EXHIBIT 20.1
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[LOGO - COMPTON PETROLEUM CORPORATION]
ANNUAL INFORMATION FORM
FOR THE YEAR ENDED DECEMBER 31, 2005
COMPTON PETROLEUM CORPORATION
March 23, 2006
TABLE OF CONTENTS
PAGE
ABBREVIATIONS AND CONVERSION FACTORS.........................................2
DEFINITIONS..................................................................3
ADVISORIES...................................................................8
CORPORATE STRUCTURE..........................................................8
GENERAL DEVELOPMENT OF THE BUSINESS..........................................9
DESCRIPTION OF THE BUSINESS.................................................10
RISK FACTORS................................................................15
STATEMENT OF RESERVES DATA..................................................19
PRICING ASSUMPTIONS.........................................................23
RECONCILIATION OF CHANGES IN RESERVES AND FUTURE NET REVENUE................24
ADDITIONAL INFORMATION RELATING TO RESERVES DATA............................26
OTHER OIL AND GAS INFORMATION...............................................28
DIVIDENDS...................................................................33
CAPITAL STRUCTURE...........................................................33
MARKET FOR SECURITIES.......................................................34
CONFLICTS OF INTEREST.......................................................34
INTERESTS OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS.................34
MATERIAL CONTRACTS..........................................................35
INTERESTS OF EXPERTS........................................................35
RATINGS ....................................................................35
DIRECTORS AND OFFICERS......................................................36
AUDIT, FINANCE AND RISK COMMITTEE INFORMATION...............................38
COMPOSITION OF AUDIT, FINANCE AND RISK COMMITTEE............................38
EXTERNAL AUDITOR FEES.......................................................38
TRANSFER AGENT AND REGISTRAR................................................39
ADDITIONAL INFORMATION......................................................39
SCHEDULE A..................................................................40
SCHEDULE B..................................................................42
SCHEDULE C..................................................................44
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ABBREVIATIONS AND CONVERSION FACTORS
ABBREVIATIONS
The following are abbreviations of technical term used throughout this Annual
Information Form:
"BBL" means barrel;
"BBLS" means barrels;
"BCF" means billion cubic feet;
"BOE" means barrels of crude oil equivalent;
"BOEPD" or "BOE/D" means barrels of crude oil equivalent per day;
"BOPD" means barrels of crude oil per day;
"LT" means long ton;
"MBBLS" means thousand barrels;
"MBOE" means thousand barrels of crude oil equivalent;
"MCF" means thousand cubic feet;
"MMBBLS" means million barrels;
"MMBOE" means million barrels of crude oil equivalent;
"MMCF" means million cubic feet;
"MCFE" means thousand cubic feet equivalent;
"MMCFD" or "MMCF/D" means million cubic feet per day;
"MLT" means thousands of long tons;
"MSTB" means thousand stock tank barrels; and
"NGLS" means natural gas liquids.
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CONVERSION FACTORS
To conform with common usage, Standard Imperial Units of measurement are used
in this Annual Information Form to describe exploration and production
activities. The following table sets forth conversions between Standard
Imperial Units and the International System of Units (or metric units).
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TO CONVERT FROM TO MULTIPLY BY
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cubic feet cubic metres 0.028174
boe Mcfe 6.000
cubic metres of gas cubic feet 35.490
bbls cubic metres 0.159
cubic metres of oil bbls 6.289
feet metres 0.305
metres feet 3.281
miles kilometres 1.609
kilometres miles 0.621
acres hectares 0.405
hectares acres 2.471
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DEFINITIONS
The following terms, when used in this document, have the following meanings,
as set forth in National Instrument 51-101.
"ASSOCIATED GAS" means the gas cap overlying a crude oil accumulation in a
reservoir.
"CONSTANT PRICES AND COSTS" means prices and costs used in an estimate that
are:
(a) the company's prices and costs as at the effective date of the
estimation, held constant throughout the estimated lives of the
properties to which the estimate applies; and
(b) if, and only to the extent that, there are fixed or presently
determinable future prices or costs to which the company is legally
bound by a contractual or other obligation to supply a physical
product, including those for an extension period of a contract that
is likely to be extended, those prices or costs rather than the
prices and costs referred to in paragraph (a).
For the purpose of paragraph (a), the reporting issuer's prices will be the
posted price for oil and the spot price for gas, after historical adjustments
for transportation, gravity and other factors.
"COMPANY" or "COMPTON" or "WE" means Compton Petroleum Corporation.
"CRUDE OIL" or "OIL" means a mixture that consists mainly of pentanes and
heavier hydrocarbons, which may contain sulphur and other non-hydrocarbon
compounds, that is recoverable at a well from an underground reservoir and that
is liquid at the conditions under which its volume is measured or estimated. It
does not include solution gas or natural gas liquids.
"DEVELOPED NON-PRODUCING" reserves are those reserves that either have not been
on production, or have previously been on production, but are shut-in and the
date of resumption of production is unknown.
"DEVELOPED PRODUCING" reserves are those reserves that are expected to be
recovered from completion intervals open at the time of the estimate. These
reserves may be currently producing or, if shut-in, they must have previously
been on production and the date of resumption of production must be known with
reasonable certainty.
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"DEVELOPMENT COSTS" means costs incurred to obtain access to reserves and to
provide facilities for extracting, treating, gathering and storing the oil and
gas from the reserves. More specifically, development costs, including
applicable operating costs of support equipment and facilities and other costs
of development activities, are costs incurred to:
(a) gain access to and prepare well locations for drilling, including
surveying well locations for the purpose of determining specific
development drilling sites, clearing ground, draining, road
building, and relocating public roads, gas lines and power lines, to
the extent necessary in developing the reserves;
(b) drill and equip development wells, development type stratigraphic
test wells and service wells, including the costs of platforms and
of well equipment such as casing, tubing, pumping equipment and the
wellhead assembly;
(c) acquire, construct and install production facilities such as flow
lines, separators, treaters, heaters, manifolds, measuring devices,
production storage tanks, natural gas cycling and processing plants
and central utility and waste disposal systems; and
(d) provide improved recovery systems.
"DEVELOPMENT WELL" means a well drilled inside the established limits of an oil
or gas reservoir, or in close proximity to the edge of the reservoir, to the
depth of a stratigraphic horizon known to be productive.
"EUB" means the Alberta Energy and Utilities Board.
"EXPLORATION COSTS" means costs incurred in identifying areas that may warrant
examination and in examining specific areas that are considered to have
prospects that may contain oil and gas reserves, including costs of drilling
exploratory wells and exploratory type stratigraphic test wells. Exploration
costs may be incurred both before acquiring the related property (sometimes
referred to in part as "prospecting costs") and after acquiring the property.
Exploration costs, which include applicable operating costs of support
equipment and facilities and other costs of exploration activities, are:
(a) costs of topographical, geochemical, geological and geophysical
studies, rights of access to properties to conduct those studies and
salaries and other expenses of geologists, geophysical crews and
others conducting those studies (collectively sometimes referred to
as "geological and geophysical costs");
(b) costs of carrying and retaining unproved properties, such as delay
rentals, taxes (other than income and capital taxes) on properties,
legal costs for title defense and the maintenance of land and lease
records;
(c) dry hole contributions and bottom hole contributions;
(d) costs of drilling and equipping exploratory wells; and
(e) costs of drilling exploratory type stratigraphic test wells.
"EXPLORATORY WELL" means a well that is not a development well, a service well
or a stratigraphic test well.
"FIELD" means an area consisting of a single reservoir or multiple reservoirs
all grouped on or related to the same individual geological structural feature
and/or stratigraphic condition. There may be two or more reservoirs in a field
that are separated vertically by intervening impervious strata or laterally by
local geologic barriers or both. Reservoirs that are associated by being in
overlapping or adjacent fields may be treated as a single or common operational
field. The geological terms "structural feature" and "stratigraphic condition"
are intended to denote
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localized geological features, in contrast to broader terms such as "basin",
"trend", "province", "play" or "area of interest".
"FUTURE PRICES AND COSTS" means future prices and costs that are:
(a) generally accepted as being a reasonable outlook of the future;
(b) if, and only to the extent that, there are fixed or presently
determinable future prices or costs to which the Company is legally
bound by a contractual or other obligation to supply a physical
product, including those for an extension period of a contract that
is likely to be extended, those prices or costs rather than the
prices and costs referred to in paragraph (a).
