter acquired, unless all
payments due under the indenture and the notes are secured on an equal and
ratable basis with the obligations so secured until such time as such
obligations are no longer secured by a Lien.
DIVIDEND AND OTHER PAYMENT RESTRICTIONS AFFECTING RESTRICTED SUBSIDIARIES
Compton will not, and will not permit any of its Restricted
Subsidiaries to, directly or indirectly, create or permit to exist or become
effective any consensual encumbrance or restriction on the ability of any
Restricted Subsidiary to:
(1) pay dividends or make any other distributions on its Capital
Stock to Compton or any of its Restricted Subsidiaries, or
with respect to any other interest or participation in, or
measured by, its profits, or pay any indebtedness owed to
Compton or any of its Restricted Subsidiaries;
(2) make loans or advances to Compton or any of its Restricted
Subsidiaries; or
(3) transfer any of its properties or assets to Compton or any of
its Restricted Subsidiaries.
However, the preceding restrictions will not apply to encumbrances or
restrictions existing under or by reason of:
(1) agreements governing Existing Indebtedness or Credit
Facilities as in effect or which come into effect on the date
of the indenture and any amendments, modifications,
restatements, renewals, increases, supplements, refundings,
replacements or refinancings of those agreements, PROVIDED
that the amendments, modifications, restatements, renewals,
increases, supplements, refundings, replacements or
refinancings are not materially less favourable to holders of
notes, as determined by Compton's Board of Directors in their
reasonable and good faith judgment;
(2) the indenture, the notes and the Subsidiary Guarantees;
(3) applicable law;
(4) any instrument governing Indebtedness or Capital Stock of a
Person acquired by Compton or any of its Restricted
Subsidiaries as in effect at the time of such acquisition
(except to the extent such Indebtedness or Capital Stock was
incurred in connection with or in contemplation of such
acquisition), which encumbrance or restriction is not
applicable to any Person, or the properties or assets of any
Person, other than the Person, or the property or assets of
the Person, so acquired, PROVIDED that, in the case of
Indebtedness, such Indebtedness was permitted by the terms of
the indenture to be incurred;
(5) customary non-assignment provisions in contracts entered into
in the ordinary course of business and consistent with past
practice;
(6) purchase money obligations for property acquired in the
ordinary course of business that impose restrictions on that
property of the nature described in clause (3) of the
preceding paragraph;
(7) any agreement for the sale or other disposition of a
Restricted Subsidiary that restricts distributions by that
Restricted Subsidiary pending its sale or other disposition;
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(8) Permitted Refinancing Indebtedness, PROVIDED that the
restrictions contained in the agreements governing such
Permitted Refinancing Indebtedness are not materially less
favourable to holders of notes, as determined by Compton's
Board of Directors in their reasonable and good faith
judgment;
(9) agreements existing on the date of the indenture;
(10) Liens securing Indebtedness otherwise permitted to be incurred
under the provisions of the covenant described above under the
caption "-- Liens" that limit the right of the debtor to
dispose of the assets subject to such Liens;
(11) provisions with respect to the disposition or distribution of
assets or property in joint venture agreements, assets sale
agreements, stock sale agreements and other similar agreements
entered into in the ordinary course of business; and
(12) restrictions on cash or other deposits or net worth imposed by
customers under contracts entered into in the ordinary course
of business.
MERGER, CONSOLIDATION OR SALE OF ASSETS
Compton may not, directly or indirectly: (1) amalgamate, consolidate or
merge with or into another Person (whether or not Compton is the surviving
corporation); or (2) sell, assign, transfer, convey or otherwise dispose of all
or substantially all of the properties or assets of Compton and its Restricted
Subsidiaries taken as a whole, in one or more related transactions, to another
Person; unless:
(1) either: (a) Compton is the surviving corporation; or (b) the
Person formed by or surviving any such consolidation or merger
(if other than Compton) or to which such sale, assignment,
transfer, conveyance or other disposition has been made is a
corporation organized or existing under the laws of Canada or
any province thereof or the United States, any state of the
United States or the District of Columbia;
(2) the Person formed by or surviving any such consolidation or
merger (if other than Compton) or the Person to which such
sale, assignment, transfer, conveyance or other disposition
has been made assumes all the obligations of Compton under the
notes, the indenture and the registration rights agreement
pursuant to agreements reasonably satisfactory to the trustee;
(3) immediately after such transaction no Default or Event of
Default exists; and
(4) Compton or the Person formed by or surviving any such
consolidation or merger (if other than Compton), or to which
such sale, assignment, transfer, conveyance or other
disposition has been made:
(a) will have Consolidated Net Worth immediately
after the transaction equal to or greater than the
Consolidated Net Worth of Compton immediately
preceding the transaction; and
(b) will, on the date of such transaction after
giving pro forma effect thereto and any related
financing transactions as if the same had occurred at
the beginning of the applicable four-quarter period,
be permitted to incur at least US$1.00 of additional
Indebtedness pursuant to the Fixed Charge Coverage
Ratio test set forth in the first paragraph of the
covenant described above under the caption "--
Incurrence of Indebtedness and Issuance of Preferred
Stock"; and
(5) the transactions will not result in Compton or the surviving
corporation being required to make any deduction or
withholding on account of taxes as described below under the
caption "-- Payment of Additional Amounts" that Compton would
not have been required to make had such transactions or series
of transactions not occurred.
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In addition, Compton may not, directly or indirectly, lease all or
substantially all of its properties or assets, in one or more related
transactions, to any other Person. This "Merger, Consolidation or Sale of
Assets" covenant will not apply to a sale, assignment, transfer, conveyance or
other disposition of assets between or among Compton and any of the Guarantors.
TRANSACTIONS WITH AFFILIATES
Compton will not, and will not permit any of its Restricted
Subsidiaries to, make any payment to, or sell, lease, transfer or otherwise
dispose of any of its properties or assets to, or purchase any property or
assets from, or enter into or make or amend any transaction, contract,
agreement, understanding, loan, advance or guarantee with, or for the benefit
of, any Affiliate (each, an "Affiliate Transaction"), unless:
(1) the Affiliate Transaction is on terms that are no less
favorable to Compton or the relevant Restricted Subsidiary
than those that would have been obtained in a comparable
transaction by Compton or such Restricted Subsidiary with an
unrelated Person; and
(2) Compton delivers to the trustee:
(a) with respect to any Affiliate Transaction or series
of related Affiliate Transactions involving aggregate
consideration in excess of US$2.5 million, a
resolution of the Board of Directors set forth in an
officers' certificate certifying that such Affiliate
Transaction complies with this covenant and that such
Affiliate Transaction has been approved by a majority
of the disinterested members of the Board of
Directors; and
(b) with respect to any Affiliate Transaction or series
of related Affiliate Transactions involving aggregate
consideration in excess of US$15.0 million, an
opinion as to the fairness to Compton or the relevant
Restricted Subsidiary of such Affiliate Transaction
from a financial point of view issued by an
accounting, appraisal or investment banking firm of
national standing in Canada or the United States.
The following items will not be deemed to be Affiliate Transactions
and, therefore, will not be subject to the provisions of the prior paragraph:
(1) any employment agreement entered into by Compton or any
of its Restricted Subsidiaries in the ordinary course of
business and consistent with the past practice of Compton or
such Restricted Subsidiary;
(2) transactions between or among Compton and/or its Restricted
Subsidiaries;
(3) transactions with a Person that is an Affiliate of Compton
solely because Compton owns an Equity Interest in, or
controls, such Person;
(4) payment of reasonable and customary compensation or fees to,
or the execution of customary expense reimbursement,
indemnification or similar arrangements with, Compton or any
of its Restricted Subsidiaries or any of their respective
directors and officers in the ordinary course of business;
(5) sales of Equity Interests (other than Disqualified Stock) to
Affiliates of Compton; and
(6) Restricted Payments that are permitted by the provisions of
the indenture described above under the caption "-- Restricted
Payments".
ADDITIONAL SUBSIDIARY GUARANTEES
If Compton or any of its Subsidiaries acquires or creates another
Restricted Subsidiary after the date of the indenture, then that newly acquired
or created Restricted Subsidiary will become a Guarantor and execute a
supplemental indenture providing for a Subsidiary Guarantee and deliver an
opinion of counsel reasonably satisfactory to the trustee that
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such supplemental indenture has been duly authorized, executed and delivered and
constitutes a legal, valid, binding and enforceable obligation, all within ten
Business Days of the date on which it was acquired or created.
DESIGNATION OF RESTRICTED AND UNRESTRICTED SUBSIDIARIES
The Board of Directors of Compton may designate any Restricted
Subsidiary to be an Unrestricted Subsidiary if that designation would not cause
a Default. If a Restricted Subsidiary is designated as an Unrestricted
Subsidiary, the aggregate fair market value of all outstanding Investments owned
by Compton and its Restricted Subsidiaries in the Subsidiary so designated will
be deemed to be an Investment made as of the time of the designation and will
reduce the amount available for Restricted Payments under the first paragraph of
the covenant described above under the caption "-- Restricted Payments" or
Permitted Investments, as determined by Compton. That designation will only be
permitted if the Investment would be permitted at that time and if the
Restricted Subsidiary otherwise meets the definition of an Unrestricted
Subsidiary. The Board of Directors of Compton may redesignate any Unrestricted
Subsidiary to be a Restricted Subsidiary if the redesignation would not cause a
Default.
BUSINESS ACTIVITIES
Compton will not, and will not permit any Restricted Subsidiary to,
engage in any business other than the Oil and Gas Business, except to such
extent as would not be material to Compton and its Restricted Subsidiaries taken
as a whole.
PAYMENTS FOR CONSENT
Compton will not, and will not permit any of its Subsidiaries to,
directly or indirectly, pay or cause to be paid any consideration to or for the
benefit of any Holder of notes for or as an inducement to any consent, waiver or
amendment of any of the terms or provisions of the indenture or the notes unless
such consideration is offered to be paid and is paid to all Holders of the notes
that consent, waive or agree to amend in the time frame set forth in the
solicitation documents relating to such consent, waiver or agreement.
PAYMENT OF ADDITIONAL AMOUNTS
All payments made by Compton or on behalf of Compton with respect to
the notes will be made without withholding or deduction for any taxes imposed by
any Canadian taxing authority, unless required by law or the interpretation or
administration thereof by the relevant taxing authority. If Compton is obligated
to withhold or deduct any amount on account of taxes imposed by any Canadian
taxing authority from any payment made with respect to the notes, Compton will:
(1) make such withholding or deduction;
(2) remit the full amount deducted or withheld to the relevant
government authority in accordance with the applicable law;
(3) pay such additional amounts ("Additional Amounts") as may be
necessary so that the net amount received by each Holder
(including Additional Amounts) after such withholding or
deduction will not be less than the amount the Holder would
have received if such taxes had not been withheld or deducted;
(4) furnish to the trustee for the benefit of the Holders, within
30 days after the date of the payment of any taxes is due, an
official receipt of the relevant government authorities for
all amounts deducted or withheld, or if such receipts are not
obtainable, other evidence of payment by Compton of those
taxes;
(5) indemnify and hold harmless each Holder, other than as
described below, for the amount of:
(a) any taxes (including interest and penalties) paid by
such Holder as a result of payments made on or with
respect thereto, and
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(b) any taxes imposed with respect to any reimbursement
under the preceding bullet or this bullet, but
excluding any such taxes on such Holder's net income;
and
(6) at least 15 days prior to each date on which any Additional
Amounts are payable, deliver to the trustee an officers'
certificate setting forth the calculation of the Additional
Amounts to be paid and such other information as the trustee
may request to enable the trustee to pay such Additional
Amounts to Holders on the payment date.
Notwithstanding the foregoing, Compton will not pay Additional Amounts
to a Holder in respect of a beneficial owner of a note:
o with which Compton does not deal at arm's length (within the
meaning of the Income Tax Act (Canada)) at the time of making
such payment, or
o which is subject to such taxes by reason of its being
connected with Canada or any province or territory thereof
otherwise than by the mere acquisition, holding or disposition
of notes or the receipt of payments thereunder.
Any reference in the indenture to the payment of principal, premium, if
any, interest, Additional Interest, Change of Control or Asset Sale purchase
price, redemption price or any other amount payable under or with respect to any
note, will be deemed to include the payment of Additional Amounts to the extent
that, in such context, Additional Amounts are, were or would be payable in
respect thereof. Compton's obligation to make payments of Additional Amounts
will survive any termination of the indenture or the defeasance of any rights
thereunder. For a discussion of the exemption from Canadian withholding taxes
applicable to payments under or with respect to the notes, see "-- Material
Income Tax Considerations -- Canadian Federal Income Tax Considerations".
REPORTS
Whether or not required by the Commission, so long as any notes are
outstanding, Compton will furnish to the Holders of notes, within the time
periods specified in the Commission's rules and regulations or cause the trustee
to furnish to the Holders:
(1) (a) all annual financial information that would be
required to be contained in a filing with the
Commission on Forms 20-F or 40-F, as applicable (or
any successor forms), containing the information
required therein (or required in such successor
form); and
(b) for the first three quarters of each year, all
quarterly financial information that would be
required to be contained in a filing with the
Commission on Form 6-K (or any successor form)
containing in all material respects the financial
information that would be required to be included in
a filing on Form 10-Q (or any such successor form)
that, regardless of applicable requirements shall, at
a minimum, contain the information that would be
required to be provided in quarterly reports under
the laws of Canada or any province thereof to
securityholders of a company with securities listed
on the Toronto Stock Exchange, whether or not the
Company has any of its securities so listed,
in each case including a "Management's Discussion and Analysis
of Financial Condition and Results of Operations" and, with
respect to the annual information only, a report on the annual
financial statements by Compton's certified independent
accountants; and
(2) all current reports that would otherwise be required to be
filed with the Commission on Form 6-K if Compton were required
to file such reports.
If Compton has designated any of its Subsidiaries as Unrestricted
Subsidiaries, then the quarterly and annual financial information required by
the preceding paragraph will include a reasonably detailed presentation, either
on the face of the financial statements or in the footnotes thereto, and in
Management's Discussion and Analysis of Financial Condition
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and Results of Operations, of the financial condition and results of operations
of Compton and its Restricted Subsidiaries excluding the Unrestricted
Subsidiaries.
In addition, all such financial information and reports will contain
all financial information required to be provided in quarterly reports under the
laws of Canada or any province thereof to security holders of a company with
securities listed on the Toronto Stock Exchange. In addition, following the
consummation of the exchange offer, whether or not required by the Commission,
Compton will file a copy of all of the information and reports referred to in
clauses (1) and (2) above with the Commission for public availability within the
time periods specified in the Commission's rules and regulations (unless the
Commission will not accept such a filing).
EVENTS OF DEFAULT AND REMEDIES
Each of the following is an Event of Default:
(1) default for 30 days in the payment when due of interest on, or
Additional Interest with respect to the notes;
(2) default in payment when due of the principal of, or premium,
if any, on the notes;
(3) failure by Compton or any of its Restricted Subsidiaries to
comply with the provisions described under the captions "--
Repurchase at the Option of Holders -- Change of Control", "--
Repurchase at the Option of Holders -- Asset Sales", or "--
Certain Covenants -- Merger, Consolidation or Sale of Assets";
(4) failure by Compton or any of its Restricted Subsidiaries to
comply with any of the other agreements in the indenture for
60 days after written notice has been given to Compton by the
trustee or to Compton and the trustee by Holders of at least
25% of the outstanding principal amount of the notes;
(5) default under any other mortgage, indenture or instrument
under which there may be issued or by which there may be
secured or evidenced any Indebtedness for money borrowed by
Compton or any of its Restricted Subsidiaries (or the payment
of which is guaranteed by Compton or any of its Restricted
Subsidiaries) whether such Indebtedness or guarantee now
exists, or is created after the date of the indenture, if that
default:
(a) is caused by a failure to pay principal of, or
interest or premium, if any, on such Indebtedness
prior to the expiration of the applicable grace or
cure period provided in such Indebtedness on the date
of such default (a "Payment Default"); or
(b) results in the acceleration of such Indebtedness
prior to its express maturity,
and, in each case, the principal amount of any such
Indebtedness, together with the principal amount of any other
such Indebtedness under which there has been a Payment Default
which remains outstanding or the maturity of which has been so
accelerated, aggregates US$10.0 million or more, PROVIDED that
if any such default is cured or waived or any such
acceleration rescinded, or such Indebtedness is repaid, within
a period of 10 days from the continuation of such default
beyond the applicable grace or cure period or the occurrence
of such acceleration, as the case may be, such Event of
Default under the indenture and any consequential acceleration
of the notes shall be automatically rescinded, so long as such
rescission does not conflict with any judgment or decree;
(6) failure by Compton or any of its Restricted Subsidiaries to
pay final judgments aggregating in excess of US$10.0 million,
which judgments are not paid, discharged or stayed for a
period of 60 days; and
(7) except as permitted by the indenture, any Subsidiary Guarantee
shall be held in any judicial proceeding to be unenforceable
or invalid or shall cease for any reason to be in full force
and effect or any Significant Subsidiary, or any Person acting
on behalf of any Significant Subsidiary, shall deny or
disaffirm its obligations under its Subsidiary Guarantee; and
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(8) certain events of bankruptcy or insolvency described in the
indenture with respect to Compton or any of its Significant
Subsidiaries.
In the case of an Event of Default arising from certain events of
bankruptcy or insolvency, with respect to Compton, any Subsidiary that is a
Significant Subsidiary or any group of Subsidiaries that, taken together, would
constitute a Significant Subsidiary, all outstanding notes will become due and
payable immediately without further action or notice. If any other Event of
Default occurs and is continuing, the trustee or the Holders of at least 25% in
principal amount of the then outstanding notes may declare all the notes to be
due and payable immediately.
Holders of the notes may not enforce the indenture or the notes except
as provided in the indenture. Subject to certain limitations, Holders of a
majority in principal amount of the then outstanding notes may direct the
trustee in its exercise of any trust or power. The trustee may withhold from
Holders of the notes notice of any continuing Default or Event of Default if it
determines that withholding notice is in their interest, except a Default or
Event of Default relating to the payment of principal or interest or Additional
Interest.
The Holders of a majority in aggregate principal amount of the notes
then outstanding by notice to the trustee may on behalf of the Holders of all of
the notes waive any existing Default or Event of Default and its consequences
under the indenture except a continuing Default or Event of Default in the
payment of interest or Additional Interest on, or the principal of, the notes.
In the case of any Event of Default occurring by reason of any willful
action or inaction taken or not taken by or on behalf of Compton with the
intention of avoiding payment of the premium that Compton would have had to pay
if Compton then had elected to redeem the notes pursuant to the optional
redemption provisions of the indenture, an equivalent premium will also become
and be immediately due and payable to the extent permitted by law upon the
acceleration of the notes. If an Event of Default occurs prior to May 15, 2006,
by reason of any willful action (or inaction) taken (or not taken) by or on
behalf of Compton with the intention of avoiding the prohibition on redemption
of the notes prior to May 15, 2006, then the premium specified in the indenture
will also become immediately due and payable to the extent permitted by law upon
the acceleration of the notes.
Compton is required to deliver to the trustee annually a statement
regarding compliance with the indenture. Upon becoming aware of any Default or
Event of Default, Compton is required to deliver promptly to the trustee a
statement specifying such Default or Event of Default.
NO PERSONAL LIABILITY OF DIRECTORS, OFFICERS, EMPLOYEES AND STOCKHOLDERS
No director, officer, employee, incorporator or stockholder of Compton
or any Guarantor, as such, will have any liability for any obligations of
Compton or the Guarantors under the notes, the indenture, the Subsidiary
Guarantees, or for any claim based on, in respect of, or by reason of, such
obligations or their creation. Each Holder of notes by accepting a note waives
and releases all such liability. The waiver and release are part of the
consideration for issuance of the notes. The waiver may not be effective to
waive liabilities under the federal securities laws.
LEGAL DEFEASANCE AND COVENANT DEFEASANCE
Compton may, at its option and at any time, elect to have all of its
obligations discharged with respect to the outstanding notes and all obligations
of the Guarantors discharged with respect to their Subsidiary Guarantees ("Legal
Defeasance") except for:
(1) the rights of Holders of outstanding notes to receive payments
in respect of the principal of, or interest or premium and
Additional Interest, if any, on such notes when such payments
are due from the trust referred to below;
(2) Compton's obligations with respect to the notes concerning
issuing temporary notes, registration of notes, replacing
mutilated, destroyed, lost or stolen notes, maintaining an
office or agency for payment and segregating and holding money
for security payments held in trust;
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(3) the rights, powers, trusts, duties and immunities of the
trustee, and Compton's and the Guarantor's obligations in
connection therewith; and
(4) the Legal Defeasance provisions of the indenture.
In addition, Compton may, at its option and at any time, elect to have
the obligations of Compton and the Guarantors released with respect to certain
covenants that are described in the indenture ("Covenant Defeasance") and
thereafter any omission to comply with those covenants will not constitute a
Default or Event of Default with respect to the notes. In the event Covenant
Defeasance occurs, certain events (not including non-payment, bankruptcy,
receivership, reorganization and insolvency events) described under "-- Events
of Default and Remedies" will no longer constitute an Event of Default with
respect to the notes.
In order to exercise either Legal Defeasance or Covenant Defeasance:
(1) Compton must irrevocably deposit with the trustee, in trust,
for the benefit of the Holders of the notes, cash in U.S.
dollars, Government Securities that may not be redeemed by the
holder prior to their stated maturity or a combination of cash
in U.S. dollars and non-callable Government Securities, in
amounts as will be sufficient, in the opinion of a nationally
recognized firm of independent public accountants in Canada or
the United States, to pay the principal of, or interest and
premium and Additional Interest, if any, on the outstanding
notes on the stated maturity or on the applicable redemption
date, as the case may be, and Compton must specify whether the
notes are being defeased to maturity or to a particular
redemption date;
(2) in the case of Legal Defeasance, Compton has delivered to the
trustee an opinion of counsel reasonably acceptable to the
trustee confirming that (a) Compton has received from, or
there has been published by, the Internal Revenue Service a
ruling or (b) since the date of the indenture, there has been
a change in the applicable federal income tax law, in either
case to the effect that, and based thereon such opinion of
counsel will confirm that, the Holders of the outstanding
notes will not recognize income, gain or loss for federal
income tax purposes as a result of such Legal Defeasance and
will be subject to federal income tax on the same amounts, in
the same manner and at the same times as would have been the
case if such Legal Defeasance had not occurred;
(3) in the case of Covenant Defeasance, Compton has delivered to
the trustee (a) an opinion of counsel reasonably acceptable to
the trustee confirming that the Holders of the outstanding
notes will not recognize income, gain or loss for U.S. federal
income tax purposes as a result of such Covenant Defeasance
and will be subject to U.S. federal income tax on the same
amounts, in the same manner and at the same times as would
have been the case if such Covenant Defeasance had not
occurred and (b) an opinion of counsel qualified to practice
in Canada or a ruling from Revenue Canada, Taxation to the
effect that Holders of the outstanding notes who are not
resident in Canada will not recognize income, gain or loss for
Canadian federal, provincial or territorial income tax or
other tax purposes as a result of such deposit and defeasance
and will only be subject to Canadian federal, provincial
income tax and other taxes on the same amounts, in the same
manner and at the same times as would have been the case had
such deposit and defeasance not occurred;
(4) no Default or Event of Default has occurred and is continuing
on the date of such deposit (other than a Default or Event of
Default resulting from the borrowing of funds to be applied to
such deposit);
(5) such Legal Defeasance or Covenant Defeasance will not result
in a breach or violation of, or constitute a default under any
material agreement or instrument (other than the indenture) to
which Compton or any of its Restricted Subsidiaries is a party
or by which Compton or any of its Restricted Subsidiaries is
bound;
(6) Compton must deliver to the trustee an officers' certificate
stating that the deposit was not made by Compton with the
intent of preferring the Holders of notes over the other
creditors of Compton with the intent of defeating, hindering,
delaying or defrauding creditors of Compton or others; and
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(7) Compton must deliver to the trustee an officers' certificate
and an opinion of counsel, each stating that all conditions
precedent under the indenture relating to the Legal Defeasance
or the Covenant Defeasance have been complied with.
AMENDMENT, SUPPLEMENT AND WAIVER
Except as provided in the next three succeeding paragraphs, the
indenture or the notes may be amended or supplemented with the consent of the
Holders of at least a majority in principal amount of the notes then outstanding
(including, without limitation, consents obtained in connection with a purchase
of, or tender offer or exchange offer for, notes), and any existing Default or
compliance with any provision of the indenture or the notes may be waived with
the consent of the Holders of a majority in principal amount of the then
outstanding notes (including, without limitation, consents obtained in
connection with a purchase of, or tender offer or exchange offer for, notes).
Without the consent of each Holder affected, an amendment or waiver may
not (with respect to any notes held by a non-consenting Holder):
(1) reduce the principal amount of notes whose Holders must
consent to an amendment, supplement or waiver;
(2) reduce the principal of or change the fixed maturity of any
note or alter the provisions with respect to the redemption of
the notes (other than provisions relating to the covenants
described above under the caption "-- Repurchase at the Option
of Holders");
(3) reduce the rate of or change the time for payment of interest
on any note;
(4) waive a Default or Event of Default in the payment of
principal of, or interest or premium, or Additional Interest,
if any, on the notes (except a rescission of acceleration of
the notes by the Holders of at least a majority in aggregate
principal amount of the notes and a waiver of the payment
default that resulted from such acceleration);
(5) make any note payable in money other than that stated in the
notes;
(6) make any change in the provisions of the indenture relating to
waivers of past Defaults or the rights of Holders of notes to
receive payments of principal of, or interest or premium or
Additional Interest, if any, on the notes;
(7) waive a redemption payment with respect to any note (other
than a payment required by one of the covenants described
above under the caption "--Repurchase at the Option of
Holders");
(8) release any Guarantor from any of its obligations under its
Subsidiary Guarantee or the indenture, except in accordance
with the terms of the indenture; or
(9) make any change in the preceding amendment and waiver
provisions.