"FUTURE INCOME TAX EXPENSES" means future income tax expenses estimated
year-by-year:
(a) making appropriate allocations of estimated unclaimed costs and
losses carried forward for tax purposes, between oil and gas
activities and other business activities;
(b) without deducting estimated future costs (such as Crown royalties)
that are not deductible in computing taxable income;
(c) taking into account estimated tax credits and allowances; and
(d) applying to the future, pre-tax cash flows relating to the Company's
oil and gas activities and the appropriate year end statutory tax
rates, taking into account future tax rates already legislated.
"FUTURE NET REVENUE" means the estimated net amount to be received with respect
to the development and production of reserves estimated using constant prices
and costs or forecast prices and costs.
"GROSS" means:
(a) in relation to the Company's interest in production or reserves, its
working interest (operating or non-operating) share before deduction
of royalties and without including any royalty interests of the
Company;
(b) in relation to wells, the total number of wells in which the Company
has an interest; and
(c) in relation to properties, the total area of properties in which the
Company has an interest.
"LIQUIDS" means crude oil, natural gas liquids and sulphur.
"NATURAL GAS" or "GAS" means the lighter hydrocarbons and associated
non-hydrocarbon substances occurring naturally in an underground reservoir,
which under atmospheric conditions are essentially gases but which may contain
natural gas liquids. Natural gas can exist in a reservoir either dissolved in
crude oil (solution gas) or in a gaseous phase (associated gas or
non-associated gas). Non-hydrocarbon substances may include hydrogen sulphide,
carbon dioxide and nitrogen.
"NATURAL GAS LIQUIDS" means those hydrocarbon components that can be recovered
from natural gas as liquids including, but not limited to, ethane, propane,
butanes, pentanes plus, condensate and small quantities of non-hydrocarbons.
"NET" means:
(a) in relation to the Company's interest in production or reserves its
working interest (operating or non-operating) share after deduction
of royalty obligations, plus its royalty interests in production or
reserves;
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(b) in relation to the Company's interest in wells, the number of wells
obtained by aggregating the Company's working interest in each of
its gross wells; and
(c) in relation to the Company's interest in a property, the total area
of properties in which the Company has an interest multiplied by the
working interest owned by the Company.
"NON-ASSOCIATED GAS" means an accumulation of natural gas in a reservoir where
there is no crude oil.
"OPERATING COSTS" or "PRODUCTION COSTS" means costs incurred to operate and
maintain wells and related equipment and facilities, including applicable
operating costs of support equipment, facilities and other costs of operating
and maintaining those wells and related equipment and facilities.
"PROBABLE" reserves are those additional reserves that are less certain to be
recovered than proved reserves. It is equally likely that the actual remaining
quantities recovered will be greater or less than the sum of the estimated
proved plus probable reserves.
"PRODUCTION" means recovering, gathering, treating, field or plant processing
(for example, processing gas to extract natural gas liquids) and field storage
of oil and gas.
"PROPERTY" includes:
(a) fee ownership or a lease, concession, agreement, permit, licence or
other interest representing the right to extract oil or gas, subject
to such terms as may be imposed by the conveyance of that interest;
(b) royalty interests, production payments payable in oil or gas and
other non-operating interests in properties operated by others; and
(c) an agreement with a foreign government or authority under which a
reporting issuer participates in the operation of properties or
otherwise serves as producer of the underlying reserves (in contrast
to being an independent purchaser, broker, dealer or importer).
A property does not include supply agreements or contracts that represent a
right to purchase, rather than extract, oil or gas.
"PROPERTY ACQUISITION COSTS" means costs incurred to acquire a property
directly by purchase or lease, or indirectly by acquiring another corporate
entity with an interest in the property, including:
(a) costs of lease bonuses and options to purchase or lease a property;
(b) the portion of the costs applicable to hydrocarbons when land
including rights to hydrocarbons is purchased in fee; and
(c) brokers' fees, recording and registration fees, legal costs and
other costs incurred in acquiring properties.
"PROVED" reserves are those reserves that can be estimated with a high degree
of certainty to be recoverable. It is likely that the actual remaining
quantities recovered will exceed the estimated proved reserves. Nine out of ten
times, proved reserves are likely to increase.
"PROVED PROPERTY" means a property or part of a property to which reserves have
been specifically attributed.
"RESERVES" are estimated remaining quantities of oil, natural gas and related
substances anticipated to be recoverable from known accumulations, from a given
date forward, based on (a) analysis of drilling, geological, geophysical and
engineering data; (b) the use of established technology; and (c) specified
economic conditions, which are generally
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accepted as being reasonable and shall be disclosed. Reserves are classified
according to the degree of certainty associated with the estimates.
"RESERVOIR" means a porous and permeable underground formation containing a
natural accumulation of producible oil or gas that is confined by impermeable
rock or water barriers and is individual and separate from other reservoirs.
"SERVICE WELL" means a well drilled or completed for the purpose of supporting
production in an existing field. Wells in this class are drilled for the
following specific purposes: gas injection (natural gas, propane, butane or
flue gas), water injection, steam injection, air injection, salt water
disposal, water supply for injection, observation or injection for combustion.
"SHUT IN WELL" means a well which is capable of economic production or which
the Company considers capable of production but which for a variety of reasons,
including, but not limited to, lack of markets or development, is not placed on
production at the present time.
"SOLUTION GAS" means natural gas dissolved in crude oil.
"STRATIGRAPHIC TEST WELL" means a geologically directed drilling effort, to
obtain information pertaining to a specific geologic condition. Ordinarily,
such wells are drilled without the intention of being completed for hydrocarbon
production. They include wells for the purpose of core tests and all types of
expendable holes related to hydrocarbon exploration. Stratigraphic test wells
are classified as (a) "exploratory type" if not drilled into a proved property;
or (b) "development type", if drilled into a proved property. Development type
stratigraphic wells are also referred to as "evaluation wells".
"SUPPORT EQUIPMENT AND FACILITIES" means equipment and facilities used in oil
and gas activities, including seismic equipment, drilling equipment,
construction and grading equipment, vehicles, repair shops, warehouses, supply
points, camps and division, district or field offices.
"UNDEVELOPED" reserves are those reserves expected to be recovered from known
accumulations where a significant expenditure, when compared to the cost of
drilling a well, is required to render them capable of production. They must
fully meet the requirements of the reserves classification (proved, probable,
possible) to which they are assigned.
"UNPROVED PROPERTY" means a property or part of a property to which no reserves
have been specifically attributed.
"WELL ABANDONMENT COSTS" means costs of abandoning a well (net of salvage
value) and of disconnecting the well from the surface gathering system. Costs
of abandoning the gathering system or reclaiming the wellsite are not included.
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ADVISORIES
USE OF BOE EQUIVALENTS
The oil and natural gas industry commonly expresses production volumes and
reserves on a barrel of oil equivalent ("BOE") basis whereby natural gas
volumes are converted at the ratio of six thousand cubic feet to one barrel of
oil. The intention is to sum oil, ngl, and natural gas measurement units into
one basis for improved measurement of results and comparisons with other
industry participants. In several sections that follow, Compton has used the
6:1 boe measure which is the approximate energy equivalency of the two
commodities at the burner tip. However, boes do not represent a value
equivalency at the plant gate where Compton sells its production volumes and
therefore may be a misleading measure if used in isolation.
FORWARD LOOKING STATEMENTS
Certain information regarding the Company contained herein constitutes forward
looking statements under the meaning of applicable securities laws, including
the United States Private Securities Litigation Reform Act of 1995.
Forward-looking statements include estimates, plans, expectations, opinions,
forecasts, projections, guidance, or other statements that are not statements
of fact, including statements regarding (i) cash flow, 2006 production
estimates, reserve estimates, capital expenditures, 2006 drilling program, tax
estimates, total future net revenue, pricing assumptions, abandonment and
reclamation costs, and (ii) other risks and uncertainties described from time
to time in the reports and filings made by Compton with securities regulatory
authorities. Although Compton believes that the expectations reflected in such
forward looking statements are reasonable, it can give no assurance that such
expectations will prove to have been correct. There are many factors that could
cause forward looking statements not to be correct, including risks and
uncertainties inherent in the Company business. These risks include, but are
not limited to: crude oil and natural gas price volatility, exchange rate
fluctuations, availability of services and supplies, operating hazards and
mechanical failures, uncertainties in the estimates of reserves and in
projection of future rates of production and timing of development
expenditures, general economic conditions, and the actions or inactions of
third-party operators, and other risks set forth in the "Risk Factors" section
of this Annual Information Form. Compton may, as considered necessary in the
circumstances, update or revise forward looking information, whether as a
result of new information, future events, or otherwise. The Company's forward
looking statements are expressly qualified in their entirety by this cautionary
statement.
CORPORATE STRUCTURE
NAME AND INCORPORATION
Compton was incorporated by articles of incorporation pursuant to the
provisions of the Business Corporations Act (Alberta) on October 15, 1992, as
544201 Alberta Ltd. The articles were amended on April 13, 1993, to change the
Company's name to Compton Petroleum Corporation and the Company commenced
active business operations in July 1993. The articles were amended on November
21, 1994 and March 1, 1996, in order to remove the private company restrictions
contained in the articles. A further amendment was made to the articles on
September 1, 1998, in order to create a class of preferred shares issuable in
series.
The Company's head and principal office is located at Suite 3300, 425 - 1st
Street S.W., Fifth Avenue Place, East Tower, Calgary, Alberta, Canada, T2P 3L8.
Compton's registered office is located at Suite 3000, 237 - 4th Avenue, S.W.,
Fifth Avenue Place, West Tower, Calgary, Alberta, Canada, T2P 4X7.
Effective January 31, 2001, a general partnership called Compton Petroleum was
formed under the laws of Alberta. Compton Petroleum Corporation and Hornet
Energy Ltd, a wholly-owned subsidiary of Compton Petroleum Finance Corporation,
are the partners of the partnership. The majority of our production activities
are carried out through this partnership.
Compton Petroleum Finance Corporation, formed under the laws of Alberta, is a
wholly-owned subsidiary of Compton Petroleum Corporation. Compton Petroleum
Finance Corporation has no independent operations and has no significant
liabilities or assets other than US$300 million of 7 5/8% Senior Notes, its
equity interest in Hornet Energy
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Ltd. and intercorporate indebtedness. The registered office of Compton
Petroleum Finance Corporation is 4300 Bankers Hall West, 888 - 3rd Street S.W.,
Calgary, Alberta, Canada, T2P 5C5.
Compton Petroleum Holdings Corporation, formed under the laws of Alberta, is a
wholly-owned subsidiary of Compton Petroleum Corporation. Compton Petroleum
Holdings Corporation has no independent operations and has no significant
liabilities or assets other than owning US$158,250,000 aggregate principal
amount of 9.90% Notes and intercorporate indebtedness. The registered office of
Compton Petroleum Holdings Corporation is 4300 Bankers Hall West, 888 - 3rd
Street S.W., Calgary, Alberta, Canada, T2P 5C5.
[GRAPHIC OMITTED -- ORGANIZATIONAL CHART]
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100% ---------- Compton Petroleum Corporation ----------- 96%
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| | |
| 100% |
| | |
- -------------------- ------------------------- -----------------
Compton Petroleum Compton Petroleum Finance Compton Petroleum
Holdings Corporation Corporation (partnership)
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| |
100% 4%
| |
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Hornet Energy Ltd. ----------------
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The consolidated financial statements include the accounts of the Company and
all of its subsidiaries and partnerships.
GENERAL DEVELOPMENT OF THE BUSINESS
Compton is an Alberta based independent public company actively engaged in the
exploration, development, and production of natural gas, ngls, and crude oil in
the Western Canada Sedimentary Basin (the "WCSB") in Canada. Compton commenced
operations in 1993 with $1 million of share capital, a small dedicated
technical team, and a large seismic database. The objective was to build a
company through internal, full cycle exploration, complemented by strategic
acquisitions. Compton's goal was to create a company capable of long term
sustained growth with a primary focus on natural gas. Compton's focus and
strategy have remained unchanged since conception. Compton's shares are listed
on the Toronto Stock Exchange under the symbol CMT and on the New York Stock
Exchange under the symbol CMZ.
THREE YEAR HISTORY
In 2003, Compton focused on the resolution of pipeline and facility constraints
in its Southern Alberta core area. The Mazeppa Processing Partnership, which is
not affiliated with Compton, purchased the Mazeppa and Gladys natural gas
plants with related compression facilities and pipelines in Southern Alberta.
The partnership is managed and controlled by Compton and provided Compton
flexibility to pursue and accelerate various processing alternatives, including
plant expansions. The Hooker pipeline system was expanded to 80 MMcf/d and
natural gas production from Brant was offloaded to the ATCO sales pipeline.
With processing restrictions removed, Compton was then able to continue to
explore lands adjacent to the Mazeppa, Gladys, and Brant pipeline and plant
infrastructures.
The Company continued to pursue the exploration and development of its assets
and prospects in 2003. Compton's capital program totaled $285 million,
including the consolidation of the Mazeppa gas plant expenditures. The Company
drilled 168 gross (134 net) wells in 2003 with an 83% success rate.
In 2004, the expansion of the Mazeppa gas plant from 90 MMcf/d to 135 MMcf/d
through the addition of 45 MMcf/d of sweet gas processing capacity was
completed. This expanded Compton's processing capacity in Southern Alberta to
200 MMcf/d and removed all restrictions. The Mazeppa Processing Partnership
completed the $75 million external financing of the acquisition, expansion, and
operations of the Mazeppa facilities and repaid funds borrowed from Compton.
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Consolidated capital expenditures totaled $316 million in 2004 and Compton
drilled 186 gross (146 net) wells with a 90% success rate. Of the wells
drilled, 77% were classified as development wells and 23% were classified as
exploratory wells. Approximately 26 MMBoe was added to the Company's proved
plus probable reserves through drilling successes, acquisitions, and
extensions. Total proved plus probable reserves increased 22% from the prior
year to 145 MMBoe.
In 2005, progress was made on each of the Company's five resource plays
including the Edmonton Horseshoe Canyon coalbed methane, plains Belly River,
Basal Quartz at Hooker and thrusted, foothills Belly River at Callum in
Southern Alberta, and the Rock Creek/Gething play at Niton in Central Alberta.
Compton was one of the top 10 most active operators in Canada throughout the
year. The Company's consolidated capital program of $513 million, included
drilling 392 gross (334 net) wells with a 96% success rate. The drilling
program resulted in an exit production rate of 35,500 boe/d and average
production of 29,424 boe/d for the year. High commodity prices and increased
production generated record revenue of $558 million.
Compton's proved plus probable reserves totaled 207 MMBoe as at December 31,
2005. Approximately 62 MMBoe was added to the Company's proved plus probable
reserves through drilling successes, acquisitions, and extensions.
DESCRIPTION OF THE BUSINESS
EXPLORATION AND PRODUCTION OPERATIONS
Compton's exploration, development and exploitation activities are concentrated
principally in three core areas: 1) Southern Alberta targeting the plains Belly
River, Edmonton Horseshoe Canyon coalbed methane ("CBM"), Hooker Basal Quartz
and thrusted, foothills Belly River at Callum; 2) Central Alberta targeting the
Gething/Rock Creek at Niton; and 3) the Peace River Arch area producing from
the Charlie Lake pool at Cecil/Worsley. These areas are the geographic focus of
Compton's seismic database and are areas in which Compton's Management
("MANAGEMENT") and staff have significant technical expertise and operational
experience.
BUSINESS PLAN AND OPERATING STRATEGY
The Company's business plan is to grow Compton's reserves and maximize
production and cash flow from its core geographic areas and other areas where
Compton has technical expertise. Management is implementing this objective by
focusing on the efficient exploration, development and exploitation of ithe
Company's properties, controlling operating costs, adding economic reserves and
production, and making strategic acquisitions in its core areas. Compton has
experienced professional, management, technical, and support staff sufficient
to carry out its business plan and its current exploration, exploitation,
development, production, engineering, financial, and administrative functions.