Notwithstanding the preceding, without the consent of any Holder of
notes, Compton, the Guarantors and the trustee may amend or supplement the
indenture or the notes:
(1) to cure any ambiguity, defect or inconsistency;
(2) to provide for uncertificated notes in addition to or in place
of certificated notes;
(3) to provide for the assumption of Compton's and each
Guarantor's obligations to Holders of notes in the case of a
merger or consolidation or sale of all or substantially all of
Compton's assets;
(4) to make any change that would provide any additional rights or
benefits to the Holders of notes or that does not adversely
affect the legal rights under the indenture of any such
Holder; or
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(5) to comply with requirements of the Commission in order to
effect or maintain the qualification of the indenture under
the Trust Indenture Act.
SATISFACTION AND DISCHARGE
The indenture will be discharged and will cease to be of further effect
as to all notes issued thereunder, when:
(1) either:
(a) all notes that have been authenticated, except
lost, stolen or destroyed notes that have been
replaced or paid and notes for whose payment money
has been deposited in trust and thereafter repaid to
Compton, have been delivered to the trustee for
cancellation; or
(b) all notes that have not been delivered to the trustee
for cancellation have become due and payable by
reason of the mailing of a notice of redemption or
otherwise or will become due and payable within one
year and Compton or any Guarantor has irrevocably
deposited or caused to be deposited with the trustee
as trust funds in trust solely for the benefit of the
Holders, cash in U.S. dollars, non-callable
Government Securities, or a combination of cash in
U.S. dollars and non-callable Government Securities,
in amounts as will be sufficient to pay and discharge
the principal, premium and Additional Interest, if
any, and accrued interest to the date of maturity or
redemption;
(2) no Default or Event of Default has occurred and is continuing
on the date of the deposit or will occur as a result of the
deposit other than a Default or Event of Default resulting
from the borrowing of funds to be applied to such deposit and
the deposit will not result in a breach or violation of, or
constitute a default under, any other instrument to which
Compton or any Guarantor is a party or by which Compton or any
Guarantor is bound;
(3) Compton or any Guarantor has paid or caused to be paid all
sums payable by it under the indenture; and
(4) Compton has delivered irrevocable instructions to the trustee
under the indenture to apply the deposited money toward the
payment of the notes at maturity or the redemption date, as
the case may be.
In addition, Compton must deliver an officers' certificate and an
opinion of counsel to the trustee stating that all conditions precedent to
satisfaction and discharge have been satisfied.
CONCERNING THE TRUSTEE
If the trustee becomes a creditor of Compton or any Guarantor, the
indenture limits its right to obtain payment of claims in certain cases, or to
realize on certain property received in respect of any such claim as security or
otherwise. The trustee will be permitted to engage in other transactions;
however, if it acquires any conflicting interest it must eliminate such conflict
within 90 days, apply to the Commission for permission to continue or resign.
The Holders of a majority in principal amount of the then outstanding
notes will have the right to direct the time, method and place of conducting any
proceeding for exercising any remedy available to the trustee, subject to
certain exceptions. The indenture provides that in case an Event of Default
occurs and is continuing, the trustee will be required, in the exercise of its
power, to use the degree of care of a prudent man in the conduct of his own
affairs. Subject to such provisions, the trustee will be under no obligation to
exercise any of its rights or powers under the indenture at the request of any
Holder of notes, unless such Holder has offered to the trustee security and
indemnity satisfactory to it against any loss, liability or expense.
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ADDITIONAL INFORMATION
Anyone who receives this prospectus may obtain a copy of the indenture
and registration rights agreement without charge by writing to Compton Petroleum
Corporation, Suite 3300, 425 - 1st Street S.W., Calgary, Alberta, T2P 3L8,
Attention: Corporate Secretary.
DEFINITIONS
Set forth below are certain defined terms used in the indenture.
Reference is made to the indenture for a full disclosure of all such terms, as
well as any other capitalized terms used herein for which no definition is
provided.
"ACQUIRED DEBT" means, with respect to any specified Person:
(1) Indebtedness of any other Person existing at the time such
other Person is merged with or into or became a Restricted
Subsidiary of such specified Person, whether or not such
Indebtedness is incurred in connection with, or in
contemplation of, such other Person merging with or into, or
becoming a Restricted Subsidiary of, such specified Person;
and
(2) Indebtedness secured by a Lien encumbering any asset acquired
by such specified Person;
provided that any Indebtedness of such Person that is redeemed,
defeased, retired or otherwise repaid at the time of or immediately
upon consummation of the transaction by which such other Person is
merged with or into, or becomes a Restricted Subsidiary of, such
specified Person, or such assets are acquired from such Person, will
not be Acquired Debt.
"ADJUSTED CONSOLIDATED NET TANGIBLE ASSETS" means, without duplication,
as of the date of determination; the sum of:
(1) discounted future net revenues from proved oil and gas
reserves of Compton and its Restricted Subsidiaries calculated
in accordance with Commission guidelines (before any
provincial, state or federal income taxes), as confirmed by a
nationally recognized firm of independent petroleum engineers
(which shall include Outtrim Szabo Associates Ltd.) in a
reserve report prepared as of the end of Compton's most
recently completed fiscal year, as INCREASED BY, as of the
date of determination, the discounted future net revenues of
(a) estimated proved oil and gas reserves acquired since the
date of such year-end reserve report, and (b) estimated oil
and gas reserves attributable to extensions, discoveries and
other additions and upward revisions of estimates of proved
oil and gas reserves since the date of such year-end reserve
report due to exploration, development or exploitation
activities, in each case, calculated in accordance with
Commission guidelines (utilizing the prices utilized in such
year-end reserve report), AND DECREASED BY, as of the date of
determination, the estimated discounted future net revenues of
(c) estimated proved oil and gas reserves produced or disposed
of since the date of such year-end reserve report and (d)
reductions in estimated proved oil and gas reserves
attributable to downward revisions of estimates of proved oil
and gas reserves since the date of such year-end reserve
report due to changes in geological conditions or other
factors that would, in accordance with standard industry
practice, cause such revisions, in each case calculated in
accordance with Commission guidelines (utilizing the prices in
such year-end reserve report), PROVIDED that, in the case of
each of the determinations made pursuant to clauses (a)
through (d), such increases and decreases shall be as
estimated by Compton's petroleum engineers, unless there is a
Material Change as a result of such acquisitions, dispositions
or revisions, in which case the discounted future net revenues
utilized for purposes of this clause (1) shall be confirmed in
a written report of a nationally recognized firm of
independent petroleum engineers (which shall include Outtrim
Szabo Associates Ltd.) delivered to the trustee (which report
shall be reasonably satisfactory in form and substance to the
trustee),
(2) the capitalized costs that are attributable to oil and gas
properties of Compton and its Restricted Subsidiaries to which
no proved oil and gas reserves are attributable, based on
Compton's books and records as of a date no earlier than the
date of Compton's most recent available internal quarterly
financial statements,
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(3) the Consolidated Net Working Capital of Compton on a date no
earlier than the date of Compton's most recently available
internal quarterly financial statements, and
(4) the greater of (a) the net book value of other tangible assets
of Compton on a date no earlier than the date of Compton's
most recently available internal quarterly financial
statements or (b) the appraised value, as estimated by
independent appraisers, of other tangible assets of Compton
and its Restricted Subsidiaries, in either case, as of the
date of Compton's most recently available internal quarterly
financial statements,
MINUS the sum of:
(1) minority interests,
(2) any net gas balancing liabilities of Compton and its
Restricted Subsidiaries reflected in Compton's most recently
available internal quarterly financial statements,
(3) to the extent included in the first clause (1) above, the
discounted future net revenues, calculated in accordance with
Commission guidelines utilizing the prices utilized in
Compton's year-end reserve report, attributable to reserves
that are required to be delivered to third parties to fully
satisfy the obligations of Compton and its Restricted
Subsidiaries with respect to Volumetric Production Payments on
the schedules specified with respect thereto,
(4) the discounted future net revenues, calculated in accordance
with Commission guidelines, attributable to reserves subject
to Dollar-Denominated Production Payments that, based on the
estimates of production and price assumptions included in
determining the discounted future net revenues specified in
the first clause (1) above, would be necessary to fully
satisfy the payment obligations of Compton and its Restricted
Subsidiaries with respect to Dollar-Denominated Production
Payments on the schedules specified with respect thereto, and
(5) the discounted future net revenues, calculated in accordance
with Commission guidelines utilizing the prices utilized in
Compton's year-end reserve report, attributable to reserves
that are subject to participation, partnership, vendor
financing or other agreements then in effect, or that are
otherwise required to be delivered to third parties but only
to the extent that such third parties are then entitled to
such reserves, or in the case of vendor financing or other
encumbrances reduced only by the value of such encumbrances.
If Compton changes its method of accounting from the full cost method
to the successful efforts method or a similar method of accounting,
"Adjusted Consolidated Net Tangible Assets" will continue to be
calculated as if Compton were still using the full cost method of
accounting.
"AFFILIATE" of any specified Person means any other Person directly or
indirectly controlling or controlled by or under direct or indirect
common control with such specified Person. For purposes of this
definition, "control", as used with respect to any Person, means the
possession, directly or indirectly, of the power to direct or cause the
direction of the management or policies of such Person, whether through
the ownership of voting securities, by agreement or otherwise; PROVIDED
that beneficial ownership of 10% or more of the Voting Stock of a
Person will be deemed to be control. For purposes of this definition,
the terms "controlling", "controlled by" and "under common control
with" have correlative meanings.
"ASSET SALE" means:
(1) the sale, lease, conveyance or other disposition of any assets
or rights, other than sales of inventory in the ordinary
course of business consistent with past practices; PROVIDED
that the sale, conveyance or other disposition of all or
substantially all of the assets of Compton and its
Subsidiaries taken as a whole will be governed by the
provisions of the indenture described above under the caption
"-- Repurchase at the Option of Holders -- Change of Control"
and/or the provisions described above under the caption
"--
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Certain Covenants -- Merger, Consolidation or Sale of Assets"
and not by the provisions of the Asset Sale covenant; and
(2) the issuance of Equity Interests in any of Compton's
Restricted Subsidiaries or the sale of Equity Interests in any
of its Subsidiaries.
Notwithstanding the preceding, none of the following items will be
deemed to be an Asset Sale:
(1) any single transaction or series of related transactions that
involves assets having a fair market value of less than US$1.0
million;
(2) a transfer of assets between or among Compton and its
Restricted Subsidiaries;
(3) an issuance of Equity Interests by a Subsidiary to Compton or
to another Subsidiary;
(4) consisting of worn-out, obsolete or retired equipment or
facilities in the ordinary course of business;
(5) the sale or lease of equipment, inventory, including current
production, accounts receivable or other assets in the
ordinary course of business;
(6) the sale or other disposition of cash or Cash Equivalents;
(7) any transfer of properties or assets (including Capital Stock)
that is governed by the provisions of the indenture described
under "-- Certain Covenants -- Consolidation, Merger and Sale
of Assets"; or that is a Restricted Payment or Permitted
Investment that is permitted by the covenant described above
under the caption "-- Certain Covenants -- Restricted
Payments";
(8) the sale or transfer (whether or not in the ordinary course of
business) of oil and gas properties or direct or indirect
interests in real property, provided that at the time of such
sale or transfer such properties do not have associated with
them any proved reserves;
(9) the abandonment, farm-out, lease or sublease of developed or
undeveloped oil and gas properties in the ordinary course of
business or resulting from any pooling, unit or farm-out
agreement entered into in the ordinary course of business;
(10) the trade or exchange by the Company or any Subsidiary of the
Company of any oil and gas property owned or held by the
Company or such Subsidiary for any oil and gas property owned
or held by another Person;
(11) the sale or transfer of hydrocarbons or other mineral products
in the ordinary course of business; and
(12) a Permitted Investment.
"BENEFICIAL OWNER" has the meaning assigned to such term in Rule 13d-3
and Rule 13d-5 under the Exchange Act, except that in calculating the
beneficial ownership of any particular "person" (as that term is used
in Section 13(d)(3) of the Exchange Act), such "person" will be deemed
to have beneficial ownership of all securities that such "person" has
the right to acquire by conversion or exercise of other securities,
whether such right is currently exercisable or is exercisable only upon
the occurrence of a subsequent condition. The terms "Beneficially Owns"
and "Beneficially Owned" have a corresponding meaning.
"BOARD OF DIRECTORS" means:
(1) with respect to a corporation, the board of directors of the
corporation;
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(2) with respect to a partnership, the Board of Directors of the
corporation which is the general partner of the partnership;
and
(3) with respect to any other Person, the board or committee of
such Person serving a similar function.
"CAPITAL LEASE OBLIGATION" means, at the time any determination is to
be made, the amount of the liability in respect of a capital lease that
would at that time be required to be classified and accounted for as a
capitalized lease obligation on a balance sheet in accordance with
generally accepted accounting principles, consistently applied,
which are in effect in Canada from time to time (referred to as GAAP).
"CAPITAL STOCK" means:
(1) in the case of a corporation, corporate stock of any class;
(2) in the case of an association or business entity, any and all
shares, interests, participations, rights or other equivalents
(however designated) of corporate stock;
(3) in the case of a partnership or limited liability company,
partnership or membership interests (whether general or
limited); and
(4) any other interest or participation that confers on a Person
the right to receive a share of the profits and losses of, or
distributions of assets of, the issuing Person.
"CASH EQUIVALENTS" means:
(1) United States or Canadian dollars;
(2) securities issued by or directly and fully guaranteed or
insured by the federal governments of Canada or the United
States of America or any agency or instrumentality thereof
(PROVIDED that the full faith and credit of the federal
governments of Canada or the United States is pledged in
support of those securities) having maturities of not more
than 270 days from the date of acquisition;
(3) certificates of deposit and eurodollar time deposits with
maturities of 270 days or less from the date of acquisition,
bankers' acceptances with maturities not exceeding 270 days
and overnight bank deposits, in each case, with any lender
party to the Credit Agreement or with any United States
commercial bank or any Canadian chartered bank having capital
and surplus in excess of US$500.0 million and a Thomson Bank
Watch Rating of "B" or better;
(4) repurchase obligations with a term of not more than seven days
for underlying securities of the types described in clauses
(2) and (3) above entered into with any financial institution
meeting the qualifications specified in clause (3) above;
(5) commercial paper rated at least P-1 by Moody's Investors
Service, Inc. or A-1 by Standard & Poor's Rating Services or
at least R-1 by Dominion Bond Rating Service and in each case
maturing within 270 days after the date of acquisition; and
(6) money market funds at least 95% of the assets of which
constitute Cash Equivalents of the kinds described in clauses
(1) through (5) of this definition.
"CHANGE OF CONTROL" means the occurrence of any of the following
events:
(1) the direct or indirect sale, transfer, conveyance or other
disposition (other than by way of merger, amalgamation or
consolidation), in one or a series of related transactions, of
all or substantially all of the properties or assets of
Compton and its Restricted Subsidiaries, taken as a whole, to
any "person" (as that term is used in Section 13(d)(3) of the
Exchange Act);
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(2) the adoption or approval by the Board of Directors of Compton
or its stockholders of a plan relating to the liquidation or
dissolution of Compton;
(3) the consummation of any transaction (including, without
limitation, any merger or consolidation) the result of which
is that any "person" (as defined above) becomes the Beneficial
Owner, directly or indirectly, of more than 50% the Voting
Stock of Compton, measured by voting power rather than number
of shares; or
(4) the first day on which a majority of the members of the Board
of Directors of Compton are not Continuing Directors.
"CONSOLIDATED CASH FLOW" means, with respect to any specified Person
for any period, the Consolidated Net Income of such Person for such
period PLUS:
(1) an amount equal to any extraordinary loss, plus any net loss
realized by such Person or any of its Restricted Subsidiaries
in connection with an Asset Sale, to the extent such losses
were deducted in computing such Consolidated Net Income; PLUS
(2) provision for taxes based on income or profits of such Person
and its Restricted Subsidiaries for such period, to the extent
that such provision for taxes was deducted in computing such
Consolidated Net Income; PLUS
(3) consolidated interest expense of such Person and its
Restricted Subsidiaries for such period, whether paid or
accrued and whether or not capitalized (including, without
limitation, amortization of debt issuance costs and original
issue discount, non-cash interest payments, the interest
component of any deferred payment obligations, the interest
component of all payments associated with Capital Lease
Obligations, commissions, discounts and other fees and charges
incurred in respect of letter of credit or bankers' acceptance
financings, and net of the effect of all payments made or
received pursuant to Hedging Obligations), to the extent that
any such expense was deducted in computing such Consolidated
Net Income; PLUS
(4) depreciation, depletion, amortization (including amortization
of goodwill and other intangibles but excluding amortization
of prepaid cash expenses that were paid in a prior period) and
other non-cash expenses (excluding any such non-cash expense
to the extent that it represents an accrual of or reserve for
cash expenses in any future period or amortization of a
prepaid cash expense that was paid in a prior period) of such
Person and its Restricted Subsidiaries for such period to the
extent that such depreciation, depletion, amortization and
other non-cash expenses were deducted in computing such
Consolidated Net Income; MINUS
(5) non-cash items increasing such Consolidated Net Income for
such period, other than the accrual of revenue in the ordinary
course of business; and MINUS
(6) to the extent included in determining Consolidated Net Income,
the sum of:
(a) the amount of deferred revenues that are amortized
during such period and that are attributable to
reserves that are subject to Volumetric Production
Payments; and
(b) amounts recorded in accordance with GAAP as
repayments of principal and interest pursuant to
Dollar-Denominated Production Payments,
in each case, on a consolidated basis and determined in accordance with
GAAP.
"CONSOLIDATED NET INCOME" means, with respect to any specified Person
for any period, the aggregate of the Net Income of such Person and its
Restricted Subsidiaries for such period, on a consolidated basis,
determined in accordance with GAAP; PROVIDED that:
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(1) the Net Income (but not loss) of any Person that is not a
Restricted Subsidiary or that is accounted for by the equity
method of accounting will be included only to the extent of
the amount of dividends or distributions paid in cash to the
specified Person or a Restricted Subsidiary of the Person;
(2) the Net Income of any Restricted Subsidiary will be excluded
to the extent that the declaration or payment of dividends or
similar distributions by that Restricted Subsidiary of that
Net Income is not at the date of determination permitted
without any prior governmental approval (that has not been
obtained) or, directly or indirectly, by operation of the
terms of its charter or any agreement, instrument, judgment,
decree, order, statute, rule or governmental regulation
applicable to that Restricted Subsidiary or its stockholders;
(3) the Net Income (but not loss) of any Person acquired in a
pooling of interests transaction for any period prior to the
date of such acquisition will be excluded;
(4) the cumulative effect of a change in accounting principles
will be excluded;
(5) any non-cash charges related to a ceiling test write-down
under GAAP will be excluded; and
(6) to the extent not otherwise included, any gain on the
disposition of a Restricted Investment will be included.
"CONSOLIDATED NET WORKING CAPITAL" of any Person as of any date of
determination means the difference (shown on the balance sheet of such
Person and its Restricted Subsidiaries determined on a consolidated
basis in accordance with GAAP as of the end of the most recent fiscal
quarter of such Person for which internal financial statements are
available) between (i) all current assets of such Person and its
Restricted Subsidiaries and (ii) all current liabilities of such Person
and its Restricted Subsidiaries except the current portion of long-term
Indebtedness.
"CONSOLIDATED NET WORTH" means, with respect to any specified Person as
of any date, the sum of:
(1) the consolidated equity of the common stockholders of such
Person and its consolidated Subsidiaries as of such date; plus
(2) the respective amounts reported on such Person's balance sheet
as of such date with respect to any series of preferred stock
(other than Disqualified Stock) that by its terms is not
entitled to the payment of dividends unless such dividends may
be declared and paid only out of net earnings in respect of
the year of such declaration and payment, but only to the
extent of any cash received by such Person upon issuance of
such preferred stock.
"CONTINUING DIRECTORS" means, as of any date of determination, any
member of the Board of Directors of Compton who:
(1) was a member of such Board of Directors on the date of the
indenture; or
(2) was nominated for election or elected to such Board of
Directors with the approval of a majority of the Continuing
Directors who were members of such Board at the time of such
nomination or election.
"CREDIT AGREEMENT" means that certain Amended and Restated Credit
Agreement dated as of the date of the Indenture, among Compton, as
borrower, certain Canadian chartered banks, as lenders, Bank of
Montreal, as lead arranger and administrative agent, The Bank of Nova
Scotia, as syndication agent, and The Toronto-Dominion Bank, as
documentation agent, including any related notes, debentures, pledges,
guarantees, security documents, instruments and agreements executed
from time to time in connection therewith, and in each case as amended,
modified, restated, renewed, replaced or refinanced from time to time,
including any agreement extending the maturity of, refinancing,
replacing or otherwise restructuring or adding Subsidiaries as
additional borrowers or guarantors thereunder, and all or any portion
of the Indebtedness and other Obligations under such agreement or
agreements or any successor or replacement agreement or any agreements,
and whether by the same or any other agent, lender or group of lenders.
For greater certainty, it is acknowledged that Interest Rate
Agreements, Currency
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Agreements and Oil and Gas Hedging Contracts entered into with a person
that at that time is a lender (or an affiliate thereof) under the
Credit Agreement are separate from, are not included within and do not
form part of any above inclusions of the Credit Agreement.
"CREDIT FACILITIES" means one or more credit or debt facilities
(including, without limitation, under the Credit Agreement) or
commercial paper facilities, in each case with banks or other
institutional lenders providing for , among other things, revolving
credit loans, term loans, receivables financing (including through the
sale of receivables to such lenders or to special purpose entities
formed to borrow from such lenders against such receivables) or letters
of credit, in each case, as amended, restated, modified, renewed,
refunded, replaced or refinanced in whole or in part from time to time.
"CURRENCY AGREEMENT" means any financial arrangement entered into
between a Person (or its Restricted Subsidiaries) and a counterparty on
a case by case basis in connection with a foreign exchange futures
contract, currency swap agreement, currency option or currency exchange
or other similar currency related transactions, the purpose of which is
to mitigate or eliminate its exposure to fluctuations in exchange rates
and currency values.
"DEFAULT" means the occurrence of any event that is, or with the
passage of time or the giving of notice or both would be, an Event of
Default under the indenture.
"DISQUALIFIED STOCK" means, with respect to any Person, any Capital
Stock that, by its terms (or by the terms of any security into which it
is convertible, or for which it is exchangeable, in each case at the
option of the holder of the Capital Stock), or upon the happening of
any event, matures or is mandatorily redeemable, pursuant to a sinking
fund obligation or otherwise, or redeemable at the option of the holder
of the Capital Stock, in whole or in part, prior to the date on which
the notes mature. Notwithstanding the preceding sentence, any Capital
Stock that would constitute Disqualified Stock solely because the
holders of the Capital Stock have the right to require Compton to
repurchase such Capital Stock upon the occurrence of a change of
control or an asset sale will not constitute Disqualified Stock if the
terms of such Capital Stock provide that Compton may not repurchase or
redeem any such Capital Stock pursuant to such provisions unless such
repurchase or redemption complies with the covenant described above
under the caption "-- Certain Covenants -- Restricted Payments".
"DOLLAR-DENOMINATED PRODUCTION PAYMENTS" means production payment
obligations recorded as liabilities in accordance with GAAP, together
with all undertakings and obligations in connection therewith.
"EQUITY INTERESTS" means Capital Stock and all warrants, options or
other rights to acquire Capital Stock (but excluding any debt security
that is convertible into, or exchangeable for, Capital Stock).
"EQUITY OFFERINGS" means any public or private sale of equity
securities of Compton (other than Disqualified Stock) generating gross
proceeds to Compton of at least US$10.0 million.
"EXISTING INDEBTEDNESS" means all Indebtedness of Compton and its
Subsidiaries (other than Indebtedness under the Credit Agreement) in
existence on the date of the indenture.
"FAIR MARKET VALUE" means, with respect to any asset, property or
service, the price that could be negotiated in an arm's length free
market transaction, for cash, between a willing seller and a willing
buyer, neither of whom is under pressure or compulsion to complete the
transaction. Unless otherwise specified in the indenture, in the case
of a transaction with respect to Compton or any of its Restricted
Subsidiaries exceeding US$10.0 million, fair market value will be
determined by the Board of Directors of Compton acting in good faith
and will be evidenced by a resolution delivered to the trustee.
"FIXED CHARGES" means, with respect to any specified Person for any
period, the sum, without duplication, of:
(1) the consolidated interest expense of such Person and its
Restricted Subsidiaries for such period, whether paid or
accrued, including, without limitation, amortization of debt
issuance costs and original issue discount, non-cash interest
payments, the interest component of any deferred payment
obligations, the interest component of all payments associated
with Capital Lease Obligations, commissions, discounts and
other fees and charges incurred in respect of letter of credit
or bankers' acceptance financings, and net of the effect of
all payments made or received pursuant to Interest Rate
Agreements; PLUS
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(2) the consolidated interest of such Person and its Restricted
Subsidiaries that was capitalized during such period; PLUS
(3) any interest expense on Indebtedness of another Person that is
Guaranteed by such Person (other than such Person or its
Restricted Subsidiaries) or one of its Restricted Subsidiaries
or secured by a Lien on assets of such Person or one of its
Restricted Subsidiaries, whether or not such Guarantee or Lien
is called upon; PLUS
(4) the product of (a) all dividends, whether paid or accrued and
whether or not in cash, on any series of Disqualified Stock of
such Person or any of its Restricted Subsidiaries, times (b) a
fraction, the numerator of which is one and the denominator of
which is one minus the then current combined federal,
provincial, state and local statutory tax rate of such Person
or any of its Restricted Subsidiaries, expressed as a decimal,
in each case, on a consolidated basis and in accordance with
GAAP.