The Company's operating strategy includes the components set forth below:
CONCENTRATE ON CORE AREAS. Compton is focused on its core areas, which provide
a balanced portfolio of exploration, development, and exploitation prospects.
These areas are the geographic focus of the Company's seismic database rights,
and are areas in which Management and staff have significant technical
expertise and operational experience. Compton intends to generate exploration
opportunities and to increase the Company's undeveloped land base within the
WCSB.
FOCUS ON UNCONVENTIONAL NATURAL GAS IN LARGE RESOURCE PLAYS. As of December 31,
2005, 73% of proved reserves were natural gas. The Company has gained
considerable technical expertise and achieved significant success in exploring
for unconventional, larger natural gas accumulations in the WCSB. Compton plans
to continue to focus on finding and developing these types of natural gas
opportunities because of their generally lower decline curves and higher
economic return over the life of the reserves compared to conventional natural
gas opportunities. The large scale nature of the Company's resource plays also
offers multiple low-risk drilling locations resulting in lower costs and
decreased exploration risk.
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PURSUE GROWTH THROUGH THE DRILL BIT COMPLEMENTED BY SELECTIVE ACQUISITIONS.
Compton plans to continue to reinvest internally generated cash flow and to use
other sources of capital to fund the growth of the Company's exploration and
development programs and to further increase its undeveloped land base to
maintain a growing inventory of drilling prospects in core areas. In 2004,
Compton began an accelerated drilling program. Based on plans for an annual
drilling program of 500 to 700 gross wells, the Company has over ten years of
drilling inventory on existing lands. Most of these planned wells are expected
to be in close proximity to producing wells in existing core areas. Compton's
drilling success rate has been at or above 90% for each of the past three
years, providing confidence in the Company's ability to successfully grow
reserves and production from its extensive inventory of drilling locations.
CONTROL INFRASTRUCTURE AND OPERATORSHIP. Compton believes that control over
gathering and processing infrastructure and operatorship of drilling programs
will continue to be critical to the success of the Company's full-cycle
exploration program. Compton currently owns or has access to critical
infrastructure in each of its three core areas. Being an operator ensures
discretion in determining the timing and methodology of ongoing exploration,
development, and exploitation programs. Compton expects to continue to expand
its working interest in core areas to maximize these operating efficiencies.
MAINTAIN FINANCIAL FLEXIBILITY. The Company is committed to maintaining
financial flexibility sufficient to allow it to pursue its full-cycle
exploration program in periods of low commodity prices and to respond to
opportunities for strategic acquisitions as they arise. Compton has
historically funded its exploration, development, and exploitation capital
program through internally generated cash flow and has financed acquisitions
through bank debt, the issuance of common shares, or a combination thereof. The
Company's accelerated drilling program has recently been, and will continue to
be, funded through internally generated cash flow, the issuance of additional
equity and debt, and non-core property sales. Other components of Compton's
financial discipline include establishing appropriate leverage ratios and
maintaining an active commodity hedging program.
PRINCIPAL PROPERTIES
SOUTHERN ALBERTA
Southern Alberta remains the primary focus of Compton's activities. The Company
holds 804,007 (699,751 net) acres of land in the South, which are prospective
for multiple zones including Basal Quartz at Hooker, thrusted Belly River at
Callum, Wabamun/Crossfield, Plains Belly River, and Edmonton/CBM. In 2005,
Compton drilled 195 (183 net) wells in Southern Alberta with a 99% success
rate. The Company anticipates spending $361 million and drilling 277 wells in
the area in 2006.
HOOKER BASAL QUARTZ
During the past year, Compton continued the development of its Lower Cretaceous
Basal Quartz resource play at Hooker. The play covers an extensive area of
260,270 (195,200 net) acres. In 2005, the Company drilled 27 wells, extending
the productive limits and optimizing reserve recovery in the heart of the pool.
In 2005, Compton designed and completed several advanced core and log analysis
studies to gain a better understanding of the petrophysical characteristics of
the play. As a result of this work, the Company now estimates that the Hooker
pool contains at least 1.5 TCF of gas-in-place. Compton is currently conducting
further engineering and geological studies to confirm its expectations that the
gas-in-place may be greater than initially determined. It has also become
evident that the edges of the Hooker pool are not yet clearly identified and as
such, Compton has designed its 2006 drilling program to infill and extend the
productive limits of the pool.
The Hooker play is currently drilled on one to two wells per section, however,
engineering models and geological studies indicate that at least three wells
per section will be required to maximize reserve recovery from this low
permeability gas pool. Compton has made an application to the EUB to conduct a
pilot drilling program on two sections in the pool to evaluate the
effectiveness of reduced spacing.
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PLAINS BELLY RIVER AND HORSESHOE CANYON COALBED METHANE
In 2005, the Company drilled 170 Belly River wells in the Centron, Gladys, and
Brant areas, with all wells encountering multiple pay sections and uphole
producible Edmonton/Horseshoe Canyon Coals. The Belly River drilling program
continues to exceed expectations.
Compton further refined its Belly River seismic and geological models during
the year. The use of the Company's extensive 3D and 2D seismic database was
critical to identifying the best producible sands. The models were tested and
confirmed through drilling.
Compton currently has approval to drill two wells per section on seven
townships of land. The Alberta Energy and Utilities Board recently announced a
phased modification to spacing for the Belly River in Southern Alberta that is
intended to see the standard spacing change from one well per section to four
wells per section. This initiative would effectively double the number of Belly
River drilling locations in the Company's inventory. In anticipation of reduced
spacing approval, Compton initiated three 3D seismic programs to assist in the
identification of downspace locations. Drilling in select areas on reduced
spacing is expected to start during the third quarter of 2006. This will allow
Compton to dramatically ramp up its Belly River/Edmonton drilling program,
commencing in 2007.
Compton will also define the optimum development of the vertical section of
Belly River and Edmonton Horseshoe Canyon zones. The Company plans to drill 250
wells in 2006 that will have the potential to be completed in both zones. In
addition, Compton has drilled over 400 wells through the Edmonton Horseshoe
Canyon formation into the Belly River sands and the Company is planning to
re-complete 70 of these wells in the Edmonton in 2006.
Compton holds 664,175 (597,760 net) acres of land in Southern Alberta that is
prospective for dry Edmonton Horseshoe Canyon coalbed methane and the
underlying Plains Belly River sands. During 2005, Compton drilled and cored
four CBM pilots across its Southern Alberta acreage to gather the necessary
geological evidence to better quantify its CBM resource potential. Each pilot
consisted of four to six wells, for a total of 19 wells drilled. In-line flow
testing on the initial pilots commenced in the first quarter of 2006 and two
additional pilots are in various stages of well licensing.
The pilots assessed the potential of 483,560 (435,200 net) acres of the
Company's lands in the South. Compton worked closely with Netherland, Sewell &
Associates, Inc., ("Netherland Sewell") independent reserve evaluators,
throughout the pilot programs to quantify the resource potential associated
with the Horseshoe Canyon coals. Netherland Sewell has determined the original
unrisked gas-in-place in the Horseshoe Canyon coals to be 3.05 Tcf and Compton
estimates the net original unrisked gas-in-place on the Company's acreage to be
2.7 Tcf. This gas-in-place number is restricted to the coals only, with no
interbedded Edmonton sands, silts, or shales included. Additionally, the pilot
evaluations excluded any potential gas that may be present in the overlying
Scollard Formation.
As confirmed by well logs, the remaining 177,780 (160,000 net) acres of
Compton's acreage contain Edmonton sands, silts, and Horseshoe Canyon coals,
and will require further core confirmation of the gas content. In 2006, Compton
will evaluate and quantify the potential of the Edmonton sands and silts across
the Company's acreage in 2006.
The Company has production from the Edmonton Horseshoe Canyon coals at Centron,
Gladys, Brant, and Ghost Pine. Currently Belly River production extends across
Compton's Southern Alberta lands.
CALLUM THRUSTED BELLY RIVER
The Callum property consists of a series of low permeability, overpressured,
thrusted Upper Cretaceous Belly River sands in the foothills of Southern
Alberta. Subsequent to year end, the Company acquired its partner's working
interest in the play and now holds a 100% interest in 70,400 acres of land.
-12-
In the second quarter of 2005, the Company drilled a 100% working interest
natural gas well at Callum. Specialized core analysis techniques were used to
assist in identifying more prospective intervals and to optimize completion
fluids and frac design parameters. The lowermost sand in the stacked Belly
River sequence was completed in this well and Compton plans to monitor and
analyze this single zone performance before completing prospective uphole
zones. The well was placed on continuous production in December 2005. The first
two weeks of initial production averaged approximately 1,525 boe per day from a
single sand and the well is continuing to produce approximately 300 boe per day
as at the end of February 2006. This well has significantly improved the
Company's geological, geophysical, and engineering models of the play. The
resultant advances in the understanding of this complex reservoir are a major
step forward in the development of the Callum play.
The play is technically complex and the key to successfully developing the
Callum prospect rests with rock characterization and completion optimization.
In the eight Compton wells drilled to date, various completion techniques have
been evaluated. All wells have produced gas and initial production ranged from
300 Mcfe/d to 8 MMcfe/d.
A second well was drilled in December 2005, encountering multiple sands. The
well has since been cased and Compton is currently testing. The second well
will be completed using methods pioneered by Compton on its previous well. In
2006, 10 wells are planned at Callum.
Based on Compton's initial detailed geological, geophysical, and engineering
analysis of seismic, cores, well logs, test and production data, Callum appears
to exhibit many similarities to the deep unconventional gas pools of the Rocky
Mountain region of the United States, specifically in the Greater Green River
Basin in Wyoming.
CENTRAL ALBERTA
Central Alberta provides Compton with excellent exploration and development
drilling opportunities using analogous techniques gained through its years of
experience in Southern Alberta unconventional gas development. Compton has an
average 55% working interest in 541,643 (297,475 net) acres of land. In 2005,
the Company drilled 73 (38 net) wells with a 97% success rate and plans to
drill 90 wells in the area in 2006.
NITON
The Niton area, where the majority of Compton's Central Alberta acreage lies,
is characterized by multi-zone, deep basin targets analogous to the Hooker pool
in Southern Alberta. The Company has an interest in 137,390 (103,040 net) acres
of land in the play targeting the Gething and Rock Creek formations. In 2005,
33 wells were drilled and results have continued to exceed expectations.
As a result of the Company's successful drilling program at Niton, the Compton
owned McLeod River gas plant will be operating at maximum capacity of 20 MMcf/d
in the first half of 2006. The Company is currently evaluating plant expansion
alternatives, as well as the option of routing a portion of its production to
adjacent non-operated plants, in which the Company holds minor working
interests.
PEACE RIVER ARCH
The Peace River Arch area, located north of Grande Prairie, contains multi-zone
exploration and development opportunities. This area includes both light oil
production at Cecil/Worsley and natural gas exploration at Howard and Pouce
Coupe. The Company averages a 61% working interest in 199,040 (121,634 net)
acres of land in the area. In 2005, Compton drilled 124 (114 net) wells in the
Arch with an 89% success rate and plans to drill 106 wells in 2006.
CECIL/WORSLEY
Compton's 2005 drilling program at Worsley was extremely successful,
significantly increasing the reserve value and production from the area. The
Company drilled 80 Charlie Lake oil wells, more than twice the original number
budgeted, which resulted in pool boundary extensions in all directions.
-13-
Approval for a pool wide waterflood on the Charlie Lake H and J pool at Worsley
was received in February 2005 and a total of eight wells have been converted to
injectors thus far. The waterflood is projected to increase the ultimate
recovery factor for the pool to 25% from 15% on primary depletion. The Company
will continue its program at Worsley in 2006 and anticipates drilling 90 wells
in the upcoming year.
At Cecil, 23 100% working interest and 9 non-operated 40% working interest
horizontal Charlie Lake oil wells were drilled in 2005. All wells encountered
excellent pay zones and have been systematically brought on production
throughout 2005 and into the first quarter of 2006. Compton is undertaking
geological and engineering work to evaluate additional waterflood potential in
the Cecil area. The Company plans to drill 17 wells in 2006 and to focus on
optimizing production from its previously drilled horizontal wells.
PRINCIPAL MARKETS AND DISTRIBUTION METHODS
Compton's natural gas production is sold under a combination of longer term
contracts with aggregators and short term daily or 30 day AECO indexed
contracts. Approximately 10% of the Company's natural gas production in 2005
was committed to aggregators, compared to an average of 11% in 2004. The
average aggregator price realized in 2005 was $1.25/Mcf less than the
non-aggregator prices realized during the year. Natural gas production is
transported through regulated pipelines within Alberta, at tolls requiring
government approval.
The Company's crude oil sales are priced at Edmonton postings and are typically
sold on 30 day evergreen arrangements. Natural gas liquids are bid out on an
annual basis to obtain the most favorable pricing. The Company sells crude oil
and natural gas liquids primarily to refineries and marketers of crude oil and
natural gas liquids. Liquids may be transported through regulated pipelines or
trucked to the point of sale.
ENVIRONMENTAL POLICIES
Compton believes in the importance of protecting the environment. The Company
is committed to conducting all operations in a safe manner that minimizes
environmental impact, while meeting regulatory requirements and corporate
standards. The Company maintains a comprehensive range of internal programs and
controls to promote regulatory compliance and an appropriate level of safety
and environmental protection across its operations. The Company's proactive
program includes annual environmental compliance audit and inspection programs
to ensure Compton's facilities continually meet or exceed regulatory standards.
The Company has participated in programs for continual improvement set forth by
the Canadian Association of Petroleum Producers, Alberta Energy and Utilities
Board, Alberta Environmental Protection, and other related associations, thus
demonstrating Compton's commitment to minimizing the Company's environmental
impact.
The Company carries out its activities in compliance with all relevant
regulations and industry best practices. At present, the Company believes that
it meets all existing environmental standards and regulations and has included
appropriate amounts in its capital expenditure budget to continue to meet
current environmental protection requirements. The Company does not anticipate
making extraordinary material expenditures for environmental compliance during
2006. However, it does expect to incur site restoration costs over a prolonged
period as existing wells become fully produced. Compton provides for future
abandonment and reclamation costs in its financial statements in accordance
with Canadian generally accepted accounting principles.
MAZEPPA PROCESSING PARTNERSHIP
In June of 2003, Mazeppa Processing Partnership ("MPP") acquired certain
midstream assets from an independent third party. The assets consist of major
natural gas gathering and processing facilities in Southern Alberta. Compton
does not have an ownership position in MPP. Through a management agreement,
Compton manages the activities of MPP and is therefore considered to be the
primary beneficiary of MPP's operations. As a result, Compton consolidates the
accounts of MPP for reporting purposes in accordance with the guidelines issued
by the Accounting Standards Board, in Accounting Guideline AcG-15,
"Consolidation of Variable Interest Entities." The results of the midstream
activities are immaterial to Compton's consolidated financial condition.
-14-
EMPLOYEES
As at December 31, 2005, Compton had 155 full-time employees in its Calgary
office and 43 full-time employees at field locations.
COMPETITIVE CONDITIONS
Producers benefited from high oil and gas prices in 2005, increasing revenue
and cash flow. However, higher commodity prices also accelerated capital
programs throughout the industry, resulting in service and supply shortages and
increasing the overall cost of doing business. As commodity prices weakened in
the first few months of 2006 due to unseasonably warm weather and concern over
the high natural gas storage levels, field and operating netbacks decreased.
Land prices continue to climb, adding considerably to finding, development, and
acquisition ("FD&A") costs, as well as consuming a larger portion of annual
budgets. In Compton's core areas, prices at recent land sales are up to four
times what the Company originally paid for its undeveloped acreage.
Drilling rigs, service rigs, equipment, and experienced crews continue to
operate at or near maximum capacity, which results in escalating drilling costs
and inefficiencies. Deeper drilling and more complex plays have contributed to
higher FD&A costs for the industry in general. Strong demand for experienced
professionals has caused a significant increase in salaries and workloads,
further adding to inefficiency in the industry. Additionally, the increasing
complexity and ever changing government rules regarding license applications,
environmental regulations, and governance matters is adding significantly to
overall cost and time required to complete operations.