"FIXED CHARGE COVERAGE RATIO" means with respect to any specified
Person for any period, the ratio of the Consolidated Cash Flow of such
Person and its Restricted Subsidiaries for such period to the Fixed
Charges of such Person and its Restricted Subsidiaries for such period.
In the event that the specified Person or any of its Restricted
Subsidiaries incurs, assumes, Guarantees, repays, repurchases or
redeems any Indebtedness (other than ordinary working capital
borrowings) or issues, repurchases or redeems preferred stock
subsequent to the commencement of the period for which the Fixed Charge
Coverage Ratio is being calculated and on or prior to the date on which
the event for which the calculation of the Fixed Charge Coverage Ratio
is made (the "Calculation Date"), then the Fixed Charge Coverage Ratio
will be calculated giving pro forma effect to such incurrence,
assumption, Guarantee, repayment, repurchase or redemption of
Indebtedness, or such issuance, repurchase or redemption of preferred
stock, and the use of the proceeds therefrom as if the same had
occurred at the beginning of the applicable four-quarter reference
period.
In addition, for purposes of calculating the Fixed Charge Coverage
Ratio:
(1) acquisitions that have been made by the specified Person or
any of its Restricted Subsidiaries, including through mergers
or consolidations and including any related financing
transactions, during the four-quarter reference period or
subsequent to such reference period and on or prior to the
Calculation Date will be given pro forma effect as if they had
occurred on the first day of the four-quarter reference period
and Consolidated Cash Flow for such reference period will be
calculated on a pro forma basis in accordance with Regulation
S-X under the Securities Act, but without giving effect to
clause (3) of the proviso set forth in the definition of
Consolidated Net Income;
(2) the Consolidated Cash Flow attributable to discontinued
operations, as determined in accordance with GAAP, and
operations or businesses disposed of prior to the Calculation
Date, will be excluded; and
(3) the Fixed Charges attributable to discontinued operations, as
determined in accordance with GAAP, and operations or
businesses disposed of prior to the Calculation Date, will be
excluded, but only to the extent that the obligations giving
rise to such Fixed Charges will not be obligations of the
specified Person or any of its Restricted Subsidiaries
following the Calculation Date.
"GUARANTORS" means each of:
(1) Compton's existing Subsidiaries; and
(2) any other Subsidiary that executes a Subsidiary Guarantee in
accordance with the provisions of the indenture;
and their respective successors and assigns.
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"HEDGING OBLIGATIONS" means, with respect to any specified Person, the
outstanding amount of all obligations of such Person and its Restricted
Subsidiaries under all Currency Agreements and all Interest Rate
Agreements, together with all interest, fees and other amounts payable
thereon or in connection therewith.
"INDEBTEDNESS" means, with respect to any specified Person at any date,
any indebtedness of such Person, whether or not contingent:
(1) in respect of borrowed money;
(2) evidenced by bonds, notes, debentures or similar instruments
or letters of credit (or reimbursement agreements in respect
thereof);
(3) in respect of banker's acceptances;
(4) representing Capital Lease Obligations;
(5) representing the balance deferred and unpaid of the purchase
price of any property, except any such balance that
constitutes an accrued expense or trade payable;
(6) representing any Hedging Obligations;
(7) in respect of Production Payments;
(8) in respect of Oil and Gas Hedging Contracts; or
(9) all conditional sale obligations and all obligations under
title retention agreements, but excluding a title retention
agreement to the extent it constitutes an operating lease
under Canadian law,
if and to the extent any of the preceding items (other than letters of
credit, Hedging Obligations and Oil and Gas Hedging Contracts) would
appear as a liability upon a balance sheet of the specified Person
prepared in accordance with GAAP. In addition, the term "Indebtedness"
includes all Indebtedness of others secured by a Lien on any asset of
the specified Person (whether or not such Indebtedness is assumed by
the specified Person) and, to the extent not otherwise included, the
Guarantee by the specified Person of any indebtedness of any other
Person.
The amount of any Indebtedness outstanding as of any date will be:
(1) the accreted value of the Indebtedness, in the case of any
Indebtedness issued with original issue discount; and
(2) the principal amount of the Indebtedness, together with any
interest on the Indebtedness that is more than 30 days past
due, in the case of any other Indebtedness.
"INTEREST RATE AGREEMENT" means any financial arrangement entered into
between a Person (or its Restricted Subsidiaries) and a counterparty on
a case by case basis in connection with interest rate swap
transactions, interest rate options, cap transactions, floor
transactions, collar transactions and other similar interest rate
protection related transactions, the purpose of which is to mitigate or
eliminate its exposure to fluctuations in interest rates.
"INVESTMENTS" means, with respect to any Person, all direct or indirect
investments by such Person in other Persons (including Affiliates) in
the forms of loans (including Guarantees or other obligations),
advances or capital contributions (excluding commission, travel and
similar advances to officers and employees made in the ordinary course
of business), purchases or other acquisitions for consideration of
Indebtedness, Equity Interests or other securities, together with all
items that are or would be classified as investments on a balance sheet
prepared in accordance with GAAP. "Investments" shall exclude
extensions of trade credit in the ordinary course of business for terms
not greater than 90 days. If Compton or any Subsidiary of Compton sells
or otherwise disposes of any Equity Interests of any direct or indirect
Subsidiary of Compton such that, after giving effect to any such sale
or
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disposition, such Person is no longer a Subsidiary of Compton, Compton
will be deemed to have made an Investment on the date of any such sale
or disposition equal to the fair market value of Compton's Investments
in such Subsidiary that were not sold or disposed of in an amount
determined as provided in the final paragraph of the covenant described
above under the caption "-- Certain Covenants -- Restricted Payments".
The acquisition by Compton or any Subsidiary of Compton of a Person
that holds an Investment in a third Person will be deemed to be an
Investment by Compton or such Subsidiary in such third Person in an
amount equal to the fair market value of the Investment held by the
acquired Person in such third Person in an amount determined as
provided in the final paragraph of the covenant described above under
the caption "-- Certain Covenants -- Restricted Payments".
"LIEN" means, with respect to any asset, any mortgage, lien (statutory
or otherwise), pledge, charge, security interest or encumbrance upon or
with respect to any property of any kind, whether or not filed,
recorded or otherwise perfected under applicable law, including any
conditional sale or other title retention agreement, but excluding a
title retention agreement to the extent it constitutes an operating
lease under Canadian law, any lease in the nature thereof, any option
or other agreement to sell or give a security interest in and any
filing of or agreement to give any financing statement under the
Uniform Commercial Code (or equivalent statutes) of any jurisdiction.
"MATERIAL CHANGE" means an increase or decrease (excluding changes that
result solely from changes in prices) of more than 30% during a fiscal
quarter in the estimated discounted future net cash flows from proved
oil and gas reserves of Compton and its Restricted Subsidiaries,
calculated in accordance with the first clause (1) of the definition of
Adjusted Consolidated Net Tangible Assets; provided, however, that the
following will be excluded from the calculation of Material Change:
(1) the estimated future net cash flows from:
(2) any acquisitions during the quarter of oil and gas reserves
that have been audited by a nationally recognized firm of
independent petroleum engineers (which shall include Outtrim
Szabo Associates Ltd.), and
(3) any disposition of properties held at the beginning of such
quarter that have been disposed of as provided in the covenant
described under the caption "-- Asset Sales".
"NET INCOME" means, with respect to any specified Person, the net
income (loss) of such Person, determined in accordance with GAAP and
before any reduction in respect of preferred stock dividends,
excluding, however:
(1) any gain (but not loss), together with any related provision
for taxes on such gain (but not loss), realized in connection
with: (a) any Asset Sale; or (b) the disposition of any
securities by such Person or any of its Restricted
Subsidiaries or the extinguishment of any Indebtedness of such
Person or any of its Restricted Subsidiaries; and
(2) any extraordinary gain (but not loss), together with any
related provision for taxes on such extraordinary gain (but
not loss).
"NET PROCEEDS" means the aggregate cash proceeds received by Compton or
any of its Restricted Subsidiaries in respect of any Asset Sale
(including, without limitation, any cash received upon the sale or
other disposition of any non-cash consideration received in any Asset
Sale), net of the direct costs relating to such Asset Sale, including,
without limitation, legal, accounting and investment banking fees, and
sales commissions, and any relocation expenses incurred as a result of
the Asset Sale, taxes paid or payable as a result of the Asset Sale, in
each case, after taking into account any available tax credits or
deductions and any tax sharing arrangements, and amounts required to be
applied to the repayment of Indebtedness, other than Indebtedness under
a Credit Facility secured by a Lien on the asset or assets that were
the subject of such Asset Sale and any reserve for adjustment in
respect of the sale price of such asset or assets established in
accordance with GAAP.
"NON-RECOURSE DEBT" means Indebtedness:
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(1) as to which neither Compton nor any of its Restricted
Subsidiaries (a) provides credit support of any kind
(including any undertaking, agreement or instrument that would
constitute Indebtedness), (b) is directly or indirectly liable
as a guarantor or otherwise, or (c) constitutes the lender;
(2) no default with respect to which (including any rights that
the holders of the Indebtedness may have to take enforcement
action against an Unrestricted Subsidiary) would permit upon
notice, lapse of time or both any holder of any other
Indebtedness of Compton or any of its Restricted Subsidiaries
to declare a default on such other Indebtedness or cause the
payment of the Indebtedness to be accelerated or payable prior
to its stated maturity; and
(3) as to which the lenders have been notified in writing that
they will not have any recourse to the stock or assets of
Compton or any of its Restricted Subsidiaries subject to
customary exceptions for environmental, title, fraud and
similar matters.
"OIL AND GAS BUSINESS" means:
(1) the acquisition, exploration, development, operation and
disposition of interests in oil, gas and other hydrocarbon
properties,
(2) the gathering, marketing, treating, processing, storage,
selling and transporting of any production from such interests
or properties,
(3) the exploration for or development, production, treatment,
processing, storage, transportation or marketing of oil, gas
and other minerals and products produced in association
therewith,
(4) evaluating, participating in or pursuing any other activity or
opportunity that is primarily related to clauses (1) through
(3) above, and
(5) any activity that is ancillary to or necessary or appropriate
for the activities described in clauses (1) through (4) of
this definition,
provided that, in respect of Compton, the determination of what
reasonably constitutes a permissible Oil and Gas Business pursuant to
clauses (1) to (5) above shall be made in good faith by the Board of
Directors of Compton.
"OIL AND GAS HEDGING CONTRACTS" means any transaction, arrangement or
agreement entered into between a Person (or any of its Restricted
Subsidiaries) and a counterparty on a case by case basis, including any
futures contract, a commodity option, a swap, a forward sale or
otherwise, the purpose of which is to mitigate, manage or eliminate its
exposure to fluctuations in commodity prices, including contracts
settled by physical delivery of the commodity not settled within 60
days of the date of any such contract; provided that Production
Payments will not be treated as Oil and Gas Hedging Contracts for the
purposes of the indenture.
"OIL AND GAS INVESTMENTS" means any Investments made in the ordinary
course of, and of a nature that is or shall have become customary in,
the Oil and Gas Business as a means of actively exploiting, exploring
for, acquiring, developing, producing, processing, gathering, marketing
or transporting oil and gas through agreements, transactions, interests
or arrangements which permit one to share risks or costs, comply with
regulatory requirements regarding local ownership or satisfy other
objectives customarily achieved through the conduct of Oil and Gas
Business jointly with third parties, including, without limitation:
(1) ownership interests in oil and gas properties, processing
facilities or gathering systems or ancillary real property
interests and
(2) Investments in the form of or pursuant to operating
agreements, processing agreements, farm-in agreements,
farm-out agreements, development agreements, area of mutual
interest agreements, unitization agreements, pooling
agreements, joint bidding agreements, service contracts, joint
venture agreements,
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partnership agreements (whether general or limited),
subscription agreements, stock purchase agreements and other
similar agreements with third parties.
"PERMITTED ASSETS" means any and all long-term assets that are used or
useful in an Oil and Gas Business.
"PERMITTED INVESTMENTS" means, without duplication:
(1) any Investment in Compton or in a Restricted Subsidiary of
Compton;
(2) any Investment in Cash Equivalents;
(3) any Investment by Compton or any Restricted Subsidiary of
Compton in a Person, if as a result of such Investment:
(a) such Person becomes a Restricted Subsidiary of
Compton; or
(b) such Person is merged, consolidated or amalgamated
with or into, or transfers or conveys substantially
all of its assets to, or is liquidated into, Compton
or a Restricted Subsidiary of Compton;
(4) any Investment made as a result of the receipt of non-cash
consideration from an Asset Sale that was made pursuant to and
in compliance with the covenant described above under the
caption "-- Repurchase at the Option of Holders -- Asset
Sales";
(5) any acquisition of assets solely in exchange for the issuance
of Equity Interests (other than Disqualified Stock) of
Compton;
(6) any Investments received in compromise of obligations of such
persons incurred in the ordinary course of trade creditors or
customers that were incurred in the ordinary course of
business, including pursuant to any plan of reorganization or
similar arrangement upon the bankruptcy or insolvency of any
trade creditor or customer;
(7) Hedging Obligations and Oil and Gas Hedging Contracts;
(8) Oil and Gas Investments;
(9) loans or advances made (a) to any officer, director or
employee of Compton or any of its Restricted Subsidiaries that
are approved by a duly authorized officer, the proceeds of
which are used solely to exercise stock options received
pursuant to an employee stock option plan or other incentive
plan, in a principal amount not to exceed the exercise price
of such stock options and (b) to refinance loans, together
with accrued interest thereon, made pursuant to this clause
(9); PROVIDED such loans do not exceed US$5.0 million at any
one time outstanding; and
(10) other Investments in any Person having an aggregate fair
market value (measured on the date each such Investment was
made and without giving effect to subsequent changes in
value), when taken together with all other Investments made
pursuant to this clause (10) that are at the time outstanding
not to exceed US$10.0 million.
"PERMITTED LIENS" means, as of any date:
(1) Liens on assets of Compton and any Subsidiary securing
Indebtedness that constitutes Permitted Debt under Credit
Facilities and Obligations in respect of such Indebtedness;
(2) Liens in favor of Compton or any of the Guarantors;
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(3) Liens on property of a Person existing at the time such Person
is amalgamated or merged with or into or consolidated with
Compton or any Restricted Subsidiary of Compton; PROVIDED that
such Liens were in existence prior to the contemplation of
such amalgamation, merger or consolidation and do not extend
to any assets other than those of the Person amalgamated or
merged into or consolidated with Compton or the Subsidiary;
(4) Liens securing Hedging Obligations and Oil and Gas Hedging
Contracts that constitute Permitted Debt;
(5) Liens securing the assets purchased by purchase money
indebtedness which is Permitted Debt;
(6) Liens to secure payment of royalties, revenue interests, net
profits interests and preferential rights of purchase incurred
in the ordinary course of business to the extent of the
security interest in those underlying assets;
(7) Liens for any judgments rendered that do not constitute an
Event of Default;
(8) Liens for any judgment rendered, or claim filed, against
Compton or any Restricted Subsidiary which are being contested
in good faith by appropriate proceedings that do not
constitute an Event of Default if during such contestation a
stay of enforcement of such judgment or claim is in effect;
(9) Liens on property existing at the time of acquisition of the
property by Compton or any Restricted Subsidiary of Compton,
PROVIDED that such Liens were in existence prior to the
contemplation of such acquisition;
(10) Liens to secure the performance of statutory obligations,
surety or appeal bonds, performance bonds or other obligations
of a like nature incurred in the ordinary course of business;
(11) Liens to secure Indebtedness (including Capital Lease
Obligations) permitted by clause (4) of the second paragraph
of the covenant entitled "-- Certain Covenants -- Incurrence
of Indebtedness and Issuance of Preferred Stock" covering only
the assets acquired with such Indebtedness;
(12) Liens existing on the date of the indenture;
(13) Liens for taxes, assessments or other governmental charges or
claims that are not yet due and payable or, if due and payable
and delinquent, that are being contested by Compton or a
Restricted Subsidiary in good faith by appropriate proceedings
promptly instituted and diligently concluded, PROVIDED that
any reserve or other appropriate provision as is required in
conformity with GAAP has been made therefor; and
(14) Liens in pipelines or pipeline facilities that arise by
operation of law;
(15) Liens arising in the ordinary course of business under
operating agreements, joint venture agreements, partnership
agreements, oil and gas leases, farm-out agreements, division
orders, contracts for the sale transportation or exchange of
oil or natural gas, unitization and pooling declarations and
agreements, area of mutual interest agreements and other
agreements (including in respect of Production Payments), or
arising by operation of law, that are customary in the Oil and
Gas Business, and easements, rights of way or other similar
rights in land in the ordinary course of business and that do
not involve borrowing of money;
(16) Liens reserved in oil and gas mineral leases for bonus or
rental payments and for compliance with the terms of such
leases;
(17) Liens incurred in the ordinary course of business of Compton
or any Subsidiary of Compton with respect to obligations that
do not in the aggregate exceed US$5.0 million at any one time
outstanding; and
(18) Liens securing Permitted Refinancing Indebtedness in respect
of Permitted Debt that was secured by Permitted Liens above
and securing similar property.
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"PERMITTED REFINANCING INDEBTEDNESS" means any Indebtedness of Compton
or any of its Restricted Subsidiaries issued in exchange for, or the
net proceeds of which are used to extend, refinance, renew, replace,
defease or refund other Indebtedness of Compton or any of its
Restricted Subsidiaries (other than intercompany Indebtedness);
PROVIDED that:
(1) the principal amount (or accreted value, if applicable) of
such Permitted Refinancing Indebtedness does not exceed the
principal amount (or accreted value, if applicable) of the
Indebtedness extended, refinanced, renewed, replaced, defeased
or refunded (plus all accrued interest on the Indebtedness and
the amount of all expenses and premiums incurred in connection
therewith);
(2) such Permitted Refinancing Indebtedness has a final maturity
date later than the final maturity date of, and has a Weighted
Average Life to Maturity equal to or greater than the Weighted
Average Life to Maturity of, the Indebtedness being extended,
refinanced, renewed, replaced, defeased or refunded;
(3) if the Indebtedness being extended, refinanced, renewed,
replaced, defeased or refunded is subordinated in right of
payment to the notes, such Permitted Refinancing Indebtedness
has a final maturity date later than the final maturity date
of, and is subordinated in right of payment to, the notes on
terms at least as favorable to the Holders of notes as those
contained in the documentation governing the Indebtedness
being extended, refinanced, renewed, replaced, defeased or
refunded; and
(4) such Indebtedness is incurred either by Compton or by the
Restricted Subsidiary who is the obligor on the Indebtedness
being extended, refinanced, renewed, replaced, defeased or
refunded.
"PRODUCTION PAYMENTS" means Dollar-Denominated Production Payments and
Volumetric Production Payments, collectively.
"RESTRICTED INVESTMENT" means an Investment other than a Permitted
Investment.
"RESTRICTED SUBSIDIARY" of a Person means any Subsidiary of such Person
that is not an Unrestricted Subsidiary.
"SIGNIFICANT SUBSIDIARY" means any Subsidiary that would be a
"significant subsidiary" as defined in Article 1, Rule 1-02 of
Regulation S-X, promulgated pursuant to the Securities Act, as such
Regulation is in effect on the date hereof.
"STATED MATURITY" means, with respect to any installment of interest or
principal on any series of Indebtedness, the date on which the payment
of interest or principal was scheduled to be paid in the original
documentation governing such Indebtedness, and will not include any
contingent obligations to repay, redeem or repurchase any such interest
or principal prior to the date originally scheduled for the payment
thereof.
"SUBSIDIARY" means, with respect to any specified Person:
(1) any corporation, association or other business entity of which
more than 50% of the total voting power of shares of Capital
Stock entitled (without regard to the occurrence of any
contingency) to vote in the election of directors, managers or
trustees of the corporation, association or other business
entity is at the time owned or controlled, directly or
indirectly, by that Person or one or more of the other
Subsidiaries of that Person (or a combination thereof); and
(2) any partnership (a) the sole general partner or the managing
general partner of which is such Person or a Subsidiary of
such Person or (b) the only general partners of which are that
Person or one or more Subsidiaries of that Person (or any
combination thereof).
"UNRESTRICTED SUBSIDIARY" means any Subsidiary of Compton that is
designated by the Board of Directors of Compton as an Unrestricted
Subsidiary pursuant to a Board Resolution, but only to the extent that
such Subsidiary:
(1) has no Indebtedness other than Non-Recourse Debt;
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(2) is not party to any agreement, contract, arrangement or
understanding with Compton or any Restricted Subsidiary of
Compton unless the terms of any such agreement, contract,
arrangement or understanding are no less favorable to Compton
or such Restricted Subsidiary than those that might be
obtained at the time from Persons who are not Affiliates of
Compton;
(3) is a Person with respect to which neither Compton nor any of
its Restricted Subsidiaries has any direct or indirect
obligation (a) to subscribe for additional Equity Interests or
(b) to maintain or preserve such Person's financial condition
or to cause such Person to achieve any specified levels of
operating results;
(4) has not guaranteed or otherwise directly or indirectly
provided credit support for any Indebtedness of Compton or any
of its Restricted Subsidiaries; and
(5) has at least one director on its Board of Directors that is
not a director or executive officer of Compton or any of its
Restricted Subsidiaries and has at least one executive officer
that is not a director or executive officer of Compton or any
of its Restricted Subsidiaries.
Any designation of a Subsidiary of Compton as an Unrestricted
Subsidiary will be evidenced to the trustee by filing with the trustee
a certified copy of the Board Resolution giving effect to such
designation and an officers' certificate certifying that such
designation complied with the preceding conditions and was permitted by
the covenant described above under the caption "-- Certain Covenants --
Restricted Payments". If, at any time, any Unrestricted Subsidiary
would fail to meet the preceding requirements as an Unrestricted
Subsidiary, it will thereafter cease to be an Unrestricted Subsidiary
for purposes of the indenture and any Indebtedness of such Subsidiary
will be deemed to be incurred by a Restricted Subsidiary of Compton as
of such date and, if such Indebtedness is not permitted to be incurred
as of such date under the covenant described under the caption "--
Certain Covenants -- Incurrence of Indebtedness and Issuance of
Preferred Stock", Compton will be in default of such covenant. The
Board of Directors of Compton may at any time designate any
Unrestricted Subsidiary to be a Restricted Subsidiary; PROVIDED that
such designation will be deemed to be an incurrence of Indebtedness by
a Restricted Subsidiary of Compton of any outstanding Indebtedness of
such Unrestricted Subsidiary and such designation will only be
permitted if (1) such Indebtedness is permitted under the covenant
described under the caption "-- Certain Covenants -- Incurrence of
Indebtedness and Issuance of Preferred Stock", calculated on a pro
forma basis as if such designation had occurred at the beginning of the
four-quarter reference period; (2) no Default or Event of Default would
be in existence following such designation; and (3) such Unrestricted
Subsidiary becomes a Guarantor and executes a supplemental indenture
and delivers an opinion of counsel reasonably satisfactory to the
trustee within 10 Business Days of the date on which it is designated
to the effect that such supplemental indenture has been duly
authorized, executed and delivered and constitutes a legal, valid and
binding agreement of such Subsidiary, enforceable against such
Subsidiary in accordance with its terms.
"VOLUMETRIC PRODUCTION PAYMENTS" means production payment obligations
recorded as deferred revenue in accordance with GAAP, together with all
undertakings and obligations in connection therewith.
"VOTING STOCK" of any Person as of any date means the Capital Stock of
such Person that is at the time entitled to vote in the election of the
Board of Directors of such Person.
"WEIGHTED AVERAGE LIFE TO MATURITY" means, when applied to any
Indebtedness at any date, the number of years obtained by dividing:
(1) the sum of the products obtained by multiplying (a) the amount
of each then remaining installment, sinking fund, serial
maturity or other required payments of principal, including
payment at final maturity, in respect of the Indebtedness, by
(b) the number of years (calculated to the nearest
one-twelfth) that will elapse between such date and the making
of such payment; by
(2) the then outstanding principal amount of such Indebtedness.
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DESCRIPTION OF THE INITIAL NOTES
The initial notes were issued and sold on May 8, 2002, in a private
transaction that was exempt from the registration requirements of the Securities
Act. The form and terms of the initial notes are the same as the form and terms
of the exchange notes, except that:
o the initial notes are not registered under the Securities Act
and bear legends restricting their transfer, and
o holders of initial notes have rights under a registration
rights agreement which will terminate upon the consummation of
the exchange offer.
Please refer to the section of this prospectus entitled "Description of
the Exchange Notes".
BOOK-ENTRY, DELIVERY AND FORM
Except as described below, we will initially issue the exchange notes
in the form of one or more registered exchange notes in global form without
coupons. We will deposit each global note on the date of the closing of this
exchange offer with, or on behalf of, The Depository Trust Company in New York,
New York, and register the exchange notes in the name of The Depository Trust
Company or its nominee, or will leave these notes in the custody of the trustee.
DEPOSITORY TRUST COMPANY PROCEDURES
For your convenience, we are providing you with a description of the
operations and procedures of The Depository Trust Company, the Euroclear System
and Clearstream Banking, S.A. These operations and procedures are solely within
the control of the respective settlement systems and are subject to changes by
them. We are not responsible for these operations and procedures and urge you to
contact the system or its participants directly to discuss these matters.