The mergers and acquisitions ("M&A") market in 2005 was quite strong and it
appears the high level of activity will continue in 2006. The M&A market is
being driven by several factors. High commodity prices and the belief they will
stay high are raising the value of oil and gas producers in the equity market,
while large amounts of available cash in combination with rising FD&A are
encouraging producers to seek growth through acquisitions.
RISK FACTORS
VOLATILITY OF PRICES, MARKETS AND MARKETING PRODUCTION
Oil and gas prices have historically been extremely volatile. The average
prices that the Company currently receives for its production are significantly
higher than historic averages. Factors which contribute to oil and gas price
fluctuations include global demand, domestic and foreign supplies of oil and
gas, the price of foreign oil and gas imports, decisions of the Organization of
Petroleum Exporting Countries relating to export quotas, domestic and foreign
governmental regulations, political conditions in producing regions, global and
domestic economic conditions, the price and availability of alternative fuels,
including liquefied natural gas, and weather conditions.
The Company's financial condition is substantially dependent on, and highly
sensitive to, oil and gas commodity prices. Any material decline in prices
could result in a material reduction of Compton's operating results, revenue,
reserves, and overall value. Lower commodity prices could change the economics
of production from some wells. As a result, the Company could elect not to
drill, develop, or produce from certain wells. In addition, Compton is impacted
by the differential between prices paid by refiners for light quality oil and
the grades of oil produced by the Company.
Under Canadian GAAP, oil and gas assets are reviewed quarterly to determine if
the carrying value of the assets exceeds their expected future cash flows. A
sustained period of low commodity prices may reduce expected future cash flows
and require a write down to the fair value of the Company's oil and gas
properties, thereby adversely affecting operating results.
Any future and sustained period of weakness in oil and gas prices would also
have an adverse effect on the Compton's capacity to borrow funds. The Company's
senior secured credit facilities, as the borrowing amount determined by the
lenders, is based on their estimate of the value of the Company's proved
reserves. A reduction in the quantity or value of reserves may also obligate
Compton to make additional payments under the processing agreement with MPP.
-15-
Any decline in the Company's ability to market production could have a material
adverse effect on production levels or on the sale price received for
production. Compton's ability to market the oil and gas from the Company's
wells depends on numerous factors beyond the Company's control, including the
availability and capacity of gas gathering systems, pipelines and processing
facilities, and their proximity to the wells. The Company will be impacted by
Canadian federal and provincial, as well as U.S. federal and state, energy
policies, taxes, regulation of oil and gas production, processing, and
transportation, as well as Canadian federal regulation of oil and gas sold or
transported outside of the province of Alberta.
NEED TO REPLACE RESERVES
Compton's future success depends upon the Company's ability to find, develop,
or acquire additional oil and gas reserves that are economically recoverable.
Without successful exploration, development, exploitation, or acquisition
activities, the Company's reserves will deplete and, as a consequence, either
production or the average life of reserves will decline. If future production
declines to the extent that cash flow becomes insufficient to fund capital
expenditures, and external sources of capital become limited or unavailable,
the Company's ability to make the necessary capital expenditures to maintain
and expand its oil and gas reserves will be impaired. Compton cannot guarantee
that the Company will be able to find and develop or acquire additional
reserves at an acceptable cost.
Management will continue to evaluate prospects on an ongoing basis in a manner
consistent with industry standards and past practices. The long term commercial
success of the Company depends on its ability to find, acquire, develop, and
commercially produce oil and gas reserves. No assurance can be given that
Compton will be able to locate satisfactory properties for acquisition or
participation. Moreover, if such acquisitions or participations are identified,
the Company may determine that current markets, terms of acquisition and
participation, or pricing conditions make such acquisitions or participations
uneconomic.
Compton's strategies to minimize this inherent risk include focusing on
selected core areas in Western Canada with high working interests and assuming
operatorship of key facilities. The Company utilizes a team of highly qualified
professionals with expertise and experience in these areas. Compton assesses
strategic acquisitions to complement existing activities while striving for a
balance between exploration and lower risk development and exploitation
prospects.
UNCERTAINTY OF RESERVE ESTIMATES
Estimates of oil and gas reserves and the future net cash flow therefrom,
involve a great deal of uncertainty because they depend upon the reliability of
available geologic and engineering data, which is inherently imprecise.
Geologic and engineering data are used to determine the probability that an oil
and gas reservoir exists at a particular location, and whether oil and gas are
recoverable from the reservoir. The probability of the existence and
recoverability of reserves is less than 100% and actual recoveries of proved
reserves may be materially different from estimates.
Estimates of oil and gas reserves require numerous assumptions relating to
operating conditions and economic factors, including future oil and gas prices,
recovery costs, the availability of enhanced recovery techniques, the ability
to market production, and governmental and other regulatory factors, such as
taxes, royalty rates, and environmental laws. A change in one or more of these
factors could result in known quantities of oil and gas previously estimated as
proved reserves becoming unrecoverable. Each of these factors also impact
recovery costs and production rates, and therefore, will reduce the present
value of future net cash flows from estimated reserves.
In addition, estimates of reserves and future net cash flows expected
therefrom, that are prepared by different independent engineers or by the same
engineers at different times, may vary substantially.
EXPLORATION, DEVELOPMENT AND PRODUCTION RISKS
There are many operating risks and hazards inherent in exploring for,
producing, processing, and transporting oil and gas. Drilling operations may
encounter unexpected formations or pressures that could cause damage to
equipment or personal injury and fires, explosions, blowouts, oil spills, or
other accidents may occur. Additionally,
-16-
Compton could experience interruptions to or the termination of drilling,
production, processing, and transportation activities due to bad weather,
natural disasters, delays in obtaining governmental approvals or consents,
insufficient storage or transportation capacity, or other geological and
mechanical conditions. Any of these events resulting in a shutdown or slowdown
of operations, will adversely affect the Company's business. While close well
supervision and effective maintenance operations can contribute to maximizing
production rates over time, production delays and declines from normal field
operating conditions cannot be eliminated and can be expected to adversely
affect revenue and cash flow levels to varying degrees.
Drilling activities, including completions, are subject to the risk that no
commercially productive reservoirs will be encountered and the Company will not
recover all or any portion of its investment. The cost of drilling, completing,
and operating wells is often uncertain due to drilling in unknown formations,
the costs associated with encountering various drilling conditions such as over
pressured zones, and changes in drilling plans and locations as a result of
prior exploratory wells or additional seismic data and interpretations thereof.
INSURANCE
The risks and hazards of Compton's operations could result in damage to, or
destruction of, oil and gas wells, production and processing facilities,
pipelines or other property, environmental damage, or personal injury for which
the Company will be liable. The location of operations near populated areas,
including residential areas, commercial business centers, and industrial sites
could increase these risks and hazards. The Company cannot fully protect
against all of these risks, nor are all of these risks insurable. Compton may
become liable for damages arising from these events against which it cannot
insure or against which it may elect not to insure because of high premium
costs or other reasons. The occurrence of a significant event not fully insured
or indemnified against could seriously harm Compton's financial condition and
operating results.
COMPETITION
The oil and gas industry is highly competitive. The Company competes for
capital, acquisitions of reserves, undeveloped lands, skilled personnel, access
to drilling rigs, service rigs and other equipment, access to processing
facilities, and pipeline and refining capacity with a substantial number of
other organizations, many of which may have greater technical and financial
resources than Compton. Some of these organizations not only explore for,
develop and produce oil and gas but also carry on refining operations and
market crude oil and other products on a worldwide basis. As a result of these
complementary activities, some competitors may have greater and more diverse
competitive resources to draw on than Compton does.
AVAILABILITY OF DRILLING EQUIPMENT AND ACCESS RESTRICTIONS
Compton's drilling operations could be curtailed, delayed, or cancelled as a
result of access restrictions or shortages or delays in the delivery of
equipment and services. Oil and gas industry operations in the WCSB are
affected by road bans imposed from time to time, which can restrict access to
well sites and production facility sites. In addition, landowner constraints or
poor surface conditions could disrupt access to the Company's properties.
Compton's inability to access the Company's properties or to conduct business
as planned could result in a shutdown or slowdown of operations.