The Depository Trust Company has advised us that it is a
limited-purpose trust company created to hold securities for its participating
organizations and to facilitate the clearance and settlement of transactions in
those securities between its participants through electronic book entry changes
in the accounts of these participants. These direct participants include
securities brokers and dealers, banks, trust companies, clearing corporations
and other organizations. Access to The Depository Trust Company's system is also
indirectly available to other entities that clear through or maintain a direct
or indirect, custodial relationship with a direct participant. The Depository
Trust Company may hold securities beneficially owned by other persons only
through its participants and the ownership interests and transfers of ownership
interests of these other persons will be recorded only on the records of the
participants and not on the records of The Depository Trust Company.
The Depository Trust Company has also advised us that, in accordance
with its procedures:
(1) upon deposit of the global notes, it will credit the accounts
of the direct participants with an interest in the global
notes; and
(2) it will maintain records of the ownership interests of these
direct participants in the global notes and the transfer of
ownership interests by and between direct participants.
The Depository Trust Company will not maintain records of the ownership
interests of, or the transfer of ownership interests by and between, indirect
participants or other owners of beneficial interests in the global notes. Both
direct and indirect participants must maintain their own records of ownership
interests of, and the transfer of ownership interests by and between, indirect
participants and other owners of beneficial interests in the global notes.
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Investors in the global notes may hold their interests in the notes
directly through The Depository Trust Company if they are direct participants in
The Depository Trust Company or indirectly through organizations that are direct
participants in The Depository Trust Company. Investors in the global notes may
also hold their interests in the notes through Euroclear and Clearstream if they
are direct participants in those systems or indirectly through organizations
that are participants in those systems. Euroclear and Clearstream will hold
omnibus positions in the global notes on behalf of the Euroclear participants
and the Clearstream participants, respectively, through customers' securities
accounts in Euroclear's and Clearstream's names on the books of their respective
depositories, which are Morgan Guaranty Trust Company of New York, Brussels
office, as operator of Euroclear, and Citibank, N.A. and The Chase Manhattan
Bank, N.A., as operators of Clearstream. These depositories, in turn, will hold
these positions in their names on the books of DTC. All interests in a global
note, including those held through Euroclear or Clearstream, may be subject to
the procedures and requirements of The Depository Trust Company. Those interests
held through Euroclear or Clearstream may also be subject to the procedures and
requirements of those systems.
The laws of some states require that some persons take physical
delivery in definitive certificated form of the securities that they own. This
may limit or curtail the ability to transfer beneficial interests in a global
note to these persons. Because The Depository Trust Company can act only on
behalf of direct participants, which in turn act on behalf of indirect
participants and others, the ability of a person having a beneficial interest in
a global note to pledge its interest to persons or entities that are not direct
participants in The Depository Trust Company or to otherwise take actions in
respect of its interest, may be affected by the lack of physical certificates
evidencing the interests.
Except as described below, owners of interests in the global notes will
not have notes registered in their names, will not receive physical delivery of
notes in certificated form and will not be considered the registered owners or
holders of these notes under the indenture for any purpose.
Payments with respect to the principal of and interest on any notes
represented by a global note registered in the name of The Depository Trust
Company or its nominee on the applicable record date will be payable by the
trustee to or at the direction of The Depository Trust Company or its nominee in
its capacity as the registered holder of the global note representing these
notes under the indenture. Under the terms of the indenture, we and the trustee
will treat the person in whose names the notes are registered, including notes
represented by global notes, as the owners of the notes for the purpose of
receiving payments and for any and all other purposes whatsoever. Payments in
respect of the principal and interest on global notes registered in the name of
The Depository Trust Company or its nominee will be payable by the trustee to
The Depository Trust Company or its nominee as the registered holder under the
indenture. Consequently, none of the trustee or any of our agents, or the
trustee's agents has or will have any responsibility or liability for:
(1) any aspect of The Depository Trust Company's records or any
direct or indirect participant's records relating to, or
payments made on account of, beneficial ownership interests in
the global notes or for maintaining, supervising or reviewing
any of The Depository Trust Company's records or any direct or
indirect participant's records relating to the beneficial
ownership interests in any global note; or
(2) any other matter relating to the actions and practices of The
Depository Trust Company or any of its direct or indirect
participants.
The Depository Trust Company has advised us that its current practice,
upon receipt of any payment in respect of securities such as the notes,
including principal and interest, is to credit the accounts of the relevant
participants with the payment on the payment date, in amounts proportionate to
their respective holdings in the principal amount of beneficial interest in the
security as shown on its records, unless it has reasons to believe that it will
not receive payment on the payment date. Payments by the direct and indirect
participants to the beneficial owners of interests in the global note will be
governed by standing instructions and customary practice and will be the
responsibility of the direct or indirect participants and will not be the
responsibility of The Depository Trust Company, the trustee or us.
Neither we nor the trustee will be liable for any delay by The
Depository Trust Company or any direct or indirect participant in identifying
the beneficial owners of the notes and the exchange agent and the trustee may
conclusively rely on, and will be protected in relying on, instructions from The
Depository Trust Company or its nominee for all purposes, including with respect
to the registration and delivery, and the respective principal amounts, of the
notes.
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Transfers between participants in The Depository Trust Company will be
effected in accordance with The Depository Trust Company's procedures, and will
be settled in same day funds, and transfers between participants in Euroclear
and Clearstream will be effected in accordance with their respective rules and
operating procedures.
Cross-market transfers between the participants in The Depository Trust
Company, on the one hand, and Euroclear or Clearstream participants, on the
other hand, will be effected through The Depository Trust Company in accordance
with The Depository Trust Company's rules on behalf of Euroclear or Clearstream,
as the case may be, by its respective depositary; however, such cross-market
transactions will require delivery of instructions to Euroclear or Clearstream,
as the case may be, by the counterparty in such system in accordance with the
rules and procedures and within the established deadlines (Brussels time) of
such system. Euroclear or Clearstream, as the case may be, will, if the
transaction meets its settlement requirements, deliver instructions to its
respective depositary to take action to effect final settlement on its behalf by
delivering or receiving interests in the relevant global note in The Depository
Trust Company, and making or receiving payment in accordance with normal
procedures for same-day funds settlement applicable to The Depository Trust
Company. Euroclear participants and Clearstream participants may not deliver
instructions directly to the depositories for Euroclear or Clearstream.
The Depository Trust Company has advised us that it will take any
action permitted to be taken by a holder of notes only at the direction of one
or more participants to whose account The Depository Trust Company has credited
the interests in the global notes and only in respect of the portion of the
aggregate principal amount of the notes as to which the participant or
participants has or have given that direction. However, if there is an event of
default with respect to the notes, The Depository Trust Company reserves the
right to exchange the global notes for legended notes in certificated form and
to distribute them to its participants.
Although The Depository Trust Company, Euroclear and Clearstream have
agreed to these procedures to facilitate transfers of interests in the global
notes among participants in The Depository Trust Company, Euroclear and
Clearstream, they are under no obligation to perform or to continue to perform
these procedures and may discontinue them at any time. None of the trustee or
any of our or the trustee's respective agents will have any responsibility for
the performance by The Depository Trust Company, Euroclear or Clearstream or
their direct or indirect participants of their respective obligations under the
rules and procedures governing their operations.
EXCHANGE OF BOOK-ENTRY NOTES FOR CERTIFICATED NOTES
A global note will be exchangeable for definitive notes in registered
certificated form if:
(1) The Depository Trust Company notifies us that it is unwilling
or unable to continue as depository for the global notes or if
it ceases to be a clearing agency registered under the
Exchange Act and we fail to appoint a successor depository
within 120 days;
(2) we, in our sole discretion, determine that the global notes
should be exchanged for definitive notes; or
(3) a default or an event of default under the indenture for the
notes has occurred and is continuing.
In all cases, certificated notes delivered in exchange for any global
note or beneficial interests in a global note will be registered in the name,
and issued in any approved denominations, requested by or on behalf of The
Depository Trust Company, in accordance with its customary procedures.
EXCHANGE OF CERTIFICATED NOTES FOR BOOK-ENTRY NOTES
Initial notes issued in certificated form may be exchanged for
beneficial interests in the global note.
SAME DAY SETTLEMENT
We expect that the interests in the global notes will be eligible to
trade in The Depository Trust Company's Same-Day Funds Settlement System. As a
result, secondary market trading activity in these interests will settle in
immediately
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available funds, subject in all cases to the rules and procedures of The
Depository Trust Company and its participants. We expect that secondary trading
in any certificated notes will also be settled in immediately available funds.
Because of time zone differences, the securities account of a Euroclear
or Clearstream participant purchasing an interest in a global note from a
participant in The Depository Trust Company will be credited, and any such
crediting will be reported to the relevant Euroclear or Clearstream participant,
during the securities settlement processing day (which must be a business day
for Euroclear and Clearstream) immediately following the settlement date of The
Depository Trust Company. The Depository Trust Company has advised us that cash
received in Euroclear or Clearstream as a result of sales of interests in a
global note by or through a Euroclear or Clearstream participant to a
participant in The Depository Trust Company will be received with value on the
settlement date of The Depository Trust Company but will be available in the
relevant Euroclear or Clearstream cash account only as of the business day for
Euroclear or Clearstream following The Depository Trust Company's settlement
date.
PAYMENT
The indenture requires that payments in respect of the notes
represented by global notes, including principal and interest, be made by wire
transfer of immediately available funds to the accounts specified by the holder
of the global notes. With respect to notes in certificated form, we will make
all payments of principal and interest on the notes at our office or agency
maintained for that purpose within the city and state of New York. This office
will initially be the office of the Paying Agent maintained for that purpose. At
our option however, we may make these installments of interest by
(1) check mailed to the holders of notes at their respective
addresses provided in the register of holder of notes; or
(2) transfer to an account maintained by the payee.
MATERIAL INCOME TAX CONSIDERATIONS
THE FOLLOWING SUMMARY IS OF A GENERAL NATURE ONLY AND IS NOT INTENDED
TO BE, AND SHOULD NOT BE CONSTRUED TO BE, LEGAL OR TAX ADVICE TO ANY PROSPECTIVE
INVESTOR AND NO REPRESENTATION WITH RESPECT TO THE TAX CONSEQUENCES TO ANY
PARTICULAR INVESTOR IS MADE. ACCORDINGLY, PROSPECTIVE INVESTORS ARE URGED TO
CONSULT WITH THEIR OWN TAX ADVISORS FOR ADVICE WITH RESPECT TO THE INCOME TAX
CONSEQUENCES TO THEM, HAVING REGARD TO THEIR OWN PARTICULAR CIRCUMSTANCES,
INCLUDING ANY CONSEQUENCES OF AN INVESTMENT IN THE NOTES OR THE EXCHANGE NOTES
ARISING UNDER STATE, PROVINCIAL OR LOCAL TAX LAWS OR TAX LAWS OF JURISDICTIONS
OUTSIDE THE UNITED STATES OR CANADA.
CANADIAN FEDERAL INCOME TAX CONSIDERATIONS
In the opinion of Fraser Milner Casgrain LLP, our Canadian legal
counsel, the following is, as of the date of this prospectus, a fair and
adequate opinion of the principal Canadian federal income tax consequences to a
holder of the notes who is a non-resident of Canada. This opinion is based on
the current provisions of the INCOME TAX ACT (Canada) and the regulations under
that Act, counsel's understanding of the current published administrative
practices of Canada Customs and Revenue Agency, and all specific proposals to
amend the INCOME TAX ACT (Canada) and the regulations announced by the Minister
of Finance prior to the date of this prospectus. This opinion does not otherwise
take into account or anticipate changes in the law, whether by judicial,
governmental or legislative decisions or action, nor does it take into account
tax legislation or considerations of any province or territory of Canada or any
jurisdiction other than Canada.
This opinion assumes that, throughout the period the notes are
outstanding, Compton will deal with the holders of notes (including DTC) at
arm's length within the meaning of the INCOME Tax ACT (Canada), and that Compton
will not, under any circumstances, be obliged to pay more than 25% of the
aggregate principal amount of the notes within five years from the later of the
date of issue or the date funds are advanced, except in the event of a default
under the terms of the notes or of any agreement relating to the notes or if the
terms of the notes or any such agreement become unlawful or are changed by
legislative, judicial or administrative action.
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The payment by Compton of interest or principal on the notes to a
holder who is a non-resident of Canada and with whom Compton deals at arm's
length within the meaning of the INCOME TAX ACT (Canada), at the time amounts
are payable, in the case of interest, or at the time the payments are made, in
the case of principal, will be exempt from Canadian withholding tax. For the
purposes of the INCOME TAX ACT (Canada), related persons (as defined in the
INCOME TAX ACT (Canada)) are deemed not to deal at arm's length and it is a
question of fact whether persons not related to each other deal at arm's length.
No other taxes on income (including taxable capital gains) will be
payable under the INCOME TAX ACT (Canada) on the holding, redemption or
disposition of the notes, or the receipt of interest on the notes by holders who
are neither residents nor deemed to be residents of Canada for the purposes of
the INCOME TAX ACT (Canada) and who do not use or hold and are not deemed by
those laws to use or hold the notes in carrying on business in Canada for the
purposes of the INCOME TAX ACT (Canada), except that in some circumstances
holders who are non-resident insurers carrying on an insurance business in
Canada and elsewhere may be subject to those taxes.
U.S. FEDERAL INCOME TAX CONSIDERATIONS
In the opinion of Paul, Weiss, Rifkind, Wharton & Garrison, our United
States special counsel, the following is a summary of the material United States
federal income tax consequences of the exchange of initial notes for exchange
notes in accordance with the exchange offer and of the ownership and disposition
of those exchange notes by United States persons (as defined below) who acquire
the exchange notes in the exchange offer. This discussion assumes that United
States persons hold the exchange notes as capital assets ("United States
Holders") within the meaning of Section 1221 of the Internal Revenue Code of
1986, as amended (the "Code"). Furthermore, the following discussion does not
purport to be a complete analysis of all of the potential United States federal
income tax considerations that may be relevant to particular holders of exchange
notes in light of their particular circumstances nor does it deal with persons
that are subject to special tax rules, such as dealers in securities or
currencies, financial institutions, insurance companies, tax-exempt
organizations, persons holding the initial notes or exchange notes as part of a
straddle, hedge or conversion transaction or a synthetic security or other
integrated transaction, holders whose "functional currency" is not the United
States dollar, and holders who are not United States Holders. In addition, the
discussion below does not address tax consequences applicable to subsequent
purchasers of the exchange notes nor does it address the tax consequences of the
law of any state, locality or foreign jurisdiction. There can be no assurance
that the United States Internal Revenue Service ("IRS") will take a similar view
as to any of the tax consequences described in this summary.
The following is based on currently existing provisions of the Code,
existing and proposed Treasury regulations under the Code and current
administrative rulings and court decisions. Everything listed in the previous
sentence may change, possibly on a retroactive basis, and any change could
affect the continuing validity of this discussion.
PERSONS CONSIDERING THE PURCHASE, OWNERSHIP OR DISPOSITION OF NOTES ARE
URGED TO CONSULT THEIR OWN TAX ADVISORS CONCERNING THE U.S. FEDERAL INCOME TAX
CONSEQUENCES APPLICABLE TO THEM IN LIGHT OF THEIR PARTICULAR SITUATION AS WELL
AS ANY CONSEQUENCES ARISING UNDER THE LAWS OF ANY STATE, LOCAL OR FOREIGN TAXING
JURISDICTION.
As used in this section, the term "United States person" means a
beneficial owner of a note that is: (i) a citizen or resident of the United
States, (ii) a corporation created or organized in or under the laws of the
United States or any political subdivision of the United States; (iii) an estate
the income of which is subject to United States federal income taxation
regardless of its source; or (iv) a trust which is (A) subject to the
supervision of a court within the United States and the control of a United
States fiduciary as described in Section 7701(a)(30) of the Code; or (B) has
made a valid election to be treated as a United States person.
EXCHANGE OF INITIAL NOTES FOR EXCHANGE NOTES
The exchange of initial notes for exchange notes pursuant to the
exchange offer will not constitute a recognition event for U.S. federal income
tax purposes. Consequently, (1) no gain or loss will be realized by a United
States Holder upon receipt of an exchange note, (2) the holding period of the
exchange note will include the holding period of the initial note exchanged for
the exchange note, (3) the adjusted tax basis of the exchange note will be the
same as the adjusted tax basis of the initial note exchanged therefor
immediately before the exchange and (4) any market discount or bond premium
(discussed below) applicable to the initial notes should carry over to the
exchange notes. Further, the tax consequences of ownership and disposition of
any exchange note should be the same as the tax consequences of ownership and
disposition of an initial note.
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PAYMENTS OF INTEREST
Interest on a note will generally be taxable to a United States Holder
as ordinary income at the time it is paid or accrued in accordance with the
United States Holder's method of accounting for tax purposes. In addition to
interest on the notes, a United States Holder will be required to include in
income any additional amounts received pursuant to the section of this
prospectus entitled "The Exchange Notes - Redemption for Changes in Canadian
Withholding Taxes" and any taxes withheld from interest payments,
notwithstanding that the United States Holder does not in fact receive such
withheld taxes.
A United States Holder may be entitled to claim a credit against its
U.S. federal income tax liability, or a deduction in computing its U.S. federal
taxable income, for Canadian income taxes withheld and paid over to the Canadian
taxing authorities or for any of those taxes paid directly to the Canadian
taxing authorities. The rules governing the foreign tax credit are complex.
Investors are urged to consult their tax advisors regarding the availability of
the foreign tax credit under their particular circumstances. Interest income on
an exchange note generally will constitute foreign source income and generally
will be considered "passive" income or "financial services" income (or, if
Canadian withholding tax at a rate of 5% or more were to be imposed, as "high
withholding tax interest"), which are treated separately from other types of
income in computing the foreign tax credit allowable to United States Holders
under the Code.
MARKET DISCOUNT AND BOND PREMIUM
If a United States Holder purchased an initial note after its initial
issuance for an amount that is less than its principal amount, then, subject to
a statutory de minimis rule, the difference generally will be treated as market
discount. If a United States Holder exchanges an initial note, with respect to
which there is market discount, for an exchange note pursuant to the exchange
offer, the market discount applicable to the initial note should carry over to
the exchange note so received. In that case, any partial principal payment on,
or any gain realized on the sale, exchange, retirement or other disposition of,
including dispositions which are nonrecognition transactions under certain
provisions of the Code, the exchange note will be included in gross income and
characterized as ordinary income to the extent of the market discount that (1)
has not previously been included in income and (2) is treated as having accrued
on the exchange note prior to the payment or disposition. In addition, to the
extent that the exchange notes are acquired with market discount, a United
States Holder generally may be required to defer a portion of the interest
expense on indebtedness incurred or continued to purchase or carry such notes.
Market discount generally accrues on a straight-line basis over the remaining
term of the exchange note. A taxpayer may elect, however, to accrue market
discount on a constant yield basis. Further, a United States Holder may elect to
include market discount in gross income currently as it accrues. If such an
election is made, the preceding rules relating to the recognition of market
discount and deferral of interest expense will not apply. An election made to
include market discount in gross income as it accrues will apply to all debt
instruments acquired by the United States Holder on or after the first day of
the taxable year to which the election applies and may be revoked only with the
consent of the IRS.
If a United States Holder purchased an initial note for an amount in
excess of principal, the excess will be treated as bond premium. If a United
States Holder exchanges an initial note, with respect to which there is bond
premium, for an exchange note pursuant to the exchange offer, the bond premium
applicable to the initial note should carry over to the exchange note so
received. In general, a United States Holder may elect to amortize bond premium
over the remaining term of the exchange note on a constant yield method. An
election to amortize bond premium applies to all taxable debt instruments held
at the beginning of the first taxable year to which the election applies and
thereafter acquired by the United States Holder and may be revoked only with the
consent of the IRS.
SALE, EXCHANGE AND REDEMPTION OF NOTES
Upon the sale, exchange or redemption of an exchange note, a United
States Holder will recognize gain or loss equal to the difference between the
amount realized upon the sale, exchange or redemption (less any accrued
interest, which will be taxable as ordinary interest income) and the United
States Holder's adjusted tax basis in the exchange note. A United States
Holder's adjusted tax basis in a note generally will be the adjusted tax basis
of such holder in the initial note that was exchanged therefor, increased by
market discount, if any, that is included in such holder's income and reduced
(but not below zero) by any amortized bond premium which a United States Holder
has elected to deduct from taxable income on an annual basis. If a United States
Holder exchanges an initial note, with respect to which there is market discount
or bond premium, for an exchange note pursuant to the exchange offer, the market
discount or bond premium applicable to the initial note should carry over to the
exchange note so received. In general, market discount on an initial note is the
excess, if any, of the principal amount of an initial note over the United
States Holder's tax basis in such initial note at the time of acquisition
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(unless the amount of such excess is less than a specified DE MINIMIS amount, in
which case market discount is considered to be zero). In general, bond premium
on an initial note equals the excess, if any, of the purchase price of the
initial note over the amount payable at maturity of the initial note (other than
stated interest thereon). Except as provided above (see "Market Discount and
Bond Premium"), gain or loss realized on the sale, exchange or redemption of an
exchange note will be capital gain or loss and will be long-term capital gain or
loss if at the time of sale, exchange or retirement the exchange note has been
held for more than one year. Under current law, net capital gains of individuals
are, under some circumstances, taxed at lower rates than items of ordinary
income. The deductibility of capital losses is subject to limitations. If the
United States Holder is a U.S. resident (as defined in section 865 of the Code),
gains realized upon disposition of an exchange note by such United States Holder
generally will be U.S. source income, and disposition losses generally will be
allocated to reduce U.S. source income.
INFORMATION REPORTING AND BACKUP WITHHOLDING
In general, information reporting requirements will apply to certain
payments of principal and interest on a note and to the payments of proceeds of
the sale of an exchange note made to United States Holders other than certain
exempt recipients (such as corporations). A United States Holder that is not an
exempt recipient will generally be subject to backup withholding with respect to
such payments (currently at a rate of 30%, declining until 2006 to 28%, which
rate will remain constant until replaced by a 31% rate beginning in 2011) unless
the United States Holder provides an accurate taxpayer identification number and
otherwise complies with applicable requirements of the backup withholding rules.
Any amounts withheld under the backup withholding rules will be allowed
as a credit against the United States Holder's U.S. federal income tax liability
or refundable to the extent that it exceeds such liability. A United States
Holder who does not provide a correct taxpayer identification number may be
subject to penalties imposed by the IRS.
THE U.S. FEDERAL INCOME TAX DISCUSSION PROVIDED ABOVE IS INCLUDED FOR
GENERAL INFORMATION ONLY AND MAY OR MAY NOT APPLY TO YOU DEPENDING UPON YOUR
PARTICULAR SITUATION. YOU ARE URGED TO CONSULT YOUR OWN TAX ADVISOR WITH RESPECT
TO THE TAX CONSEQUENCES TO YOU OF OWNING, HOLDING, AND DISPOSING OF A NOTE,
INCLUDING THE TAX CONSEQUENCES UNDER STATE, LOCAL, FOREIGN, AND OTHER TAX LAWS
AND THE POSSIBLE EFFECTS OF CHANGES IN FEDERAL OR OTHER TAX LAWS.
PLAN OF DISTRIBUTION
Each broker-dealer that receives exchange notes for its own account
pursuant to the exchange offer in exchange for initial notes acquired by such
broker-dealer as a result of market making or other trading activities maybe
deemed to be an "underwriter" within the meaning of the Securities Act and,
therefore, must deliver a prospectus meeting the requirements of the Securities
Act in connection with any resales, offers to resell or other transfers of the
exchange notes received by it in connection with the exchange offer.
Accordingly, each such broker-dealer must acknowledge that it will deliver a
prospectus meeting the requirements of the Securities Act in connection with any
resale of such exchange notes. The letter of transmittal states that by
acknowledging that it will deliver and by delivering a prospectus, a
broker-dealer will not be deemed to admit that it is an "underwriter" within the
meaning of the Securities Act. This prospectus, as it may be amended or
supplemented from time to time, may be used by a broker-dealer in connection
with resales of exchange notes received in exchange for initial notes where such
initial notes were acquired as a result of market-making activities or other
trading activities. We have agreed that, for a period of 180 days after the
expiration of this exchange offer, we will make this prospectus, as amended or
supplemented, available to any broker-dealer for use in connection with any such
resale.
We will not receive any proceeds from any sale of exchange notes by
broker-dealers. Exchange notes received by broker-dealers for their own account
pursuant to the exchange offer may be sold from time to time in one or more
transactions in the over-the-counter market, in negotiated transactions, through
the writing of options on the exchange notes or a combination of such methods of
resale, at market prices prevailing at the time of resale, at prices related to
such prevailing market prices or negotiated prices. Any such resale may be made
directly to purchasers or to or through brokers or dealers who may receive
compensation in the form of commissions or concessions from any such
broker-dealer and/or the purchasers of any such exchange notes. Any
broker-dealer that resells exchange notes that were received by it for its own
account pursuant to the exchange offer and any broker or dealer that
participates in a distribution of such exchange notes may be deemed to be an
"underwriter" within the meaning of the Securities Act and any profit of any
such resale of exchange
-100-
notes and any commissions or concessions received by any such persons may be
deemed to be underwriting compensation under the Securities Act. The letter of
transmittal states that by acknowledging that it will deliver and by delivering
a prospectus, a broker-dealer will not be deemed to admit that it is an
"underwriter" within the meaning of the Securities Act.
LEGAL MATTERS
Legal matters in connection with the exchange offer will be passed upon
for us by Paul, Weiss, Rifkind, Wharton & Garrison, New York, New York
(concerning matters of U.S. law) and Fraser Milner Casgrain LLP, Calgary,
Alberta (concerning matters of Canadian law). The partners of Paul, Weiss,
Rifkind, Wharton & Garrison beneficially own less than 1% of our outstanding
shares and the partners of Fraser Milner Casgrain LLP beneficially own less than
1% of our outstanding shares.
INDEPENDENT PETROLEUM ENGINEERS
Information about our estimated proved reserves and the future net cash
flows attributable to these reserves as of December 31, 1999 and 2000 was
prepared or reviewed by Outtrim Szabo Associates Ltd. The reserve information as
of December 31, 2001 was prepared by Outtrim Szabo Associates Ltd.
INDEPENDENT ACCOUNTANTS
The financial statements of Compton, as of December 31, 1999, 2000 and
2001 and for each of the years in the periods ended December 31, 1999, 2000 and
2001, included in this prospectus have been audited by Grant Thornton LLP,
Chartered Accountants, as stated in their report appearing herein.
WHERE YOU CAN FIND MORE INFORMATION
We have filed a registration statement on Form F-4 with the Commission
covering the exchange notes. This prospectus is part or our registration
statement. For further information about us and the exchange notes, you should
refer to our registration statement and its exhibits. This prospectus summarizes
material provisions of contracts and other documents to which we refer you.
Since the prospectus might not contain all of the information that you might
find important, you should review the full text of these documents. We have
included copies of these documents as exhibits to our registration statement.
We file information, such as periodic reports and financial
information, with the Canadian Securities Administrators, which may be accessed
at www.sedar.com. Upon filing of this registration statement, we will be subject
to the periodic reporting and other informational requirements of the Exchange
Act, and accordingly we will file reports and other information with the
Commission. Copies of such reports and other information will be available for
inspection and can be copied at the public reference facilities maintained by
the Commission. Copies of these materials may also be obtained by mail at
prescribed rates from the Public Reference Section of the Commission, 450 Fifth
Street, N.W., Washington, D.C. 20549 or by calling the Commission at
l-800-SEC-0330. Our filings with the SEC will also be available to the public
from commercial document retrieval services and at the SEC's web site at
"http://www.sec.gov". However, we are a "foreign private issuer" as defined in
Rule 405 of the Securities Act, and therefore are not required to comply with
Exchange Act provisions regarding proxy statements and short swing profit
disclosure.
Anyone who receives a copy of this prospectus may obtain a copy of the
indenture without charge by writing to: Compton Petroleum Corporation, Suite
3300, 425--1st Street S.W., Calgary, Alberta, Canada, T2P 3L8, Attn: Corporate
Secretary.
-101-
In the indenture for the notes we have agreed that, whether or not we
are required to do so by the rules and regulations of the Commission, for so
long as any of the notes are outstanding, we will furnish the trustee and
holders of notes with:
o all quarterly and annual financial information that would be
required to be contained in a submission to the Commission on
Forms 40-F and 6-K if we were required to file or furnish such
forms;
o a report on the financial information by our certified
independent accountants, with respect to our annual financial
information only; and
o all reports that would be required to be filed with the
Commission on Form 6-K if we were required to file such
reports.
In addition, for so long as any of the initial notes remain outstanding
and are "restricted securities" within the meaning of Rule l44(a)(3) of the
Securities Act, we have agreed to make available to any holder or beneficial
owner of the notes or any prospective purchaser of the notes designated by a
holder or beneficial owner of the notes, in connection with any sale of the
notes, the information required by Rule l44A(d)(4) under the Securities Act,
unless we furnish information to the Commission in accordance with Rule
12g-3-2(b) or under Section 13 or 15(d) of the Exchange Act.
-102-
FINANCIAL STATEMENTS
INDEX
FINANCIAL STATEMENTS OF COMPTON PETROLEUM CORPORATION
Report of Independent Auditors........................................ F-2
Consolidated Balance Sheets-- December 31, 2000 and 2001 and June 30,
2002.............................................................. F-3
Consolidated Statements of Earnings and Retained
Earnings-- Years Ended December 31, 1999, 2000 and 2001 and Six
Months Ended June 30, 2001 and 2002............................... F-4
Consolidated Statements of Cash Flow -- Years Ended
December 31, 1999, 2000 and 2001 and Six Months Ended
June 30, 2001 and 2002............................................ F-5
Notes to the Consolidated Financial Statements........................ F-6
F-1
INDEPENDENT AUDITORS' REPORT
To the Board of Directors and Shareholders of
Compton Petroleum Corporation
We have audited the consolidated balance sheets of Compton Petroleum Corporation
as at December 31, 2001 and 2000 and the consolidated statements of earnings and
retained earnings and cash flow for each of the years in the three year period
ended December 31, 2001. These consolidated financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these consolidated financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted
in Canada and the United States of America. These 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 disclosure 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 consolidated financial statements present fairly, in all
material respects, the financial position of the Company as at December 31, 2001
and 2000 and the results of its operations and cash flow for each of the years
in the three year period ended December 31, 2001 in accordance with accounting
principles generally accepted in Canada.
Calgary, Alberta (SIGNED) "GRANT THORNTON LLP"
March 11, 2002, except for Chartered Accountants
Note 16 which is as of May 8, 2002
COMMENTS BY AUDITOR FOR U.S. READERS ON CANADA-U.S. REPORTING DIFFERENCES
In the United States of America, reporting standards for auditors require the
addition of an explanatory paragraph (following the opinion paragraph) when
there is a change in accounting principles that has a material effect on the
comparability of the Company's financial statements, such as the changes
described in Note 3 to the consolidated financial statements. Our report to the
shareholders dated March 11, 2002 is expressed in accordance with Canadian
reporting standards which do not require a reference to such a change in
accounting principles in the Auditors' Report when the change is properly
accounted for and adequately disclosed in the consolidated financial statements.
Calgary, Alberta (SIGNED) "GRANT THORNTON LLP"
Canada Chartered Accountants
March 11, 2002
F-2
================================================================================
COMPTON PETROLEUM CORPORATION
CONSOLIDATED BALANCE SHEETS
(thousands of Canadian dollars)
AS AT AS AT DECEMBER 31,
JUNE 30, -----------------------
2002 2001 2000
- --------------------------------------------------------------------------------
(unaudited)
ASSETS
Current
Cash $ 640 $ 5,052 $ --
Accounts receivable and other 78,935 82,001 81,375
-------- -------- --------
79,575 87,053 81,375
Deferred financing charges 14,349 -- --
Property and equipment (Note 5) 623,572 606,920 442,897
-------- -------- --------
$717,496 $693,973 $524,272
======== ======== ========
LIABILITIES
Current
Accounts payable $ 42,773 $ 64,903 $ 51,439
Long-term debt (Note 6) 250,586 230,000 183,376
Capital lease obligations (Note 7) 394 449 --
Future income taxes (Notes 3 and 12) 188,643 179,192 130,302
Future site restoration (Note 8) 1,930 1,569 1,359
-------- -------- --------
484,326 476,113 366,476
-------- -------- --------
SHAREHOLDERS' EQUITY
Capital stock (Note 9) 118,293 116,572 94,472
Retained earnings 114,877 101,288 63,324
-------- -------- --------
233,170 217,860 157,796
-------- -------- --------
$717,496 $693,973 $524,272
======== ======== ========
Commitments and contingencies (Note 15)
Subsequent events (Note 16)
On behalf of the Board
Mel F. Belich (signed) I.J. Koop (signed)
- --------------------------- ---------------------------
Director Director
See accompanying notes to the consolidated financial statements.
F-3
================================================================================
COMPTON PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF EARNINGS AND RETAINED EARNINGS
(thousands of Canadian dollars, except per share data)
SIX MONTHS ENDED
JUNE 30, YEARS ENDED DECEMBER 31,
---------------------------- --------------------------------------------
2002 2001 2001 2000 1999
(restated Note 3b)
- --------------------------------------------------------------------------------------------------------------------
(unaudited)
REVENUE
Oil and gas revenues $ 96,566 $ 153,612 $ 244,970 $ 213,376 $ 97,016
Royalties, net (21,142) (36,072) (55,919) (44,695) (16,105)
------------ ------------- ------------ ------------ ------------
75,424 117,540 189,051 168,681 80,911
------------ ------------- ------------ ------------ ------------
EXPENSES
Operating 21,855 18,508 40,222 31,571 20,521
General and administrative 4,316 3,692 6,302 5,915 4,222
Interest 6,560 6,284 12,863 12,772 6,939
Unrealized foreign exchange gain (8,465) -- -- -- --
Depletion and depreciation 26,427 23,789 50,450 41,767 20,160
------------ ------------- ------------ ------------ ------------
50,693 52,273 109,837 92,025 51,842
------------ ------------- ------------ ------------ ------------
EARNINGS BEFORE TAXES 24,731 65,267 79,214 76,656 29,069
------------ ------------- ------------ ------------ ------------
TAXES
Future income taxes (Note 12) 9,294 17,224 22,248 35,707 11,782
Capital taxes 939 548 1,330 890 199
------------ ------------- ------------ ------------ ------------
10,233 17,772 23,578 36,597 11,981
------------ ------------- ------------ ------------ ------------
NET EARNINGS 14,498 47,495 55,636 40,059 17,088
RETAINED EARNINGS, beginning
of period 101,288 63,324 63,324 27,197 10,735
------------ ------------- ------------ ------------ ------------
115,786 110,819 118,960 67,256 27,823
Change in accounting policies (Note 3) -- (3,585) (3,585) (380) --
Premium on redemption of
shares (Note 9) (909) (10,406) (14,087) (3,552) (626)
------------ ------------- ------------ ------------ ------------
RETAINED EARNINGS, end of period $ 114,877 $ 96,828 $ 101,288 $ 63,324 $ 27,197
============ ============= ============ ============ ============
EARNINGS PER SHARE
Basic $ 0.13 $ 0.44 $ 0.51 $ 0.37 $ 0.18
============ ============= ============ ============ ============
Diluted (Note 11) $ 0.12 $ 0.42 $ 0.48 $ 0.36 $ 0.17
============ ============= ============ ============ ============
See accompanying notes to the consolidated financial statements.
F-4
================================================================================
COMPTON PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOW
(thousands of Canadian dollars)
SIX MONTHS ENDED
JUNE 30, YEARS ENDED DECEMBER 31,
------------------------- ----------------------------------
2002 2001 2001 2000 1999
(restated Note 3b)
- --------------------------------------------------------------------------------------------------------
(unaudited)
CASH DERIVED FROM (APPLIED TO)
OPERATING
Net earnings $ 14,498 $ 47,495 $ 55,636 $ 40,059 $ 17,088
Items not affecting cash
Depletion and depreciation 26,427 23,789 50,450 41,767 20,160
Future income taxes 9,294 17,224 22,248 35,707 11,782
Amortization of deferred charges 251 -- -- -- --
Unrealized foreign exchange gain (8,465) -- -- -- --
--------- --------- --------- --------- ---------
Cash flow from operations 42,005 88,508 128,334 117,533 49,030
Change in non-cash working
capital (Note 14) 9,097 3,941 (7,266) (13,346) (11,201)
--------- --------- --------- --------- ---------
51,102 92,449 121,068 104,187 37,829
--------- --------- --------- --------- ---------
FINANCING
Change in long-term debt (230,000) (1,376) 36,304 23,662 41,205
Capital lease obligations (55) -- (38) -- --
Issuance of Senior notes 259,050 -- -- -- --
Deferred financing charges (14,435) -- -- -- --
Proceeds from share issues, net 814 1,464 41,558 11,844 18,126
Redemption of common shares (1,234) (12,958) (17,774) (5,564) (1,187)
--------- --------- --------- --------- ---------
14,140 (12,870) 60,050 29,942 58,144
--------- --------- --------- --------- ---------
Cash available for investing
activities 65,242 79,579 181,118 134,129 95,973
--------- --------- --------- --------- ---------
INVESTING
Property and equipment additions (41,392) (78,224) (147,993) (118,153) (71,216)
Corporate acquisitions (Note 4) -- -- (29,669) -- (49,833)
Property dispositions -- -- 8,731 33,272 20,887
Property acquisitions -- -- (18,974) (33,513) (5,536)
Site restoration (99) (69) (473) (368) (507)
Change in non-cash working
capital (Note 14) (28,163) 56 12,312 (307) (4,828)
--------- --------- --------- --------- ---------
(69,654) (78,237) (176,066) (119,069) (111,033)
--------- --------- --------- --------- ---------
CHANGE IN CASH (4,412) 1,342 5,052 15,060 (15,060)
CASH, BEGINNING OF PERIOD 5,052 -- -- (15,060) --
--------- --------- --------- --------- ---------
CASH, END OF PERIOD $ 640 $ 1,342 $ 5,052 $ -- $ (15,060)
========= ========= ========= ========= =========
See accompanying notes to the consolidated financial statements.
F-5
================================================================================
COMPTON PETROLEUM CORPORATION
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Tabular amounts in thousands of Canadian dollars, unless otherwise stated)
(Information as at June 30, 2002 and for the six month period ended June 30,
2002 and 2001 is unaudited)
- --------------------------------------------------------------------------------
1. NATURE OF OPERATIONS
The Company is engaged primarily in the exploration for and production of
petroleum and natural gas reserves in a single cost centre being the Western
Canadian Sedimentary Basin.
2. SIGNIFICANT ACCOUNTING POLICIES
a) BASIS OF PRESENTATION
The consolidated financial statements of the Company have been prepared
in accordance with accounting principles generally accepted in Canada
within the framework of the accounting policies summarized below.
Accounting principles generally accepted in Canada vary in certain
significant respects from accounting principles generally accepted in
the United States of America. The application of the latter would have
affected the determination of net income for the six month period ended
June 30, 2002 and 2001 and each of the years ended December 31, 2001,
2000 and 1999 and the determination of shareholders' equity and
financial position as at June 30, 2002 and December 31, 2001 and 2000
to the extent summarized in Note 17.
Consolidation
The consolidated financial statements include the accounts of the
Company and its wholly-owned subsidiaries from the respective dates of
acquisition. Inter-company transactions and balances are eliminated
upon consolidation.
b) PETROLEUM AND NATURAL GAS PROPERTIES
i) Capitalized costs
The Company follows the full cost method of accounting for its
petroleum and natural gas operations. Under this method all
costs related to the exploration for and development of
petroleum and natural gas reserves are capitalized. Costs
include lease acquisition costs, geological and geophysical
expenses, interest on debt directly related to certain
acquisitions, and costs of drilling both productive and
non-productive wells. Proceeds from the sale of properties are
applied against capitalized costs, without any gain or loss
being realized, unless such sale would significantly alter the
rate of depletion and depreciation.
ii) Depletion and depreciation
Depletion of exploration and development costs and
depreciation of production equipment is provided using the
unit-of-production method based upon estimated proved
petroleum and natural gas reserves. The costs of significant
undeveloped properties are excluded from costs subject to
depletion. For depletion and depreciation purposes, relative
volumes of petroleum and natural gas production and reserves
are converted at the energy equivalent conversion rate of six
thousand cubic feet of natural gas to one barrel of crude oil.
Depreciation of office equipment is provided for on a
declining-balance basis at 20% per annum.
F-6
================================================================================
COMPTON PETROLEUM CORPORATION
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Tabular amounts in thousands of Canadian dollars, unless otherwise stated)
(Information as at June 30, 2002 and for the six month period ended June 30,
2002 and 2001 is unaudited)
- --------------------------------------------------------------------------------
2. SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
iii) Ceiling test
In applying the full cost method, the Company calculates a
ceiling test whereby the carrying value of petroleum and
natural gas properties and production equipment, net of
recorded future income taxes and the accumulated provision for
site restoration and abandonment costs, is compared annually
to an estimate of future net cash flow from the production of
proved reserves. Net cash flow is estimated using year end
prices, less estimated future general and administrative
expenses, financing costs and income taxes. Should this
comparison indicate an excess carrying value, the excess is
charged against earnings as additional depletion and
depreciation.
iv) Future site restoration and abandonment costs
Estimated costs of future site restoration and abandonments,
net of recoveries, are provided for over the life of proved
reserves on a unit-of-production basis. An annual provision is
recorded as additional depletion and depreciation. Costs are
based on engineering estimates of the anticipated method and
extent of site restoration in accordance with current
legislation, industry practices and costs. The accumulated
provision is reflected as a non-current liability and actual
expenditures are charged against the accumulated provision
when incurred.
c) FINANCIAL INSTRUMENTS
Financial instruments consist mainly of accounts receivable and other,
accounts payable and long-term debt. There are no significant
differences between the carrying value of these financial instruments
and their estimated fair value.
From time to time, the Company may employ financial instruments to
manage exposure related to Canada/U.S. exchange rates and commodity
prices associated with the sale of the Company's production. Gains and
losses on these financial instruments, employed as exchange rate and
commodity price hedges, are included in revenues upon sale of the
related hedged production.
d) JOINT OPERATIONS
Certain petroleum and natural gas activities are conducted jointly with
others. These consolidated financial statements reflect only the
Company's proportionate interest in such activities.
e) FLOW-THROUGH SHARES
Resource expenditure deductions for income tax purposes related to
exploration and development activities funded by flow-through share
arrangements are renounced to investors in accordance with income tax
legislation. Future income tax liability is increased and capital stock
is reduced by the estimated tax benefits transferred to shareholders.
F-7
================================================================================
COMPTON PETROLEUM CORPORATION
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Tabular amounts in thousands of Canadian dollars, unless otherwise stated)
(Information as at June 30, 2002 and for the six month period ended June 30,
2002 and 2001 is unaudited)
- --------------------------------------------------------------------------------
2. SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
f) PER SHARE AMOUNTS
Basic earnings per common share is computed by dividing earnings by the
weighted average number of common shares outstanding for the year.
Diluted per share amounts reflect the potential dilution that could
occur if securities or other contracts to issue common shares were
exercised or converted to common shares.
g) USE OF ESTIMATES
The preparation of consolidated financial statements in accordance with
accounting principles generally accepted in Canada requires management
to make assumptions and estimates that affect the reported amounts of
assets and liabilities at the date of the consolidated financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from and affect the
results reported in these consolidated financial statements.
h) HEDGING ACTIVITIES
Settlement of crude oil and natural gas swap agreements, which have
been arranged as a hedge against commodity price, are reflected in
product revenues at the time of sale of the related hedged production.
i) INCOME TAXES
Income taxes are recorded using the liability method of tax allocation.
Future income taxes are calculated based on temporary differences
arising from the difference between the tax basis of an asset or
liability and its carrying value using tax rates anticipated to apply
in the periods when the temporary differences are expected to reverse.
j) REVENUE RECOGNITION
Revenue associated with the production and sales of crude oil, natural
gas and natural gas liquids owned by the Company are recognized when
title passes from the Company to its customer.
k) STOCK-BASED COMPENSATION PLANS
The Company has a stock-based compensation plan, which includes stock
options and an employee stock savings plan.
Consideration received from employees or directors on the exercise of
stock options under the stock option plan is recorded as share capital.
Compensation costs have not been recognized for fixed share options
granted to employees and directors. The Company matches employee
contributions to the stock savings plan and these cash payments are
recorded as compensation expense.
l) DEFERRED FINANCING CHARGES
Financing costs related to the issuance of the senior term notes and
syndicated senior credit facility have been deferred and are amortized
over the term of the respective financing vehicles on a straight-line
basis.
F-8
================================================================================
COMPTON PETROLEUM CORPORATION
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Tabular amounts in thousands of Canadian dollars, unless otherwise stated)
(Information as at June 30, 2002 and for the six month period ended June 30,
2002 and 2001 is unaudited)
- --------------------------------------------------------------------------------
2. SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
m) FOREIGN CURRENCY TRANSLATION
Long-term debt payable in U.S. dollars is translated into Canadian
dollars at the period-end exchange rate, with any resulting adjustment
recorded in the Consolidated Statement of Earnings and Retained
Earnings.
n) DIVIDEND POLICY
The Company has neither declared nor paid any dividends on its common
shares. The Company intends to retain its earnings to finance growth
and expand its operations and does not anticipate paying any dividends
on its common shares in the foreseeable future.
o) RECLASSIFICATION
Certain prior year amounts in the Consolidated Statements of Cash Flow
for 1999 have been reclassified to conform to current year
presentation.
3. CHANGES IN ACCOUNTING POLICIES
a) Effective January 1, 2002, the Company adopted the Canadian Institute
of Chartered Accountants (CICA) amended accounting standard with
respect to accounting for foreign currency translation. As a result of
adopting this amended standard, gains or losses on the translation of
long-term debt denominated in U.S. dollars are no longer deferred and
amortized over the term of the debt, but are recognized in earnings.
The adoption of this amended standard resulted in an unrealized foreign
exchange gain of $8.5 million in the second quarter of 2002. This
amended standard affects the Company's accounting for its U.S.
denominated senior term notes due May 15, 2009 (refer to Note 6).
b) During the fourth quarter of 2001, the Company early adopted the new
recommendations of the CICA with respect to accounting for stock based
compensation. The Company has adopted this accounting policy
retroactively, without restating the financial statements of prior
periods. Effective January 1, 2001, the Company recorded a reduction in
retained earnings of $3.6 million, an increase in accounts payable of
$6.2 million and a decrease in future income tax liability of $2.6
million.
Due to the adoption of these recommendations, the consolidated
financial statements for the six months ended June 30, 2001, have been
restated from those originally reported by the Company. As a result,
the Company recorded an increase to net earnings of $74 thousand with
nil effect to the Company's basic and diluted earnings per share.
c) Effective January 1, 2000, the Company adopted the new recommendations
of the CICA with respect to accounting for future income taxes. Under
the new recommendations the liability method of tax allocation is used,
which is based upon the difference between financial and tax bases of
assets and liabilities.
F-9
================================================================================
COMPTON PETROLEUM CORPORATION
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Tabular amounts in thousands of Canadian dollars, unless otherwise stated)
(Information as at June 30, 2002 and for the six month period ended June 30,
2002 and 2001 is unaudited)
- --------------------------------------------------------------------------------
3. CHANGES IN ACCOUNTING POLICIES (CONTINUED)
The Company has adopted this change in accounting policy retroactively,
without restating the financial statements of prior periods. As a
result, the Company recorded a reduction in retained earnings of $0.4
million, an increase in property and equipment of $68.1 million and an
increase in the future income tax liability of $68.5 million, as at
January 1, 2000.
d) The CICA approved a new standard for the compilation and disclosure of
per share amounts. In 2000, the Company retroactively adopted the new
standard. Under this standard, the treasury stock method is used
instead of the imputed earnings method to determine the dilutive effect
of stock options and other dilutive instruments. Prior period diluted
earnings per share has been restated for this change in accounting
policy. If the imputed earnings method had been used to calculate this
amount, the reported amounts would have been for the year ended
December 31, 2000 - $0.35 per share (1999 - $0.16 per share).
4. ACQUISITIONS
Effective July 16, 2001, the Company acquired all of the issued and outstanding
shares of Hornet Energy Ltd. ("Hornet"), a public company involved in the
exploration, development and production of oil and natural gas primarily in
southern Alberta. The acquisition has been accounted for by the purchase method
of accounting and the consolidated financial statements include the results of
operations from date of acquisition. The fair value of the assets acquired is as
follows:
NET ASSETS ACQUIRED
Property and equipment $ 54,276
Future income taxes (12,236)
------------
42,040
Working capital deficiency (1,460)
Long-term debt (10,320)
Capital lease obligations (591)
------------
$ 29,669
============
CONSIDERATION
Cash $ 29,134
Transaction costs 535
------------
$ 29,669
============
1999 - COPAREX CANADA LTD.
On December 1, 1999 the Company acquired all of the issued and outstanding
shares of Coparex Canada Ltd. ("Coparex"), for cash consideration of $49.8
million. Coparex, a privately owned corporation, was engaged in oil and gas
exploration activities primarily in Alberta. The transaction has been accounted
for by the purchase method and the consolidated financial statements include the
results of the operations from date of acquisition. The fair value of the assets
acquired is as follows:
F-10
================================================================================
COMPTON PETROLEUM CORPORATION
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Tabular amounts in thousands of Canadian dollars, unless otherwise stated)
(Information as at June 30, 2002 and for the six month period ended June 30,
2002 and 2001 is unaudited)
- --------------------------------------------------------------------------------
4. ACQUISITIONS (CONTINUED)
NET ASSETS ACQUIRED
Property and equipment
Oil and gas reserves and facilities $ 64,421
Undeveloped lands 10,173
------------
74,594
Working capital 132
Long-term debt (24,893)
------------
$ 49,833
============
CONSIDERATION
Cash $ 49,368
Transaction costs 465
------------
$ 49,833
============
The following table reflects unaudited pro forma combined results of operations
of the Company and the above acquisitions on the basis that the acquisitions had
taken place at the beginning of the fiscal period for each of the periods
presented:
2001 2000 1999
---- ---- ----
Revenue, net of royalties $ 195,593 $ 176,777 $ 101,947
Net earnings 52,111 39,958 17,397
Earnings per share
Basic 0.47 0.37 0.18
Diluted 0.45 0.36 0.17
F-11
================================================================================
COMPTON PETROLEUM CORPORATION
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Tabular amounts in thousands of Canadian dollars, unless otherwise stated)
(Information as at June 30, 2002 and for the six month period ended June 30,
2002 and 2001 is unaudited)
- --------------------------------------------------------------------------------
5. PROPERTY AND EQUIPMENT
DECEMBER 31,
JUNE 30, -------------------------
2002 2001 2000
---- ---- ----
Exploration and development costs $ 667,899 $ 635,508 $ 455,565
Accumulated depletion (132,187) (109,091) (64,058)
--------- --------- ---------
535,712 526,417 391,507
--------- --------- ---------
Production equipment and processing facilities 98,204 88,727 55,529
Office equipment 3,609 2,808 2,154
--------- --------- ---------
101,813 91,535 57,683
Accumulated depreciation (13,953) (11,032) (6,293)
--------- --------- ---------
87,860 80,503 51,390
--------- --------- ---------
$ 623,572 $ 606,920 $ 442,897
========= ========= =========
The Company does not capitalize any portion of its general and administrative
expenses. During the six months ended June 30, 2002 - nil (six months ended June
30, 2001 - nil; year ended December 31, 2001 - nil; 2000 - $0.7 million; 1999 -
$0.2 million) of interest expense associated with certain property acquisitions
and processing facilities was capitalized.