Exploration and development activities also depend on the availability of
drilling and related equipment in the particular areas where such activities
will be conducted. Increased demand for that equipment or imposed access
restrictions may affect the availability of equipment to the Company and may
delay exploration and development activities.
ADDITIONAL FUNDING REQUIREMENTS
Compton's ongoing activities may not generate sufficient cash flow from
operations to fund future exploration, development, or acquisition programs.
The Company may require additional funding and there can be no assurance that
debt or equity financing will be available or sufficient to meet these
requirements or that it will be on acceptable terms. Failure to obtain such
financing on a timely basis could cause Compton to forfeit interests in certain
properties, miss certain acquisition opportunities, and reduce or terminate
operations. This may result in the
-17-
Company not being able to replaces its reserves or maintain production, which
will have an adverse effect on its financial position.
RELIANCE ON KEY EMPLOYEES
Compton depends to a large extent on the services of key management personnel,
including the Company's executive officers and other key employees, the loss of
any of whom could have a material adverse effect on operations. The Company
does not maintain key man life insurance with respect to any employees.
Compton's success will be dependent upon its ability to continue to employ and
retain skilled personnel.
ENVIRONMENTAL RISKS
The oil and gas industry is subject to extensive environmental laws and
regulations pursuant to local, provincial, and federal legislation.
Environmental regulation provides for, among other things, restrictions and
prohibitions on the generation, handling, storage, transportation, treatment
and disposal of hazardous substances and waste from spills, releases or
emissions of various substances produced in association with oil and gas
operations. The legislation also requires that wells, facility sites, and other
properties associated with the Company's operations be operated, maintained,
abandoned, and reclaimed to the satisfaction of applicable regulatory
authorities. Under environmental legislation, Compton may be liable for
personal injury, clean-up costs, remedial measures, and other environmental and
property damages, as well as administrative, civil, and criminal penalties.
Furthermore, future changes in environmental laws and regulations, including
adoption of stricter standards or more stringent enforcement, could result in
curtailment of production or materially increased costs, such as fines,
incurred liability and increased capital expenditures and operating costs, any
of which could have a material adverse effect on financial condition. For
example, Canada is a signatory to the United Nations Framework Convention on
Climate Change and has ratified the Kyoto Protocol established thereunder to
set legally binding targets to reduce nationwide emissions of carbon dioxide,
methane, nitrous oxide, and other so-called "greenhouse gases." Compton's
production facilities and other operations and activities emit greenhouse gases
that may subject the Company to legislation regulating emissions of greenhouse
gases. The Government of Canada has proposed a Climate Change Plan for Canada
that suggests further legislation will set greenhouse gases emission reduction
requirements for various industrial activities, including oil and gas
development and production. Future federal legislation, together with
provincial emission reduction requirements, such as those proposed in Alberta's
Bill 32: Climate Change and Emissions Management, may require the reduction of
emissions or emissions intensity of the Company's operations and facilities.
Compliance with such legislation can require significant expenditures and a
failure to comply may result in the issuance of "clean up" orders or the
imposition of fines and penalties, some of which may be material. It is
possible that the costs of complying with environmental regulations in the
future will have a material adverse effect on the Company's financial condition
or results of operations. Compton may incur liabilities that could be material
or require the Company to cease production on properties if environmental
damage occurs.
Compton has not established a separate reclamation fund for the purpose of
funding estimated future environmental and reclamation obligations. The Company
cannot assure that it will be able to satisfy future environmental and
reclamation obligations. Any site reclamation or abandonment costs incurred in
the ordinary course in a specific period will be funded out of cash flow from
operations. Should Compton be unable to fully fund the cost of remedying an
environmental claim, the Company might be required to suspend operations or
enter into interim compliance measures pending completion of the required
remedy.
The Company is not fully insured against certain environmental risks, either
because such insurance is not available or because of high premium costs. In
particular, insurance against risks from environmental pollution occurring over
time (as opposed to sudden and catastrophic damages) is not available on
economically reasonable terms. Accordingly, Compton's properties may be subject
to liability due to hazards that cannot be insured against or that have not
been insured against due to prohibitive premium costs or for other reasons.
-18-
STATEMENT OF RESERVES DATA
Compton's interests in its natural gas and crude oil properties as of December
31, 2005, have been evaluated in a report (the "REPORT") as of December 31,
2005, prepared by the independent international integrated petroleum
engineering and geological firm, Netherland, Sewell & Associates, Inc.
("NETHERLAND SEWELL"). The following summary of the Company's reserves is
calculated and reported in accordance with National Instrument 51-101,
"Standards of Disclosure for Oil and Gas Activities". Assumptions and
qualifications relating to costs, prices for future production, and other
matters are included below. The Report is based on data supplied by the Company
and on Netherland Sewell's opinions of reasonable practice in the industry.
All evaluations of future net revenue are after the deduction of future income
tax expenses (unless otherwise noted in the tables), royalties, development
costs, production costs, and well abandonment costs, but before consideration
of indirect costs such as administrative, overhead, and other miscellaneous
expenses. The estimated future net revenue contained in the following tables
does not necessarily represent the fair market value of Compton's reserves.
There is no assurance that the forecast price and cost assumptions contained in
the Netherland Sewell Report will be attained and variances could be material.
Other assumptions and qualifications relating to costs and other matters are
summarized in the notes to the following tables. The recovery and reserves
estimates on Compton's properties described herein are estimates only. The
actual reserves on Compton's properties may be greater or less than those
calculated and these variances may be material. Compton has no heavy oil
reserves and "crude oil" refers to light and medium crude oil only.
This statement is dated February 24, 2006. The information being provided in
this statement has an effective date of December 31, 2005 and a preparation
date of February 24, 2006.
CONSTANT PRICES AND COSTS
The following table provides a summary of the Company's reserves by product
type, based upon constant price and cost assumptions, before and after
applicable royalties, excluding the Alberta Royalty Tax Credit ("ARTC"), at the
end of the most recent fiscal year.
SUMMARY OF OIL AND GAS RESERVES USING CONSTANT PRICING AS OF DECEMBER 31, 2005
- -----------------------------------------------------------------------------------------------------------
RESERVES CATEGORY (1) CRUDE OIL NATURAL GAS (2) NGLS SULPHUR
GROSS NET GROSS NET GROSS NET GROSS NET
(MBBL) (MBBL) (MMCF) (MMCF) (MBBL) (MBBL) (MLT) (MLT)
- -----------------------------------------------------------------------------------------------------------
PROVED
Developed producing 14,222 13,206 430,136 349,723 7,937 5,635 1,605 1,428
Developed non-producing 3,195 2,951 44,496 35,519 830 566 52 41
Undeveloped 5,029 4,313 84,539 70,260 1,731 1,278 118 98
- -----------------------------------------------------------------------------------------------------------
TOTAL PROVED 22,445 20,470 559,171 455,503 10,498 7,479 1,774 1,566
- -----------------------------------------------------------------------------------------------------------
(1) Numbers may not add due to rounding.
(2) The solution and associated gas represents 6% of the Company's natural
gas reserves and is therefore considered immaterial and is not broken
out.
The table set forth below summarizes the net present value of future net
revenue as of December 31, 2005 based on constant price and cost assumptions.
-19-
SUMMARY OF NET PRESENT VALUES OF FUTURE NET REVENUE AS OF DECEMBER 31, 2005 (CONSTANT PRICES)
- -----------------------------------------------------------------------------------------------
RESERVES CATEGORY NET PRESENT VALUES OF FUTURE NET REVENUE ($000S)(1)
BEFORE INCOME TAXES AFTER INCOME TAXES
DISCOUNTED AT (%/YEAR) DISCOUNTED AT (%/YEAR)
0% 10% 0% 10%
- -----------------------------------------------------------------------------------------------
PROVED
Developed producing $3,376,094 $1,609,730 $2,403,561 $1,183,126
Developed non-producing 471,650 240,652 337,390 175,280
Undeveloped 795,420 301,318 557,529 213,100
- -----------------------------------------------------------------------------------------------
TOTAL PROVED $4,643,164 $2,151,700 $3,298,480 $1,571,506
- -----------------------------------------------------------------------------------------------
(1) A portion of the Company's reserves qualifies to receive the ARTC. The
ARTC was assumed in the Report to continue under the current program or
an extension thereof for a period of 10 years, but is not included in
these numbers.