Future capital expenditures of $33.0 million (2000 - $37.1 million; 1999 - $26.7
million), as estimated by independent engineers, relating to the development of
proved non-producing reserves have been included in costs subject to depletion,
and undeveloped properties with a cost at June 30, 2002 - $163.0 million (June
30, 2001 - $135.6 million; December 31, 2001 of $161.0 million; 2000 - $98.8
million; 1999 - $55.6 million), included in exploration and development costs,
have not been subject to depletion.
6. LONG-TERM DEBT
DECEMBER 31,
JUNE 30, -------------------
2002 2001 2000
---- ---- ----
Senior term notes (US$ 165,000,000) $250,586 $ -- $ --
Prime rate advances -- -- 8,376
Banker's Acceptances -- 230,000 175,000
-------- -------- --------
$250,586 $230,000 $183,376
======== ======== ========
a) SENIOR TERM NOTES
On May 8, 2002, the Company completed an offering of US$165 million
senior notes bearing interest at 9.90 percent with principal repayable
on May 15, 2009. Interest is payable on May 15 and November 15 of each
year, beginning on November 15, 2002. The Company used the net proceeds
to repay its entire existing bank indebtedness and for general
corporate purposes. The senior notes are unsecured.
F-12
================================================================================
COMPTON PETROLEUM CORPORATION
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Tabular amounts in thousands of Canadian dollars, unless otherwise stated)
(Information as at June 30, 2002 and for the six month period ended June 30,
2002 and 2001 is unaudited)
- --------------------------------------------------------------------------------
6. LONG-TERM DEBT (CONTINUED)
Concurrent with the closing of the senior notes offering, the Company
entered into interest rate swap arrangements with its banking syndicate
whereby interest paid by the Company on the US$165 million principal
amount will be based upon the 90 day Bankers' Acceptance rate plus 4.85
percent. This arrangement resulted in an effective interest rate of
7.40 percent during the second quarter of 2002.
b) CREDIT FACILITIES
As at June 30, 2002, the Company had authorized syndicated senior
credit facilities, with Canadian financial institutions, in the amount
of $168 million (2001 - $240 million). The senior credit facilities
consist of a $158 million (2001 - $230 million) extendible revolving
credit facility and a $10 million (2001 - $10 million) working capital
facility. As a result of the Company's US$165 million senior notes
issuance, completed May 8, 2002, the Company's senior credit facilities
were adjusted to $168 million. Advances under the facilities can be
drawn in either Canadian or U.S. funds. The facilities bear interest at
the lenders' prime lending rate or at the Bankers' Acceptance rate or
LIBOR plus a margin based on the ratio of total consolidated debt to
cash flow, currently set at 0.625 percent, 1.625 percent and 1.625
percent, respectively. These facilities mature on July 9, 2003 and are
secured by a fixed and floating charge debenture in the amount of $325
million covering all of the Company's assets and undertakings.
7. CAPITAL LEASES
Certain leases relating to gas processing equipment, having costs in the
aggregate of $601 thousand and accumulated depreciation of $36 thousand, are
classified as capital leases and are included in property and equipment. These
capital lease obligations were acquired as part of the Hornet acquisition
referred to in Note 4. Each lease contains an option to purchase and has an
implicit interest rate of 7.8 percent to 8.8 percent. Excluded from the
following future capital lease payment obligations is interest in the amount of
$92 thousand.
December 31,
2001
----
2002 $ 104
2003 323
2004 36
2005 38
2006 52
------------
553
Less: current portion,
included in accounts payable 104
------------
$ 449
============
F-13
================================================================================
COMPTON PETROLEUM CORPORATION
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Tabular amounts in thousands of Canadian dollars, unless otherwise stated)
(Information as at June 30, 2002 and for the six month period ended June 30,
2002 and 2001 is unaudited)
- --------------------------------------------------------------------------------
8. SITE RESTORATION AND ABANDONMENTS
At June 30, 2002 total future removal and site restoration costs to be accrued
over the life of the remaining proved reserves were estimated, net of
recoveries, at $8.8 million (December 31, 2001 - $8.5 million; December 31, 2000
- - $5.4 million) of which $1.9 million (December 31, 2001 - $1.6 million;
December 31, 2000 - $1.4 million) have been accrued. This estimate is subject to
change based on amendments to environmental laws and as new information
concerning operations becomes available.
9. CAPITAL STOCK
a) AUTHORIZED:
Unlimited number of common shares
Unlimited number of preferred shares, issuable in series
b) ISSUED AND OUTSTANDING:
SIX MONTHS ENDED
JUNE 30, 2002
-----------------------------
NUMBER
OF SHARES AMOUNT
--------- ------
COMMON SHARES
Balance, beginning of period 113,105,450 $ 116,572
Issued for property 350,000 1,225
Issued for cash on
exercise of options 358,099 822
Repurchased for cash (315,400) (326)
------------ ------------
Balance, end of period 113,498,149 $ 118,293
============ ============
YEARS ENDED DECEMBER 31,
------------------------------------------------------------
2001 2000
-------------------------- ---------------------------
NUMBER NUMBER
OF SHARES AMOUNT OF SHARES AMOUNT
--------- ------ --------- ------
COMMON SHARES
Balance, beginning of year 108,783,649 $ 94,472 108,047,882 $ 89,505
Issued for cash, net 7,345,604 22,964 3,075,100 6,825
Issued for property 241,997 1,285 30,000 78
Issued for cash on
exercise of warrants 625,616 1,095 -- --
Issued for cash on
exercise of options 314,584 443 56,667 76
Repurchased for cash (4,206,000) (3,687) (2,426,000) (2,012)
------------ ------------ ------------ ------------
Balance, end of year 113,105,450 $ 116,572 108,783,649 $ 94,472
============ ============ ============ ============
F-14
================================================================================
COMPTON PETROLEUM CORPORATION
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Tabular amounts in thousands of Canadian dollars, unless otherwise stated)
(Information as at June 30, 2002 and for the six month period ended June 30,
2002 and 2001 is unaudited)
- --------------------------------------------------------------------------------
9. CAPITAL STOCK (CONTINUED)
During 2001, common shares issued for cash include 7,345,604 (2000 -
3,075,100) common shares issued on a flow-through basis. Under the
terms of the year 2001 flow-through agreements, the Company is required
to expend $41.8 million on qualifying oil and natural gas expenditures
prior to December 31, 2002. As at December 31, 2001, the Company had
incurred qualifying expenditures in the amount of $16.2 million.
During the first six months of 2002, the Company repurchased for
cancellation 315,400 common shares at an average price of $3.91 per
share (2001 - 4,206,000 shares at an average price of $4.23 per share;
2000 - 2,426,000 shares at an average price of $2.29 per share),
pursuant to a normal course issuer bid. The excess of the purchase
price over book value has been charged to retained earnings.
c) OUTSTANDING WARRANTS
In 1998, in conjunction with the disposition of certain facilities, the
Company issued share purchase warrants to a third party, which entitled
the holder to acquire 3,000,000 common shares of the Company. As at
December 31, 2001, nil (2000 - 1,000,000; 1999 - 1,000,000) warrants
were outstanding at an exercise price of $1.75 per share. The warrants
were exercisable on the basis of 10,000 warrants for each $250,000 paid
to the Company as an incentive fee under the terms of the disposition.
In 2001, a total of 625,616 warrants were exercised for gross proceeds
of $1.1 million. The remaining warrants were cancelled.
d) SHAREHOLDER RIGHTS PLAN
The Company has a Shareholder Rights Plan to ensure all shareholders
are treated fairly in the event of a take-over offer or other
acquisition of control of the Company.
Pursuant to the Plan, the Board of Directors authorized and declared
the distribution of one Right in respect of each common share
outstanding. In the event that an acquisition of 20% or more of the
Company's shares is completed and the acquisition is not a permitted
bid, as defined by the Plan, each Right will permit the holder to
acquire, at the exercise price of $50.00, such number of common shares
as have a market value equal to twice the exercise price.
10. STOCK-BASED COMPENSATION PLANS
The Company has implemented a Stock Option Plan, for directors, officers and
employees. As of June 30, 2002, there were 14,500,000 common shares reserved for
issuance to eligible participants. At June 30, 2002, 9,910,954 (December 31,
2001 - 9,829,334; December 31, 2000 - 6,352,335) options with exercise prices
between $0.60 and $4.60 were outstanding and exercisable at various dates to
June 19, 2012. The exercise price of each option equals the market price of the
Company's common shares on the date of the grant.
At the beginning of the year 2001, the Company had a share appreciation rights
plan of which, the financial statement effects of this plan were determined not
to be significant to the financial statements due to the amount vested. During
the year 2001, this plan was cancelled and replaced by a fixed option plan with
a variable component.
F-15
================================================================================
COMPTON PETROLEUM CORPORATION
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Tabular amounts in thousands of Canadian dollars, unless otherwise stated)
(Information as at June 30, 2002 and for the six month period ended June 30,
2002 and 2001 is unaudited)
- --------------------------------------------------------------------------------
10. STOCK-BASED COMPENSATION PLANS (CONTINUED)
As a result, a certain number of outstanding fixed options included in the
Company's Stock Option Plan have a variable compensation cost to them. As at
December 31, 2001, approximately 2.4 million of the outstanding fixed options
total of 9.8 million were granted as a result of the aforementioned cancelled
share appreciation rights plan. These fixed options, with a variable component,
were granted in two tranches: 1.7 million at a fixed option exercise price of
$3.02 per option share and 0.7 million at a fixed option exercise price of $4.00
per option share. Attached to these fixed options is a variable compensation
component that enables the holder of such fixed option to receive a cash payment
from the Company upon exercise of the fixed option. This cash payment varies
with each fixed option holder, and is based on the difference between the lesser
of the market price of the Company's common shares on the date the fixed option
is exercised or the fixed option exercise price, and a stated compensation price
for each respective option holder. Under this structure, the maximum variable
compensation cash payment is the respective fixed option
exercise price.
The aggregate variable cost component relating to these fixed options can vary
in amount between a range based on the market value price of the Company's
common shares and is limited to a total amount of $4.4 million. The liability
related to the variable component of these options amounts to $3.4 million, and
is included in accounts payable as at June 30, 2002 (2001 - $3.9 million).
The following tables summarize the information about the share options as at:
YEARS ENDED DECEMBER 31,
SIX MONTHS ENDED -------------------------------------------------------
JUNE 30, 2002 2001 2000
------------------------ ------------------------- --------------------------
WEIGHTED WEIGHTED WEIGHTED
AVERAGE AVERAGE AVERAGE
EXERCISE EXERCISE EXERCISE
FIXED OPTIONS SHARES PRICE SHARES PRICE SHARES PRICE
------------- ------ ----- ------ ----- ------ -----
Outstanding at beginning
of period 9,829,334 $2.03 6,352,335 $1.08 6,081,334 $1.00
Granted 919,070 $4.13 3,866,250 $3.57 500,000 $2.30
Exercised (358,099) $2.33 (314,584) $1.41 (56,667) $1.34
Cancelled (479,351) $3.83 (74,667) $3.63 (172,332) $1.45
------------- ------------- -------------
Outstanding at end
of period 9,910,954 $2.13 9,829,334 $2.03 6,352,335 $1.08
============= ============= =============
Options exercisable
at period end 7,505,879 $1.59 7,009,889 $1.42 5,719,001 $1.00
============= ============= =============
F-16
================================================================================
COMPTON PETROLEUM CORPORATION
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Tabular amounts in thousands of Canadian dollars, unless otherwise stated)
(Information as at June 30, 2002 and for the six month period ended June 30,
2002 and 2001 is unaudited)
- --------------------------------------------------------------------------------
OPTIONS OUTSTANDING OPTIONS EXERCISABLE
----------------------------------------- ---------------------------
NUMBER WEIGHTED NUMBER
OUTSTANDING AVERAGE WEIGHTED EXERCISABLE WEIGHTED
AT REMAINING AVERAGE AT AVERAGE
JUNE 30, CONTRACTUAL EXERCISE JUNE 30, EXERCISE
RANGE OF EXERCISE PRICES 2002 LIFE PRICE 2002 PRICE
------------------------ ------------- ---- ----- ------------- -----
$0.60 - $1.25 4,350,000 4.4 $ 0.76 4,350,000 $ 0.76
$1.45 - $2.30 1,526,667 7.2 $ 1.90 1,393,334 $ 1.86
$2.98 - $3.50 1,583,804 7.4 $ 3.03 1,068,644 $ 3.02
$3.80 - $4.60 2,450,483 9.0 $ 4.11 693,901 $ 4.05
------------- -------------
9,910,954 $ 2.13 7,505,879 $ 1.59
============= =============
F-17
================================================================================
COMPTON PETROLEUM CORPORATION
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Tabular amounts in thousands of Canadian dollars, unless otherwise stated)
(Information as at June 30, 2002 and for the six month period ended June 30,
2002 and 2001 is unaudited)
- --------------------------------------------------------------------------------
10. STOCK-BASED COMPENSATION PLANS (CONTINUED)
OPTIONS OUTSTANDING OPTIONS EXERCISABLE
------------------------------------------ -----------------------------
NUMBER WEIGHTED NUMBER
OUTSTANDING AVERAGE WEIGHTED EXERCISABLE WEIGHTED
AT REMAINING AVERAGE AT AVERAGE
DECEMBER 31, CONTRACTUAL EXERCISE DECEMBER 31, EXERCISE
RANGE OF EXERCISE PRICES 2001 LIFE PRICE 2001 PRICE
------------------------ ------------- ---- ----- ------------- -----
$0.60 - $1.25 4,380,000 5.17 $ 0.77 4,380,000 $ 0.77
$1.45 - $2.30 1,653,334 7.67 $ 1.87 1,436,667 $ 1.83
$2.98 - $3.50 1,922,900 9.75 $ 3.04 826,899 $ 3.02
$3.80 - $4.30 1,873,100 9.67 $ 4.10 366,323 $ 3.94
------------- -------------
9,829,334 $ 2.03 7,009,889 $ 1.42
============= =============
CICA Handbook section 3870 "Stock-based Compensation", establishes financial
accounting and reporting standards for stock-based employee compensation plans
as well as transactions in which an entity issues its equity instruments to
acquire goods or services from non-employees. The Company has elected to follow
the intrinsic value method of accounting for stock-based compensation
arrangements. Since all options were granted with an exercise price equal to the
market price at the date of the grant, no compensation cost has been charged to
income at the time of the option grants. Had compensation cost for the Company's
stock options been determined based on the fair market value at the grant dates
of the awards consistent with methodology prescribed by Handbook section 3870,
the Company's net income and net income per share would have been the pro forma
amounts for the periods as indicated below:
SIX MONTHS ENDED
JUNE 30, YEARS ENDED DECEMBER 31,
------------------------- ----------------------------------------
2002 2001 2001 2000 1999
---- ---- ---- ---- ----
Net earnings:
As reported $ 14,498 $ 47,495 $ 55,636 $ 40,059 $ 17,088
Pro forma $ 13,391 $ 47,230 $ 53,446 $ 39,407 $ 16,585
Net earnings per common share - basic:
As reported $ 0.13 $ 0.44 $ 0.51 $ 0.37 $ 0.18
Pro forma $ 0.12 $ 0.44 $ 0.49 $ 0.37 $ 0.17
Net earnings per common share - diluted:
As reported $ 0.12 $ 0.42 $ 0.48 $ 0.36 $ 0.17
Pro forma $ 0.11 $ 0.42 $ 0.47 $ 0.36 $ 0.17
F-18
================================================================================
COMPTON PETROLEUM CORPORATION
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Tabular amounts in thousands of Canadian dollars, unless otherwise stated)
(Information as at June 30, 2002 and for the six month period ended June 30,
2002 and 2001 is unaudited)
- --------------------------------------------------------------------------------
10. STOCK-BASED COMPENSATION PLANS (CONTINUED)
The weighted average fair market value of options granted in the six months
ended June 30, 2002 and 2001 and for the years ended December 31, 2001, 2000 and
1999 are $3.24, $2.90, $2.52, $1.61 and $1.20 per option, respectively. The fair
value of each option granted was estimated on the date of grant using the
Modified Black-Scholes option-pricing model with the following assumptions:
SIX MONTHS ENDED
JUNE 30, YEARS ENDED DECEMBER 31,
------------------------- ----------------------------------------
2002 2001 2001 2000 1999
---- ---- ---- ---- ----
Risk-free interest rate 5.70% 5.39% 5.40% 5.54% 5.19%
Estimated hold period prior
to exercise (years) 10 10 10 10 10
Volatility in the price of the
Company's common shares 67.26% 51.10% 53.75% 52.75% 46.92%
Handbook section 3870, also requires recognition of the compensation cost with
respect to changes in intrinsic value for the variable component of fixed
options outstanding during the period. During the six month period ended June
30, 2002, the Company recorded a compensation cost recovery of $412 thousand
related to the outstanding variable component of these options (2001 - $280
thousand).
11. PER SHARE AMOUNTS
In the calculation of diluted per share amounts, options under the stock option
plan are assumed to have been converted or exercised on the later of the
beginning of the year and the date granted. The treasury stock method is used to
determine the dilutive effect of stock options. The treasury stock method
assumes that proceeds received from the exercise of in-the-money stock options
are used to repurchase common shares at the average market rate.
SIX MONTHS ENDED
JUNE 30, YEARS ENDED DECEMBER 31,
---------------------------- -------------------------------------------
2002 2001 2001 2000 1999
---- ---- ---- ---- ----
Weighted average shares
outstanding (thousands)
Basic 113,306 107,267 109,881 106,904 97,409
======= ======= ======= ======= =======
Diluted 118,239 112,405 114,844 110,645 100,800
======= ======= ======= ======= =======
F-19
================================================================================
COMPTON PETROLEUM CORPORATION
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Tabular amounts in thousands of Canadian dollars, unless otherwise stated)
(Information as at June 30, 2002 and for the six month period ended June 30,
2002 and 2001 is unaudited)
- --------------------------------------------------------------------------------
12. INCOME TAXES
a) PROVISION FOR INCOME TAXES
SIX MONTHS ENDED
JUNE 30, YEARS ENDED DECEMBER 31,
---------------------- ------------------------------------
2002 2001 2001 2000 1999
---- ---- ---- ---- ----
Earnings before taxes $ 24,731 $ 65,267 $ 79,214 $ 76,656 $ 29,069
Expected tax expense at
combined federal and
provincial rate of 42.1% 42.6% 42.6% 44.6% 44.6%
$ 10,417 $ 27,804 $ 33,745 $ 34,204 $ 12,965
Increase (decrease) resulting
from:
Non-deductible crown charges 7,274 12,313 18,570 16,915 7,831
Non-deductible depletion -- -- -- -- 1,035
Alberta royalty tax credits (104) (106) (213) (291) (602)
Resource allowance (5,439) (12,249) (22,984) (17,486) (7,207)
Statutory rate change (2,135) (7,400) (7,400) -- --
Other (719) (3,138) 530 2,365 (2,240)
-------- -------- -------- -------- --------
Provision for future income
taxes $ 9,294 $ 17,224 $ 22,248 $ 35,707 $ 11,782
======== ======== ======== ======== ========
b) FUTURE INCOME TAXES
Future income taxes consist of the following temporary differences:
DECEMBER 31,
JUNE 30, ----------------------------
2002 2001 2000
---- ---- ----
Property and equipment $ 170,798 $ 157,792 $ 136,351
Timing of partnership items 28,742 31,088 --
Resource allowance rate reduction (6,199) (5,315) (4,058)
Non-capital losses (3,029) (2,162) --
Share issue costs and other (856) (1,542) (1,385)
Future site restoration (813) (669) (606)
------------- ------------ ------------
Future income taxes $ 188,643 $ 179,192 $ 130,302
============ ============ ============
F-20
================================================================================
COMPTON PETROLEUM CORPORATION
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Tabular amounts in thousands of Canadian dollars, unless otherwise stated)
(Information as at June 30, 2002 and for the six month period ended June 30,
2002 and 2001 is unaudited)
- --------------------------------------------------------------------------------
13. FINANCIAL INSTRUMENTS
The Company is exposed to fluctuations in commodity prices, interest rates and
Canada/U.S. exchange rates. The Company, when appropriate, utilizes financial
instruments to manage its exposure to these risks.
a) COMMODITY PRICE RISK MANAGEMENT
The Company enters into hedge transactions on crude oil and natural
gas. The agreements entered into are forward transactions providing the
Company with a range of fixed prices on the commodities sold. Oil and
gas revenues for the period ended June 30, 2002 include gains of $288
thousand (2001 - $3.7 million gain; 2000 - $7.7 million loss; 1999 -
$1.1 million loss) on these transactions.
The following table outlines the financial agreements in place at June 30, 2002:
DAILY
NOTIONAL UNRECOGNIZED
TERM VOLUME PRICES RECEIVED (GAIN)/LOSS
---- ------ --------------- -----------
Natural Gas
Collar Apr 02 - Oct 02 15,000 GJ $3.83/GJ - $5.45/GJ $ (818)
Fixed price contract May 02 - Oct 02 5,000 GJ $4.50/GJ $ (683)
Collar Nov 02 - Mar 03 5,000 GJ $4.50/GJ - $7.85/GJ $ --
Crude Oil
Collar May 02 - Dec 02 1,500 bbls US$23.83/bbl - US$28.00/bbl $ --
Fixed price contract May 02 - Dec 02 500 bbls US$24.40/bbl $ 111
The following table outlines the financial agreements that were entered into by
the Company, subsequent to June 30, 2002, and are currently outstanding:
DAILY NOTIONAL
TERM VOLUME PRICES RECEIVED
---- ------ ---------------
Natural Gas
Collar Nov 02 - Mar 03 20,000 GJ $4.00/GJ - $6.55/GJ
Crude Oil
Collar Jan 03 - Dec 03 500 bbls US$23.50/bbl - US$27.00/bbl
Fixed price contract Jan 03 - Dec 03 500 bbls US$25.00/bbl
b) FOREIGN CURRENCY EXCHANGE RISK MANAGEMENT
The Company is exposed to fluctuations in the exchange rate between the
Canadian dollar and the U.S. dollar. Crude oil, and to a large extent,
natural gas prices, are based upon reference prices denominated in U.S.
dollars, while the majority of the Company's expenses are denominated
in Canadian dollars.
When appropriate, the Company enters into agreements to fix the
exchange rate of Canadian dollars to U.S. dollars in order to manage
the risk of revenue losses if the Canadian dollar increases in value
compared to the U.S. dollar.
F-21
================================================================================
COMPTON PETROLEUM CORPORATION
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Tabular amounts in thousands of Canadian dollars, unless otherwise stated)
(Information as at June 30, 2002 and for the six month period ended June 30,
2002 and 2001 is unaudited)
- --------------------------------------------------------------------------------
13. FINANCIAL INSTRUMENTS (CONTINUED)
c) INTEREST RATE RISK MANAGEMENT
The majority of the Company's long-term debt has a fixed interest rate
and the Company periodically uses interest rate swaps to manage its
debt servicing costs. The Company currently has an outstanding interest
rate swap on a total of US$165 million of long-term debt. This swap
converts fixed rate interest into floating rate interest (refer to Note
6(a)).
The Company is exposed to changes in interest rates as a result of the
senior credit facilities bearing interest of the Company's lenders'
prime rate or at the Banker's Acceptance rate, or LIBOR plus applicable
margins. At June 30, 2002, there was no amounts outstanding on the
senior credit facility, thus for each one percentage change in interest
rates on this floating rate debt had nil effect on net earnings.
d) FAIR VALUE OF FINANCIAL ASSETS AND LIABILITIES
The fair values of the Company's financial assets and liabilities that
are included in the Company's Consolidated Balance Sheet as at June 30,
2002 approximate their carrying value. The fair value of the senior
term notes does not significantly differ from the carrying amount since
the estimated interest rates that would be available to the Company at
June 30, 2002 approximate the actual interest rate of the senior term
notes.
e) CREDIT RISK MANAGEMENT
Accounts receivable include amounts receivable for oil and gas sales
which are generally made to large credit worthy purchasers, and amounts
receivable from joint venture partners which are recoverable from
production. Accordingly, the Company views credit risks on these
amounts as low.
The Company is exposed to losses in the event of non-performance by
counter-parties to these financial instruments. The Company deals with
major institutions and believes these risks are minimal.
F-22
================================================================================
COMPTON PETROLEUM CORPORATION
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Tabular amounts in thousands of Canadian dollars, unless otherwise stated)
(Information as at June 30, 2002 and for the six month period ended June 30,
2002 and 2001 is unaudited)
- --------------------------------------------------------------------------------
14. CASH FLOW
Changes in non-cash working capital items increased (decreased) cash and cash
equivalents as follows:
SIX MONTHS ENDED
JUNE 30, YEARS ENDED DECEMBER 31,
---------------------------- -------------------------------------------
2002 2001 2001 2000 1999
---- ---- ---- ---- ----
Accounts receivable and other $ 3,065 $ 10,459 $ (413) $ (29,568) $ (26,427)
Accounts payable (22,131) (6,462) 5,459 15,915 10,398
------------ ------------- ------------ ------------ ------------
$ (19,066) $ 3,997 $ 5,046 $ (13,653) $ (16,029)
============ ============= ============ ============ ============
Operating activities
Accounts receivable $ 6,624 $ (2,695) $ (10,704) $ (18,165) $ (14,113)
Accounts payable 2,473 6,636 3,438 4,819 2,912
------------ ------------- ------------ ------------ ------------
$ 9,097 $ 3,941 $ (7,266) $ (13,346) $ (11,201)
------------ ------------- ------------ ------------ ------------
Investing activities
Accounts receivable $ (3,558) $ 13,154 $ 10,291 $ (11,403) $ (12,314)
Accounts payable (24,605) (13,098) 2,021 11,096 7,486
------------ ------------- ------------ ------------ ------------
$ (28,163) $ 56 $ 12,312 $ (307) $ (4,828)
------------ ------------- ------------ ------------ ------------
$ (19,066) $ 3,997 $ 5,046 $ (13,653) $ (16,029)
============ ============= ============ ============ ============
Amounts paid during the year relating to interest expense and capital taxes are
as follows:
SIX MONTHS ENDED
JUNE 30, YEARS ENDED DECEMBER 31,
---------------------------- -------------------------------------------
2002 2001 2001 2000 1999
---- ---- ---- ---- ----
Interest paid $ 2,869 $ 7,053 $ 13,054 $ 13,639 $ 6,576
Capital taxes paid $ 1,133 $ -- $ 793 $ 470 $ 314
F-23
================================================================================
COMPTON PETROLEUM CORPORATION
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Tabular amounts in thousands of Canadian dollars, unless otherwise stated)
(Information as at June 30, 2002 and for the six month period ended June 30,
2002 and 2001 is unaudited)
- --------------------------------------------------------------------------------
15. COMMITMENTS AND CONTINGENT LIABILITIES
a) The Company has committed to certain payments under operating leases
over the next five years, as follows:
2002 2003 2004 2005 2006
---- ---- ---- ---- ----
Equipment $ 1,740 $ 1,131 $ 203 $ -- $ --
Office rental 1,210 1,444 1,452 481 --
----------- ----------- ----------- ----------- -----------
$ 2,950 $ 2,575 $ 1,655 $ 481 $ --
=========== =========== =========== =========== ===========
b) Legal proceedings
The Company is involved in various legal claims associated with normal
operations. These claims, although unresolved at the current time, are
minor in nature and are not expected to have a material impact on the
financial position or results of operations of the Company.
16. SUBSEQUENT EVENTS
a) On May 8, 2002, the Company completed an offering of US$165 million,
9.90% senior notes due 2009. The senior notes are unsecured and were
issued at a price per note of 98.273%. The net proceeds from the
offering are approximately US$156.3 million and the Company used the
net proceeds to repay its entire existing bank indebtedness and for
general corporate purposes.
b) As a result of the completion of the above mentioned senior notes
offering, the Company's senior credit facilities as described in Note
6(b) have been adjusted to $168 million, comprised of a $158 million
extendible revolving credit facility and a $10 million working capital
facility.
F-24
================================================================================
COMPTON PETROLEUM CORPORATION
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Tabular amounts in thousands of Canadian dollars, unless otherwise stated)
(Information as at June 30, 2002 and for the six month period ended June 30,
2002 and 2001 is unaudited)
- --------------------------------------------------------------------------------
17. UNITED STATES ACCOUNTING PRINCIPLES AND REPORTING
RECONCILIATION OF CONSOLIDATED FINANCIAL STATEMENTS TO UNITED STATES GENERALLY
ACCEPTED ACCOUNTING PRINCIPLES
The Company's consolidated interim financial information has been prepared using
the same accounting principles, practices and methods as those that were used
for the Company's fiscal years. Accordingly, the accounting principles,
practices and methods used in the preparation of the consolidated interim
financial information vary from U.S. principles, practices and methods as
described below.
These consolidated financial statements have been prepared in accordance with
accounting principles generally accepted in Canada ("Canadian GAAP") which, in
most respects, conforms to accounting principles generally accepted in the
United States of America ("U.S. GAAP"). The significant differences in those
principles, as they apply to the Company's statements of earnings, balance
sheets and statements of cash flow, are as follows:
a) Under U.S. GAAP, the carrying value of petroleum and natural
gas properties and related facilities, net of future or
deferred income taxes, is limited to the present value of
after tax future net revenue from proven reserves, discounted
at 10 percent, (based on prices and costs at the balance sheet
date) plus the lower of cost and fair value of unproven
properties. Under Canadian GAAP, the "ceiling test" is
calculated without application of a discount factor to future
net revenues, but estimated future general and administrative
and financing costs are deducted from future net revenue.
Prior to January 1, 2001, Canadian GAAP required the test to
be performed annually, whereas U.S. GAAP required the ceiling
test to be performed at the end of each quarter. Subsequent to
January 1, 2001, Canadian GAAP requires the ceiling test to be
performed at the end of each quarter. The Company has
completed a ceiling test calculation at June 30, 2002 and
December 31, 2001, 2000 and 1999 with no write-down required
under either Canadian or U.S. GAAP. At December 31, 1998 the
application of the full cost ceiling test under U.S. GAAP
would have resulted in a write-down of capitalized costs of
$13.8 million after income tax, utilizing commodity prices at
December 31, 1998 of $15.33/bbl for crude oil and $2.50/mcf
for natural gas. As commodity prices were uncharacteristically
lower than normal at December 31, 1998 and considering a
subsequent strengthening of prices in the first quarter of
1999, U.S. GAAP allows the Company to choose a different
measurement date for purposes of calculating the full cost
ceiling test. Accordingly, the application of the ceiling test
at March 31, 1999 did not result in a write-down indicating
that the capitalized costs were not in fact impaired at year
end. The application of the full cost ceiling test under U.S.
GAAP for years prior to the year ended December 31, 1998 did
not result in a write-down of capitalized costs.
b) Under U.S. GAAP, the provision for future site restoration
costs is recorded as a reduction of property and equipment in
the amount of $1.9 million at June 30, 2002 (December 31, 2001
- $1.6 million; 2000 - $1.4 million).
F-25
================================================================================
COMPTON PETROLEUM CORPORATION
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Tabular amounts in thousands of Canadian dollars, unless otherwise stated)
(Information as at June 30, 2002 and for the six month period ended June 30,
2002 and 2001 is unaudited)
- --------------------------------------------------------------------------------
17. UNITED STATES ACCOUNTING PRINCIPLES AND REPORTING (CONTINUED)
c) Statement of Financial Accounting Standards ("SFAS") 123,
"Accounting for Stock-based Compensation", establishes
financial accounting and reporting standards for stock-based
employee compensation plans as well as transactions in which
an entity issues its equity instruments to acquire goods or
services from non-employees. As permitted by SFAS 123, the
Company has elected to follow the intrinsic value method of
accounting for stock-based compensation arrangements, as
provided for in Accounting Principles Board Opinion 25 ("APB
25"). Since all options were granted with an exercise price
equal to the market price at the date of the grant, no
compensation cost has been charged to income at the time of
the option grants. As discussed in Note 10, the Company
retroactively adopted effective January 1, 2001, the standards
of accounting released by the CICA for stock based
compensation. These standards are consistent with SFAS 123.
APB 25, as interpreted by the Financial Accounting Standards
Board ("FASB") interpretation 44, also requires recognition of
compensation cost with respect to changes in intrinsic value
for variable employee stock compensation plans. As a result of
the modifications to the terms of employee stock options, the
modified options are subject to variable plan accounting,
which result in a compensation cost of $4.5 million and $1.5
million for the years ended December 31, 2000 and 1999 for
U.S. GAAP purposes.
d) Prior to January 1, 2000, the Company recorded the
renouncement of tax deductions resulting from the issuance of
flow-though shares by reducing property and equipment and
share capital by the estimated cost of the tax deductions
renounced.
U.S. GAAP requires that flow-through shares be recorded at
their fair value without any adjustment for the renouncement
of the tax deductions and any temporary difference resulting
from the renouncement must be recognized in the determination
of tax expense in the year incurred. U.S. GAAP also requires
the estimated cost of the tax deductions renounced be recorded
as a future income tax liability rather than a reduction of
petroleum and natural gas properties. Subsequent to January 1,
2000, the Company accounted for the estimated cost of the tax
deduction renounced as a future tax liability and hence was
consistent with U.S. GAAP. See Note 3(c) for the effect of
this accounting policy change on property and equipment and
future income taxes in 2000. The effect of increasing property
and equipment to stated value in 1999 was to increase
depletion by $1.3 million and to reduce future income taxes by
$0.6 million.
The impact of recording flow-through shares at their fair
value for the six months ended June 30, 2002, was to increase
the future income tax provision by nil (six months ended June
30, 2001 - nil; year ended December 31, 2001 - $8.7 million;
2000 - $4.7 million; 1999 - $4.9 million) and to increase
capital stock by a corresponding amount. In addition, as at
January 1, 1999, retained earnings was decreased by $5.5
million and capital stock increased by $5.5 million to
retroactively adjust for prior year flow-through share
issuances.
Prior to January 1, 2000, the charge for depletion and
depreciation will be lower for Canadian GAAP as compared to
U.S. GAAP because of the reduction of petroleum and natural
gas properties for the cost of the tax deductions renounced.
F-26
================================================================================
COMPTON PETROLEUM CORPORATION
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Tabular amounts in thousands of Canadian dollars, unless otherwise stated)
(Information as at June 30, 2002 and for the six month period ended June 30,
2002 and 2001 is unaudited)
- --------------------------------------------------------------------------------
17. UNITED STATES ACCOUNTING PRINCIPLES AND REPORTING (CONTINUED)
e) Prior to year 2000, the Company followed the deferral method
of accounting for income taxes. Under this method, there was a
matching of the income tax expense with the reported pre-tax
accounting income. In the United States, Statement of
Financial Accounting Standards No. 109 requires the use of the
asset and liability method. Under this method, a tax liability
or asset is recognized for the differences between reported
values and the tax basis of the assets and liabilities. The
Company adopted the liability method of accounting for income
taxes in 2000 retroactively, without restating the financial
statements of prior periods.
f) Statement of Financial Accounting Standards No. 130
"Comprehensive Income" requires the reporting of comprehensive
income in addition to net earnings. Comprehensive income
includes net income plus other comprehensive income.
Management believes that it has no other comprehensive income
other than as described under note 17(g).
g) SFAS No. 133, "Accounting for Derivative instruments and
Hedging Activities", as amended by SFAS 137 and SFAS 138, was
issued in June 1998 by the FASB. SFAS 133 establishes new
accounting and reporting standards for derivative instruments
and for hedging activities. This statement requires the
Company to measure all derivatives at fair value and to
recognize them in the balance sheet as an asset or liability,
depending on the Company's rights or obligations under the
applicable derivative contract. Changes in the fair value of
derivatives will be recorded each quarter in net income or
other comprehensive income, depending on whether a derivative
is designated as part of a hedge transaction and, if it is,
depending on the type of hedge transaction. The ineffective
portion of all hedges will be recognized in net income. If a
derivative does not qualify as a hedging relationship, the
derivative is recorded at fair value and changes in its fair
value will be reported in net income. Under the current
accounting policy for derivatives, only derivatives used in
sales and trading activities are recorded on the balance sheet
at fair value. The effective date of SFAS 133 for the Company
is at January 1, 2001.
DERIVATIVES
The Company used forward contracts and options on forward
contracts to manage the risk of fluctuations in the market
price of natural gas and crude oil, and the change in interest
rates. During the six months ended June 30, 2002, the Company
had 6 forward contracts. As at June 30, 2002, the natural gas
and crude oil futures contracts determined to be derivatives
under SFAS 133 are accounted for as cash flow hedges and
expire on various dates through December 2003. These contracts
are recorded at fair value on the Balance Sheet in the amount
of $2.1 million as of June 30, 2002 (2001 - $187 thousand).
The offset of the change in fair value is recorded in
comprehensive income, net of tax, and subsequently recognized
as a component of Operating expense on the Statement of
Earnings and Retained Earnings when the underlying product
being hedged is purchased. The effective portion of these
commodity contracts is $1.2 million, which is recorded in
comprehensive income as of June 30, 2002 (2001 - $123
thousand), and the ineffective portion of these commodity
contracts was immaterial for the periods ended June 30, 2002
and December 31, 2001.
F-27
================================================================================
COMPTON PETROLEUM CORPORATION
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Tabular amounts in thousands of Canadian dollars, unless otherwise stated)
(Information as at June 30, 2002 and for the six month period ended June 30,
2002 and 2001 is unaudited)
- --------------------------------------------------------------------------------
17. UNITED STATES ACCOUNTING PRINCIPLES AND REPORTING (CONTINUED)
CONSOLIDATED STATEMENTS OF OPERATIONS
The application of U.S. GAAP would have the following effect on net income:
SIX MONTHS ENDED
JUNE 30, YEARS ENDED DECEMBER 31,
-------------------- ---------------------------------
2002 2001 2001 2000 1999
---- ---- ---- ---- ----
Net income for the period,
as reported $ 14,498 $ 47,495 $ 55,636 $ 40,059 $ 17,088
Adjustments:
Depletion (d) -- -- -- -- (1,262)
Depletion (e) -- -- -- -- (5,946)
Related income taxes -- -- -- -- 3,215
Compensation costs (c) -- -- -- (4,484) (1,466)
Related income taxes -- -- -- 2,000 654
Accounting for income taxes (d) -- -- (8,715) (4,694) (4,938)
-------- -------- -------- -------- --------
Net income for the year - U.S. GAAP $ 14,498 $ 47,495 $ 46,921 $ 32,881 $ 7,345
======== ======== ======== ======== ========
Net income per common share
- U.S. GAAP
Basic $ 0.13 $ 0.44 $ 0.43 $ 0.31 $ 0.08
Diluted $ 0.12 $ 0.42 $ 0.41 $ 0.30 $ 0.07
Statement of comprehensive income (f)
Net income for the year
- U.S. GAAP $ 14,498 $ 47,495 $ 46,921 $ 32,881 $ 7,345
Accounting for hedging (g) 1,230 -- 123 -- --
-------- -------- -------- -------- --------
Comprehensive income $ 15,728 $ 47,495 $ 47,044 $ 32,881 $ 7,345
======== ======== ======== ======== ========
Depletion and depreciation expense
- U.S. GAAP $ 26,427 $ 23,789 $ 50,450 $ 41,767 $ 27,368
======== ======== ======== ======== ========
Depletion and depreciation expense
- U.S. GAAP per BOE produced $ 7.61 $ 7.73 $ 7.69 $ 7.04 $ 5.94
======== ======== ======== ======== ========
F-28
================================================================================
COMPTON PETROLEUM CORPORATION
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Tabular amounts in thousands of Canadian dollars, unless otherwise stated)
(Information as at June 30, 2002 and for the six month period ended June 30,
2002 and 2001 is unaudited)
- --------------------------------------------------------------------------------
17. UNITED STATES ACCOUNTING PRINCIPLES AND REPORTING (CONTINUED)
CONSOLIDATED BALANCE SHEETS
The application of U.S. GAAP would have the following effect on the balance
sheets:
JUNE 30, 2002
-----------------------------------
INCREASE
AS REPORTED (DECREASE) U.S. GAAP
----------- ---------- ---------
Assets
Property and equipment (b) $623,572 $ (1,930) $621,642
Accounting for hedging (g) -- 2,144 2,144
Liabilities
Site restoration costs (b) $ 1,930 $ (1,930) $ --
Future income (g) 188,643 914 189,557
Shareholders' equity
Capital stock (d) $118,293 $ 23,843 $142,136
Retained earnings (see schedule below) 114,877 (22,613) 92,264
DECEMBER 31, 2001
-----------------------------------
INCREASE
AS REPORTED (DECREASE) U.S. GAAP
----------- ---------- ---------
Assets
Property and equipment (b) $606,920 $ (1,569) $605,351
Accounting for hedging (g) -- 187 187
Liabilities
Site restoration costs (b) $ 1,569 $ (1,569) $ --
Future income taxes (g) 179,192 64 179,256
Shareholders' equity
Capital stock (d) $116,572 $ 23,843 $140,415
Retained earnings (see schedule below) 101,288 (23,720) 77,568
F-29
================================================================================
COMPTON PETROLEUM CORPORATION
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Tabular amounts in thousands of Canadian dollars, unless otherwise stated)
(Information as at June 30, 2002 and for the six month period ended June 30,
2002 and 2001 is unaudited)
- --------------------------------------------------------------------------------
17. UNITED STATES ACCOUNTING PRINCIPLES AND REPORTING (CONTINUED)
DECEMBER 31, 2000
-----------------------------------
INCREASE
AS REPORTED (DECREASE) U.S. GAAP
----------- ---------- ---------
U.S. GAAP
Assets
Property and equipment (b) $442,897 $ (1,359) $441,538
Liabilities
Site restoration costs (b) $ 1,359 $ (1,359) $ --
Future income taxes (e) 130,302 (2,687) 127,615
Other (c) -- 6,024 6,024
Shareholders' equity
Capital stock (d) $ 94,472 $ 15,128 $109,600
Retained earnings (see schedule below) 63,324 (18,465) 44,859
DECEMBER 31,
JUNE 30, -----------------------
2002 2001 2000
---- ---- ----
Retained earnings under Canadian GAAP $ 114,877 $ 101,288 $ 63,324
Flow-through share differences (d) (23,843) (23,843) (15,128)
Stock option expense adjustments -- -- (6,024)
Adjustment to future income taxes (c) -- -- 2,687
Commodity derivatives (g) 1,230 123 --
--------- --------- ---------
Retained earnings under U.S. GAAP $ 92,624 $ 77,568 $ 44,859
========= ========= =========
CONSOLIDATED STATEMENTS OF CASH FLOW
The application of U.S. GAAP would not change the amounts as reported under
Canadian GAAP for cash flows provided by (used in) operating, investing or
financing activities, except for the following:
(i) Unspent flow-through share proceeds which have been received
at December 31, 2001. During 2001, the Company received $41.8
million in proceeds from the issuance of flow-through shares
of which $25.6 million remained unspent as at December 31,
2001 (December 31, 2000 - $12.5 million). Accordingly, under
U.S. GAAP, these proceeds would be disclosed separately on the
balance sheet of Compton as restricted cash and would not be
treated as cash or cash equivalents for statement of cash flow
reporting purposes. The result of this difference would be to
disclose an increase in restricted cash as an investing
activity and to reduce cash, end of year by $25.6 million at
December 31, 2001 (December 31, 2000 - $12.5 million);
F-30
================================================================================
COMPTON PETROLEUM CORPORATION
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Tabular amounts in thousands of Canadian dollars, unless otherwise stated)
(Information as at June 30, 2002 and for the six month period ended June 30,
2002 and 2001 is unaudited)
- --------------------------------------------------------------------------------
17. UNITED STATES ACCOUNTING PRINCIPLES AND REPORTING (CONTINUED)
(ii) The consolidated statements of cash flow includes, under
investing activities, changes in working capital for items not
affecting cash, such as accounts payable and accounts
receivable, related to the non-cash elements of property and
equipment additions. This disclosure is provided in order to
disclose the aggregate costs related to such activities and to
identify the non-cash component thereof and to arrive at the
cash amounts. This presentation is not permitted under U.S.
GAAP;
(iii) The consolidated statements of cash flow includes, under
investing activities, site restoration costs. Under U.S. GAAP
these costs would be presented under operating activities; and
(iv) The consolidated statements of cash flow, for the year ended
December 31, 1999, disclosed a negative ending cash balance of
$15.1 million. Under U.S. GAAP, this negative ending cash
balance (or bank overdrafts) would be reflected as a financing
activity in the consolidated statements of cash flow.
Additionally, under U.S. GAAP, unspent flow-through share
proceeds as at December 31, 2001 and December 31, 2000 (refer
to Note 17 (i) would decrease the Company's reported ending
cash balance position, and result in a negative ending cash
balance of $17.9 million for the year ended December 31, 2001
and a positive ending cash balance of $2.6 million for the
year ended December 31, 2000.
ADDITIONAL U.S. GAAP DISCLOSURE
DECEMBER 31,
JUNE 30, --------------------------------
2002 2001 2000
---- ---- ----
Accounts receivable includes the following:
Revenue receivable $ 40,595 $ 37,101 $ 44,696
Joint interest receivable 24,603 26,132 26,388
Other receivables 13,754 18,785 10,308
Allowance for doubtful accounts (17) (17) (17)
------------ ------------ ------------
$ 78,935 $ 82,001 $ 81,375
============ ============ ============
DECEMBER 31,
JUNE 30, --------------------------------
2002 2001 2000
---- ---- ----
Accounts payable and accrued liabilities
includes the following:
Trade payables $ 31,735 $ 52,393 $ 39,537
Royalties payable 6,960 3,202 5,593
Taxes payable 950 2,359 150
Other payables 3,128 6,949 6,159
------------ ------------ ------------
$ 42,773 $ 64,903 $ 51,439
============ ============ ============
F-31
================================================================================
COMPTON PETROLEUM CORPORATION
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Tabular amounts in thousands of Canadian dollars, unless otherwise stated)
(Information as at June 30, 2002 and for the six month period ended June 30,
2002 and 2001 is unaudited)
- --------------------------------------------------------------------------------
17. UNITED STATES ACCOUNTING PRINCIPLES AND REPORTING (CONTINUED)
The aggregate capitalized costs of oil and gas activities and costs incurred in
oil and gas property acquisitions, development and exploration activities are as
follows:
Capitalized costs
DECEMBER 31,
JUNE 30, -----------------------
2002 2001 2000
---- ---- ----
Proved properties $ 606,762 $ 566,074 $ 414,493
Unproven properties:
Acquisition 112,068 110,764 72,309
Exploration 50,882 50,205 26,446
Accumulated depletion and depreciation (146,140) (120,123) (70,351)
--------- --------- ---------
$ 623,572 $ 606,920 $ 442,897
========= ========= =========
Costs incurred on unproved properties
INCLUDES COSTS INCURRED IN
JUNE 30, ------------------------------------------------------
2002 2002 2001 2000 1999 PRIOR YEARS
-------- -------- -------- -------- -------- -----------
Acquisition $112,068 $ 1,304 $ 38,455 $ 26,006 $ 17,535 $ 28,768
Exploration 50,882 677 23,759 17,143 9,303 --
-------- -------- -------- -------- -------- --------
$162,950 $ 1,981 $ 62,214 $ 43,149 $ 26,838 $ 28,768
======== ======== ======== ======== ======== ========
Costs incurred
2001 2000 1999
---- ---- ----
Acquisition costs (net of disposition)
Proven properties $ 30,716 $ 241 $ 24,309
Unproven properties 38,455 26,006 17,535
Development costs
Development of proven undeveloped reserves 16,088 19,573 7,727
Other 27,229 48,582 16,126
Exploration costs 75,417 23,992 40,001
-------- -------- --------
Total costs incurred $187,905 $118,394 $105,698
======== ======== ========
F-32
================================================================================
COMPTON PETROLEUM CORPORATION
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Tabular amounts in thousands of Canadian dollars, unless otherwise stated)
(Information as at June 30, 2002 and for the six month period ended June 30,
2002 and 2001 is unaudited)
- --------------------------------------------------------------------------------
17. UNITED STATES ACCOUNTING PRINCIPLES AND REPORTING (CONTINUED)
Costs are transferred into the depletion base on an ongoing basis as the
undeveloped properties are evaluated and proved reserves are established or
impairment determined. Pending determination of proved reserves attributable to
the above costs, the Company cannot assess the future impact on the amortization
rate.
DECEMBER 31,
JUNE 30, -----------------------
2002 2001 2000
---- ---- ----
Future income tax liabilities
Property and equipment $ 199,540 $ 188,880 $ 133,664
Future income tax assets
Other temporary differences (6,199) (5,315) (4,058)
Abandonment costs (813) (669) (606)
Loss carry forward (3,029) (2,162) --
Other 58 (1,478) (1,385)
--------- --------- ---------
Future income taxes $ 189,557 $ 179,256 $ 127,615
========= ========= =========
ABSENCE OF CONDENSED CONSOLIDATING FINANCIAL INFORMATION
The Company has no independent assets or operations. The notes are guaranteed by
Hornet Energy Ltd., 867791 Alberta Ltd. and 899776 Alberta Ltd., which are all
wholly owned subsidiaries of the Company, as well as Compton Petroleum, a
partnership whose only partners are the Company, Hornet Energy Ltd. and 867791
Alberta Ltd. The subsidiary of the Company that is not a subsidiary guarantor of
the notes is minor. The guarantees of the notes are full and unconditional and
joint and several obligations of the subsidiary guarantors. There are no
significant restrictions on the ability of the Company or any of the subsidiary
guarantors to obtain funds from its subsidiaries by dividend or loan.
RECENT ACCOUNTING PRONOUNCEMENTS
On July 20, 2001, the Financial Accounting Standards Board (FASB) issued
Statement of Financial Accounting Standards (SFAS) 141, BUSINESS COMBINATIONS,
and SFAS 142, GOODWILL AND INTANGIBLE ASSETS. SFAS 141 is effective for all
business combinations completed after June 30, 2001. SFAS 142 is effective for
fiscal years beginning after December 15, 2001; however, certain provisions of
this Statement apply to goodwill and other intangible assets acquired between
July 1, 2001 and the effective date of SFAS 142. Major provisions of these
Statements and their effective dates for the Company are as follows:
o All business combinations initiated after June 30, 2001 must use the
purchase method of accounting. The pooling of interest method of
accounting is prohibited except for transactions initiated before July
1, 2001.
o Intangible assets acquired in a business combination must be recorded
separately from goodwill if they arise from contractual or other legal
rights or are separable from the acquired entity and can be sold,
transferred, licensed, rented or exchanged, either individually or as
part of a related contract, asset or liability.
F-33
================================================================================
COMPTON PETROLEUM CORPORATION
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Tabular amounts in thousands of Canadian dollars, unless otherwise stated)
(Information as at June 30, 2002 and for the six month period ended June 30,
2002 and 2001 is unaudited)
- --------------------------------------------------------------------------------
17. UNITED STATES ACCOUNTING PRINCIPLES AND REPORTING (CONTINUED)
o Goodwill, as well as intangible assets with indefinite lives, acquired
after June 30, 2001, will not be amortized. Effective January 1, 2002,
all previously recognized goodwill and intangible assets with
indefinite lives will no longer be subject to amortization.
o Effective January 1, 2002, goodwill and intangible assets with
indefinite lives will be tested for impairment annually and whenever
there is an impairment indicator.
o All acquired goodwill must be assigned to reporting units for purposes
of impairment testing and segment reporting.
Management's assessment is that these Statements do not have a material impact
on the Company's financial position or results of operations.
In July 2001, the FASB issued SFAS No. 143, Accounting for Asset Retirement
Obligations. This Statement addresses financial accounting and reporting for
obligations associated with the retirement of tangible long-lived assets and the
associated asset retirement costs. This Statement applies to all entities. It
applies to legal obligations associated with the retirement of long-lived assets
that result from the acquisition, construction, development and (or) the normal
operation of a long-lived asset, except for certain obligations of lessees. This
Statement is effective for financial statements issued for fiscal years
beginning after June 15, 2002.
The Company is evaluating the impact of the adoption of this standard and has
not yet determined the effect of adoption on its financial position and results
of operations.
In August 2001, the FASB issued SFAS No. 144, Accounting for the Impairment or
Disposal of Long-Lived Assets. This statement addresses financial accounting and
reporting for the impairment or disposal of long-lived assets and supersedes
FASB Statement No. 121, Accounting for the Impairment of Long-Lived Assets and
for Long-Lived Assets To Be Disposed Of. The provisions of the statement are
effective for financial statements issued for fiscal years beginning after
December 15, 2001.
Management's assessment is that this Statement do not have a material impact on
the Company's financial position or results of operations.
In July 2002, the FASB issued Statement 146, ACCOUNTING FOR COSTS ASSOCIATED
WITH EXIT OR DISPOSAL ACTIVITIES. SFAS 146 nullifies EITF 94-3, LIABILITY
RECOGNITION FOR CERTAIN EMPLOYEE TERMINATION BENEFITS AND OTHER COSTS TO EXIT AN
ACTIVITY (INCLUDING CERTAIN COSTS INCURRED IN A RESTRUCTURING.). SFAS 146
requires the recognition of a liability for costs associated with exit or
disposal activities when a liability is incurred; that is, the costs meet the
definition of a liability in accordance with Concepts Statement 6, ELEMENTS OF
FINANCIAL STATEMENTS. The statement also provides guidance on the required
disclosures of exit and disposal activities. SFAS 146 is effective for exit or
disposal activities initiated after December 31, 2002.
F-34
18. SUPPLEMENTAL RESERVE INFORMATION (UNAUDITED)
The net proved oil and natural gas reserve estimates as of December 31, 1999,
2000 and 2001 set forth below were prepared in accordance with guidelines
established by the Securities and Exchange Commission and accordingly were based
on existing economic and operating conditions. Oil and natural gas prices in
effect as of the respective year ends were used without any escalation except in
those instances where the sale is covered by contract, in which case the
applicable contract price is used. Operating costs, royalties and future
development costs were based on current costs with no escalation.
There are numerous uncertainties inherent in estimating quantities of proved
reserves and in projecting the future rates of production and timing of
development expenditures. The following reserve data represents estimates only
and should not be construed as being exact. Moreover, the present value should
not be construed as the current market value of the Company's oil and natural
gas reserves or the costs that would be incurred to obtain equivalent reserves.
All of the reserves are located in Canada.
ESTIMATED QUANTITIES OF RESERVES
YEARS ENDED DECEMBER 31,
------------------------------------------------------------------------
1999 2000 2001
----------------------- ----------------------- -------------------
CRUDE OIL NATURAL CRUDE OIL NATURAL CRUDE OIL NATURAL
& NGL's gas & NGL's gas & NGL's gas
(MBBLS) (MMCF) (MBBLS) (MMCF) (MBBLS) (MMCF)
------- ------ ------- ------ ------- ------
Balance, beginning of year 7,272 155,659 10,682 181,759 9,423 223,761
Revisions of previous estimates 774 (14,832) (2,524) 1,715 313 (3,186)
Extensions, discoveries and other
additions 1,531 23,262 1,399 60,495 1,611 63,248
Acquisitions of minerals in place 2,429 38,586 1,809 8,761 301 7,412
Dispositions of minerals in place (20) (1,082) (180) (3,930) (45) (382)
Production (1,304) (19,834) (1,763) (25,039) (1,826) (28,405)
-------- -------- -------- -------- -------- --------
Balance, end of year 10,682 181,759 9,423 223,761 9,777 262,448
======== ======== ======== ======== ======== ========
Proved developed reserve
Balance, beginning of year 6,589 140,823 8,629 156,939 8,576 187,969
Balance, end of year 8,629 156,939 8,576 187,969 8,938 232,319
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS AND CHANGES THEREIN
RELATING TO PROVED OIL AND NATURAL GAS RESERVES
The Standardized Measure of Discounted Future Net Cash Flows and Changes Therein
Relating to Proved Oil and Natural Gas Reserves ("Standardized Measure") does
not purport to present the fair market value of the Company's oil and natural
gas properties. An estimate of such value should consider, among other factors,
anticipated future prices of oil and natural gas, the probability of recoveries
in excess of existing proved reserves and acreage prospects, and perhaps
different discount rates. It should be noted that estimates of reserve
quantities, especially from new discoveries, are inherently imprecise and
subject to substantial revisions.
Under the Standardized Measure, future cash inflows were estimated by applying
year end prices, adjusted for contracts currently in place to deliver production
to the estimated future production of year end proved reserves. Future cash
inflows were reduced by estimated future production and development costs based
on year end costs to determine pre-tax cash inflows. Future taxes were computed
by applying the statutory tax rate to the excess of
F-35
18. SUPPLEMENTAL RESERVE INFORMATION (UNAUDITED) (CONTINUED)
pre-tax cash inflows over the Company's tax basis in the associated proved oil
and natural gas properties. Tax credits and net operating loss carry forwards
were also considered in the future income tax calculation. Future net cash
inflows after income taxes were discounted using a 10% annual discount rate to
arrive at the Standardized Measure.
YEARS ENDED DECEMBER 31,
------------------------------------------
1999 2000 2001
------------------------------------------
(in thousands of Canadian dollars)
Future cash inflows $ 928,813 $ 2,524,446 $ 1,270,787
Future production costs (283,296) (382,540) (431,127)
Future development costs (29,478) (41,035) (41,943)
----------- ----------- -----------
Future net cash flows 616,039 2,100,871 797,717
Income taxes (221,237) (907,123) (264,960)
----------- ----------- -----------
Total undiscounted future net cash flows 394,802 1,193,748 532,757
10% annual discount for estimated timing of cash inflows (123,316) (483,879) (215,296)
----------- ----------- -----------
Standardized measure of discounted future net cash $ 271,486 $ 709,869 $ 317,461
=========== =========== ===========
(1) The Company estimates that it will incur $6.9 million in 2002, $14.9
million in 2003 and $ nil in 2004 to develop proved undeveloped reserves.
The following table sets forth an analysis of changes in the Standardized
Measure of Discounted Future Net Cash Flows from proved oil and natural gas
reserves:
YEARS ENDED DECEMBER 31,
-----------------------------------------
1999 2000 2001
-----------------------------------------
(in thousands of Canadian dollars)
Beginning of year $ 131,146 $ 271,486 $ 709,869
Sales of production, net of production costs (60,389) (137,110) (151,724)
Net change in sales prices, net of production costs 125,292 783,990 (807,804)
Extensions, discoveries and additions 58,558 116,197 127,656
Changes in estimated future development costs (31,182) (26,630) (48,528)
Development costs incurred during the period which
reduced future development costs 42,514 51,305 58,982
Revisions in quantity estimates (1,955) 88,175 (2,099)
Accretion of discount 17,040 35,497 111,245
Purchase of reserves 86,467 87,440 17,976
Sales of reserves (1,510) (7,783) (1,517)
Net change in income tax (67,119) (395,612) 389,962
Changes in production rates (timing) and other (27,376) (157,086) (86,557)
--------- --------- ---------
Standardized measure, end of year $ 271,486 $ 709,869 $ 317,461
========= ========= =========
F-36
[GRAPHIC OMITTED]
[LOGO - COMPTON PETROLEUM CORPORATION]
COMPTON
--------------------------------------
PETROLEUM CORPORATION
EXCHANGE OFFER OF
US$165,000,000 OF OUR
9.90% SENIOR NOTES
DUE 2009
------------------------------
PROSPECTUS
[____], 2002
------------------------------
No person has been authorized to give any information or to make any
representation other than those contained in this prospectus, and, if given or
made, any information or representations must not be relied upon as having been
authorized. This prospectus does not constitute an offer to sell or the
solicitation of an offer to buy any securities other than the securities to
which it relates or an offer to sell or the solicitation of an offer to buy
these securities in any circumstances in which this offer or solicitation is
unlawful. Neither the delivery of this prospectus nor any sale made under this
prospectus shall, under any circumstances, create any implication that there has
been no change in the affairs of Compton Petroleum Corporation since the date of
this prospectus or that the information contained in this prospectus is correct
as of any time subsequent to its date.
Dealer Prospectus Delivery Obligation: Until the 41st day after the
date of this prospectus, all dealers that effect transactions in these
securities, whether or not participating in this offering, may be required to
deliver a prospectus. This is in addition to the broker-dealers' obligation to
deliver a prospectus when acting as underwriters and with respect to their
unsold allotments or subscriptions.
PART II
INFORMATION NOT REQUIRED IN PROSPECTUS
ITEM 20. INDEMNIFICATION OF DIRECTORS AND OFFICERS
(a) Compton Petroleum Corporation
Hornet Energy Ltd.
867791 Alberta Ltd.
899776 Alberta Ltd.
The BUSINESS CORPORATIONS ACT (Alberta) and the CANADA
BUSINESS CORPORATIONS ACT provides that a corporation may, in certain
circumstances, indemnify a director or officer of the corporation, a former
director or officer of the corporation, a person who acts or acted at the
corporation's request as a director or officer of a body corporate of which the
corporation is or was a shareholder or creditor and the heirs and legal
representatives of any such persons (collectively, "Indemnified Persons")
against all costs, charges and expenses reasonably incurred by any such
Indemnified Person in respect of any civil, criminal or administrative action or
proceeding to which he is made a party by reason of being or having been a
director or officer of the corporation or other body corporate, if (a) he acted
honestly and in good faith with a view to the best interests of the corporation,
and (b) in the case of a criminal or administrative action or proceeding that is
enforced by a monetary penalty, he had reasonable grounds for believing that his
conduct was lawful.
The by-laws of the Registrant provide that it shall indemnify
Indemnified Persons of the Registrant to the maximum extent permitted by the
BUSINESS CORPORATIONS ACT (Alberta).
Insofar as indemnification for liabilities arising under the
Securities Act of 1933 may be permitted to directors and officers and persons
controlling the Registrant pursuant to the foregoing provisions, the Registrant
has been advised that, in the opinion of the Commission, such indemnification is
against public policy as expressed in the Securities Act of 1933 and is,
therefore, unenforceable. The Registrant carries certain insurance coverage, in
respect of potential claims against its directors and officers and in respect of
losses of which the Registrant may be required or permitted by law to indemnify
such directors and officers.
(b) Compton Petroleum
The PARTNERSHIP ACT (Alberta) provides that each partner in a
partnership is liable jointly with the other partners for debts and obligations
of the partnership incurred while they are a partner. Accordingly, as the
partners to the Compton Petroleum partnership are incorporated under the
BUSINESS CORPORATIONS ACT (Alberta) or the CANADA BUSINESS CORPORATION ACT, the
indemnification of the directors or officers of each partnership will be as set
forth above.
ITEM 21. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a) EXHIBITS
EXHIBIT
NUMBER DESCRIPTION
- ------- -----------
3.1* Articles of Incorporation of Compton Petroleum Corporation.
3.2* Articles of Incorporation of Hornet Energy Ltd.
3.3* Articles of Incorporation of 867791 Alberta Ltd.
3.4* Articles of Incorporation of 899776 Alberta Ltd.
3.5* Declaration of Partnership of Compton Petroleum.
3.6* By-laws of Compton Petroleum Corporation.
3.7* By-laws of Hornet Energy Ltd.
3.8* By-laws of 867791 Alberta Ltd.
3.9* By-laws of 899776 Alberta Ltd.
3.10* Partnership Agreement of Compton Petroleum.
4.1* Indenture, dated as of May 8, 2002, among Compton Petroleum
Corporation, Hornet Energy Ltd., 867791 Alberta Ltd., 899776
Alberta Ltd., Compton Petroleum and the Bank of Nova Scotia
Trust Company of New York, as trustee.
4.2* Form of Note.
5.1** Opinion of Fraser Milner Casgrain LLP regarding the legality
of the notes and subsidiary guarantees.
5.2* Opinion of Paul, Weiss, Rifkind, Wharton & Garrison regarding
the legality of the notes and subsidiary guarantees.
8.1** Opinion of Fraser Milner Casgrain LLP regarding Canadian tax
matters, included in Exhibit 5.1 hereto.
8.2** Opinion of Paul, Weiss, Rifkind, Wharton & Garrison regarding
U.S. tax matters.
10.1* Registration Rights Agreement, dated as of May 8, 2002 among
Compton Petroleum Corporation, Hornet Energy Ltd., 867791
Alberta Ltd., 899776 Alberta Ltd., Compton Petroleum, Lehman
Brothers, BMO Nesbitt Burns, Scotia Capital and TD Securities.
10.2* Second Amended and Restated Extendible Credit Agreement, dated
May 8, 2002, between Compton Petroleum Corporation and the
Bank of Montreal, The Bank of Nova Scotia and the
Toronto-Dominion Bank.
10.3* Employment Agreement, dated April 22, 1998, between Compton
Petroleum Corporation and Kim Davies.
10.4* Employment Agreement, dated April 22, 1998, between Compton
Petroleum Corporation and Norman G. Knecht.
10.5* Employment Agreement, dated April 22, 1998, between Compton
Petroleum Corporation and Ernest G. Sapieha.
10.6* Employment Agreement, dated April 22, 1998, between Compton
Petroleum Corporation and Murray J. Stodalka.
12.1* Statement regarding computation of ratios.
21.1* List of subsidiaries.
23.1** Consent of Fraser Milner Casgrain LLP, included in Exhibit 5.1
hereto.
23.2** Consent of Grant Thornton LLP.
23.3* Consent of Outtrim Szabo Associates Ltd.
23.4* Consent of Paul, Weiss, Rifkind, Wharton & Garrison.
24.1* Powers of Attorney (included on the signature page hereto).
25.2* Statement of Eligibility on Form T-1 of The Bank of Nova
Scotia Trust Company of New York.
99.1* Form of Letter of Transmittal.
99.2* Form of Notice of Guaranteed Delivery.
- ------------------------
* Previously filed.
** Filed herewith.
(b) FINANCIAL STATEMENT SCHEDULES
All schedules for which provision is made in the applicable accounting
regulations of the Commission are not required, are inapplicable or have been
disclosed in the notes to other financial statements and therefore have been
omitted.
ITEM 22. UNDERTAKINGS
Each of the Registrants hereby undertakes: (i) to respond to requests
for information that is incorporated by reference into the prospectus pursuant
to Items 4, 10(b), 11, or 13 of this Form, within one business day of receipt of
such request, and to send the incorporated documents by first class mail or
other equally prompt means; and (ii) to arrange or provide for a facility in the
U.S. for the purpose of responding to such requests. The undertaking in
subparagraph (i) above includes information contained in documents filed
subsequent to the effective date of the registration statement through the date
of responding to the request.
Each of the Registrants hereby undertakes to supply by means of a
post-effective amendment all information concerning a transaction and the
company being acquired involved therein, that was not the subject of and
included in the registration statement when it became effective.
Each of the Registrants hereby undertakes: (1) to file, during any
period in which offers or sales are being make, a post-effective amendment to
this registration statement: (i) to include any prospectus required by section
10(a)(3) of the Securities Act of 1933; (ii) to reflect in the prospectus any
facts or events arising after the effective date of the registration statement
(or the most recent post-effective amendment thereof) which, individually or in
the aggregate, represents a fundamental change in the information set forth in
the registration statement. Notwithstanding the foregoing, any increase or
decrease in volume of securities offered (if the total dollar value of
securities offered would not exceed that which was registered) and any deviation
from the low or high end of the extimated maximum offering range may be
reflected in the form of prospectus filed with the Commission pursuant to Rule
424(b) if, in the aggregate, the changes in volume and price represent no more
than a 20% change in the maximum aggregate offering price set forth in the
"Calculation of Registration Fee" table in the effective registration statement;
(iii) to include any material information with respect to the plan of
distribution not previously disclosed in the registration statement or any
material change to such information in the registration statement; (2) that, for
the purpose of determining any liability under the Securities Act of 1933, each
such post-effective amendment shall be deemed to be a new registration statement
relating to the securities offered therein, and the offering of such securities
at that time shall be deemed to be the initial bona fide offering thereof; and
(3) to remove from registration by means of a post-effective amendment any of
the securities being registered which remain unsold at the termination of the
offering.
SIGNATURES
Pursuant to the requirements of the Securities Act of 1933, Compton
Petroleum Corporation has duly caused this Amendment No. 2 to the Registration
Statement to be signed on its behalf by the undersigned, thereunto duly
authorized, in the City of Calgary, Province of Alberta, Canada, on October 16,
2002.
COMPTON PETROLEUM CORPORATION
By: /s/ Norman G. Knecht
---------------------------------------
Name: Norman G. Knecht
Title: Vice-President, Finance and
Chief Financial Officer
Pursuant to the requirements of the Securities Act of 1933, Compton
Petroleum has duly caused this Amendment No. 2 to the Registration Statement to
be signed on its behalf by the undersigned, thereunto duly authorized, in the
City of Calgary, Province of Alberta, Canada, on October 16, 2002.
COMPTON PETROLEUM
By its managing partner, Compton Petroleum
Corporation:
By: /s/ Norman G. Knecht
---------------------------------------
Name: Norman G. Knecht
Title: Vice-President, Finance and
Chief Financial Officer
Pursuant to the requirements of the Securities Act of 1933, Compton
Petroleum has duly caused this Amendment No. 2 to the Registration Statement to
be signed on its behalf by the undersigned, thereunto duly authorized, in the
City of Calgary, Province of Alberta, Canada, on October 16, 2002.
SIGNATURE TITLE
- --------- -----
* Director
- -----------------------------
Mel F. Belich
/s/ Norman G. Knecht Vice President Finance and Chief
- ----------------------------- Financial Officer
Norman G. Knecht (Principal Financial and Accounting
Officer)
* Director
- -----------------------------
John W. Preston
* Director, President and Chief
- ----------------------------- Executive Officer
Ernest G. Sapieha (Principal Executive Officer)
Director
- -----------------------------
Jeffrey T. Smith
*By: /s/ Norman G. Knecht
---------------------------------
Name: Norman G. Knecht
Title: Attorney-in-Fact
SIGNATURES
Pursuant to the requirements of the Securities Act of 1933, Hornet
Energy Ltd. has duly caused this Amendment No. 2 to the Registration Statement
to be signed on its behalf by the undersigned, thereunto duly authorized, in the
City of Calgary, Province of Alberta, Canada, on October 16, 2002.
HORNET ENERGY LTD.
By: /s/ Norman G. Knecht
---------------------------------------
Name: Norman G. Knecht
Title: Vice-President, Finance and
Chief Financial Officer
Pursuant to the requirements of the Securities Act, this Amendment No.
2 to the Registration Statement has been signed by the following persons in the
capacities indicated on October 16, 2002.
SIGNATURE TITLE
- --------- -----
* President and Chief Executive Officer
- ----------------------------- and Director
Ernest G. Sapieha
/s/ Norman G. Knecht Vice President, Finance and Chief
- ----------------------------- Financial Officer
Norman G. Knecht
* Director
- -----------------------------
John W. Preston
*By: /s/ Norman G. Knecht
---------------------------------
Name: Norman G. Knecht
Title: Attorney-in-Fact
SIGNATURES
Pursuant to the requirements of the Securities Act of 1933, 867791
Alberta Ltd. has duly caused this Amendment No. 2 to the Registration Statement
to be signed on its behalf by the undersigned, thereunto duly authorized, in the
City of Calgary, Province of Alberta, Canada, on October 16, 2002.
867791 ALBERTA LTD.
By: /s/ Norman G. Knecht
---------------------------------------
Name: Norman G. Knecht
Title: Secretary
Pursuant to the requirements of the Securities Act, this Amendment No.
2 to the Registration Statement has been signed by the following persons in the
capacities indicated on October 16, 2002.
SIGNATURE TITLE
- --------- -----
* President and sole director
- -----------------------------
Ernest G. Sapieha
/s/ Norman G. Knecht Secretary
- -----------------------------
Norman G. Knecht
*By: /s/ Norman G. Knecht
---------------------------------
Name: Norman G. Knecht
Title: Attorney-in-Fact
SIGNATURES
Pursuant to the requirements of the Securities Act of 1933, 899776
Alberta Ltd. has duly caused this Amendment No. 2 to the Registration Statement
to be signed on its behalf by the undersigned, thereunto duly authorized, in the
City of Calgary, Province of Alberta, Canada, on October 16, 2002.
899776 ALBERTA LTD.
By: /s/ Norman G. Knecht
---------------------------------------
Name: Norman G. Knecht
Title: Vice-President, Finance
Pursuant to the requirements of the Securities Act, this Amendment No.
2 to the Registration Statement has been signed by the following persons in the
capacities indicated on October 16, 2002.
SIGNATURE TITLE
- --------- -----
* President and Director
- -----------------------------
Ernest G. Sapieha
/s/ Norman G. Knecht Vice-President, Finance and Director
- -----------------------------
Norman G. Knecht
*By: /s/ Norman G. Knecht
---------------------------------
Name: Norman G. Knecht
Title: Attorney-in-Fact
AUTHORIZED REPRESENTATIVE
Pursuant to the requirements of Section 6(a) of the Securities Act of
1933, the Authorized Representative has signed this Amendment No. 2 to the
Registration Statement, solely in the capacity of the duly authorized
representative of Compton Petroleum Corporation, Hornet Energy Ltd., 867791
Alberta Ltd., 899776 Alberta Ltd. and Compton Petroleum in the United States, on
October 16, 2002.
COMPTON PETROLEUM (USA) CORPORATION
(Authorized U.S. Representative)
By: /s/ Norman G. Knecht
---------------------------------------
Name: Norman G. Knecht
Title: Authorized Signatory
EXHIBIT INDEX
EXHIBIT
NUMBER DESCRIPTION
- ------- -----------
3.1* Articles of Incorporation of Compton Petroleum Corporation.
3.2* Articles of Incorporation of Hornet Energy Ltd.
3.3* Articles of Incorporation of 867791 Alberta Ltd.
3.4* Articles of Incorporation of 899776 Alberta Ltd.
3.5* Declaration of Partnership of Compton Petroleum.
3.6* By-laws of Compton Petroleum Corporation.
3.7* By-laws of Hornet Energy Ltd.
3.8* By-laws of 867791 Alberta Ltd.
3.9* By-laws of 899776 Alberta Ltd.
3.10* Partnership Agreement of Compton Petroleum.
4.1* Indenture, dated as of May 8, 2002, among Compton Petroleum
Corporation, Hornet Energy Ltd., 867791 Alberta Ltd., 899776
Alberta Ltd., Compton Petroleum and the Bank of Nova Scotia
Trust Company of New York, as trustee.
4.2* Form of Note.
5.1** Opinion of Fraser Milner Casgrain LLP regarding the legality
of the notes and subsidiary guarantees.
5.2* Opinion of Paul, Weiss, Rifkind, Wharton & Garrison regarding
the legality of the notes and subsidiary guarantees.
8.1** Opinion of Fraser Milner Casgrain LLP regarding Canadian tax
matters, included in Exhibit 5.1 hereto.
8.2** Opinion of Paul, Weiss, Rifkind, Wharton & Garrison regarding
U.S. tax matters.
10.1* Registration Rights Agreement, dated as of May 8, 2002 among
Compton Petroleum Corporation, Hornet Energy Ltd., 867791
Alberta Ltd., 899776 Alberta Ltd., Compton Petroleum, Lehman
Brothers, BMO Nesbitt Burns, Scotia Capital and TD Securities.
10.2* Second Amended and Restated Extendible Credit Agreement, dated
May 8, 2002, between Compton Petroleum Corporation and the
Bank of Montreal, The Bank of Nova Scotia and the
Toronto-Dominion Bank.
10.3* Employment Agreement, dated April 22, 1998, between Compton
Petroleum Corporation and Kim Davies.
10.4* Employment Agreement, dated April 22, 1998, between Compton
Petroleum Corporation and Norman G. Knecht.
10.5* Employment Agreement, dated April 22, 1998, between Compton
Petroleum Corporation and Ernest G. Sapieha.
10.6* Employment Agreement, dated April 22, 1998, between Compton
Petroleum Corporation and Murray J. Stodalka.
12.1* Statement regarding computation of ratios.
21.1* List of subsidiaries.
23.1** Consent of Fraser Milner Casgrain LLP, included in Exhibit 5.1
hereto.
23.2** Consent of Grant Thornton LLP.
23.3* Consent of Outtrim Szabo Associates Ltd.
23.4* Consent of Paul, Weiss, Rifkind, Wharton & Garrison.
24.1* Powers of Attorney (included on the signature page hereto).
25.2* Statement of Eligibility on Form T-1 of The Bank of Nova
Scotia Trust Company of New York.
99.1* Form of Letter of Transmittal.
99.2* Form of Notice of Guaranteed Delivery.
- ------------------------
* Previously filed.
** Filed herewith.