Undiscounted total future net revenue calculated using constant prices and
costs incorporates the elements presented in the table below.
TOTAL FUTURE NET REVENUE (UNDISCOUNTED) AS OF DECEMBER 31, 2005 (CONSTANT PRICES)
- -----------------------------------------------------------------------------------------------------------------------
RESERVES REVENUE ROYALTIES OPERATING DEVELOPMENT WELL FUTURE NET INCOME TAXES FUTURE NET
CATEGORY ($000S) ($000S) COSTS COSTS ABANDONMENT REVENUE BEFORE ($000S) REVENUE AFTER
($000S) ($000S) COSTS ($000S) INCOME TAXES INCOME TAXES
($000S) ($000S)
- -----------------------------------------------------------------------------------------------------------------------
Proved $8,086,809 $1,514,951 $1,718,793 $187,687 $22,214 $4,643,164 $1,344,684 $3,298,480
- -----------------------------------------------------------------------------------------------------------------------
The following table summarizes the Company's total future net revenue using
constant prices and costs, before income taxes, by production type.
TOTAL FUTURE NET REVENUE BY PRODUCTION TYPE AS OF DECEMBER 31, 2005 (CONSTANT PRICES)
- ----------------------------------------------------------------------------------------------------------
RESERVES CATEGORY PRODUCTION TYPE FUTURE NET REVENUE BEFORE INCOME TAXES
(DISCOUNTED AT 10%/YEAR) ($000S)
- ----------------------------------------------------------------------------------------------------------
Proved Crude Oil (1) $ 611,314
Natural Gas, ngls, and sulphur (2) $1,540,386
- ----------------------------------------------------------------------------------------------------------
(1) Includes solution gas and related ngls.
(2) Excludes solution gas and related ngls.
-20-
FORECAST PRICES AND COSTS
A summary of the Company's reserves by product type based upon forecast price
and cost assumptions, before and after applicable royalties, excluding ARTC, at
the end of the most recent fiscal year is presented below.
SUMMARY OF OIL AND GAS RESERVES USING FORECAST PRICING AS OF DECEMBER 31, 2005
- ---------------------------------------------------------------------------------------------------------------
RESERVES CATEGORY (1) CRUDE OIL NATURAL GAS NGLS SULPHUR
GROSS NET GROSS NET GROSS NET GROSS NET
(MBBL) (MBBL) (MMCF) (MMCF) (MBBL) (MBBL) (MLT) (MLT)
- ---------------------------------------------------------------------------------------------------------------
PROVED
Developed producing 13,537 12,533 423,961 344,320 7,837 5,591 1,603 1,426
Developed non-producing 3,131 2,888 44,332 35,385 828 568 52 41
Undeveloped 5,019 4,304 84,333 70,085 1,731 1,283 118 98
- ---------------------------------------------------------------------------------------------------------------
TOTAL PROVED 21,688 19,725 552,626 449,790 10,396 7,441 1,773 1,565
PROBABLE 6,805 5,762 401,415 337,719 6,232 4,629 772 656
- ---------------------------------------------------------------------------------------------------------------
TOTAL PROVED PLUS PROBABLE 28,493 25,488 954,040 787,509 16,628 12,070 2,545 2,221
- ---------------------------------------------------------------------------------------------------------------
(1) Numbers may not add due to rounding.
The tables set forth below summarize the net present value of future net
revenue as of December 31, 2005 based on forecast prices and cost assumptions.
SUMMARY OF NET PRESENT VALUES OF FUTURE NET REVENUE AS OF DECEMBER 31, 2005 (FORECAST PRICES)
- ----------------------------------------------------------------------------------------------------------------
RESERVES CATEGORY (1) NET PRESENT VALUES OF FUTURE NET REVENUE ($000S)
BEFORE INCOME TAXES DISCOUNTED AT (%/YEAR)
0% 5% 8% 10% 15% 20%
- ----------------------------------------------------------------------------------------------------------------
PROVED
Developed producing $2,809,295 $1,790,246 $1,502,423 $1,367,244 $1,136,835 $989,296
Developed non-producing 407,231 275,162 231,040 209,205 170,528 145,066
Undeveloped 673,954 369,776 278,044 234,937 162,989 119,410
- ----------------------------------------------------------------------------------------------------------------
TOTAL PROVED 3,890,479 2,435,184 2,011,507 1,811,386 1,470,353 1,253,772
PROBABLE 2,308,449 1,155,102 830,029 681,260 439,847 299,340
- ----------------------------------------------------------------------------------------------------------------
TOTAL PROVED PLUS PROBABLE $6,198,928 $3,590,286 $2,841,537 $2,492,645 $1,910,200 $1,553,112
- ----------------------------------------------------------------------------------------------------------------
(1) Numbers may not add due to rounding.
-21-
- -----------------------------------------------------------------------------------------------------------------
RESERVES CATEGORY (1) NET PRESENT VALUES OF FUTURE NET REVENUE ($000S)
AFTER INCOME TAXES DISCOUNTED AT (%/YEAR)
0% 5% 8% 10% 15% 20%
- -----------------------------------------------------------------------------------------------------------------
PROVED
Developed producing $2,023,759 $1,341,801 $1,126,747 $1,024,244 $ 849,212 $ 738,331
Developed non-producing 295,311 201,924 170,478 154,939 127,372 109,188
Undeveloped 478,428 267,812 201,919 170,878 119,110 87,859
- -----------------------------------------------------------------------------------------------------------------
TOTAL PROVED 2,797,499 1,811,537 1,499,144 1,350,061 1,095,694 935,377
PROBABLE 1,537,575 767,481 534,430 427,302 254,907 156,833
- -----------------------------------------------------------------------------------------------------------------
TOTAL PROVED PLUS PROBABLE $4,335,073 $2,579,018 $2,033,574 $1,777,363 $1,350,601 $1,092,210
- -----------------------------------------------------------------------------------------------------------------
(1) Numbers may not add due to rounding.
Undiscounted total future net revenue calculated using forecast prices and
costs incorporates the elements presented in the table below.
TOTAL FUTURE NET REVENUE (UNDISCOUNTED) AS OF DECEMBER 31, 2005
- --------------------------------------------------------------------------------------------------------------------
RESERVES REVENUE ROYALTIES OPERATING DEVELOPMENT WELL FUTURE NET INCOME FUTURE NET
CATEGORY ($000S) ($000S) COSTS COSTS ABANDONMENT REVENUE BEFORE TAXES REVENUE AFTER
($000S) ($000S) COSTS(1) INCOME TAXES ($000S) INCOME TAXES
($000S) ($000S) ($000S)
- --------------------------------------------------------------------------------------------------------------------
Proved $ 7,823,503 $1,436,847 $2,265,900 $192,916 $37,361 $3,890,479 $1,092,980 $2,797,499
Proved plus
probable $12,577,769 $2,253,840 $3,251,277 $811,508 $62,216 $6,198,928 $1,863,855 $4,335,073
- --------------------------------------------------------------------------------------------------------------------
(1) Includes, at minimum, well abandonment costs (rather than total
abandonment and reclamation costs).
The following table summarizes the Company's total future net revenue using
forecast price and cost assumptions, before income taxes, by production type.
TOTAL FUTURE NET REVENUE BY PRODUCTION TYPE AS OF DECEMBER 31, 2005
- --------------------------------------------------------------------------------------------------------------------
RESERVES CATEGORY PRODUCTION TYPE FUTURE NET REVENUE BEFORE INCOME TAXES (DISCOUNTED
AT 10%/YEAR) ($000S)
- --------------------------------------------------------------------------------------------------------------------
Proved Crude Oil (1) $ 542,624
Natural Gas and ngls (2) $1,268,762
Proved plus probable Crude Oil (1) $ 645,369
Natural Gas and ngls (2) $1,847,276
- --------------------------------------------------------------------------------------------------------------------
(1) Includes solution gas and related ngls.
(2) Excludes solution gas and related ngls.
-22-
PRICING ASSUMPTIONS
CONSTANT PRICES USED IN ESTIMATES
Constant price assumptions presume the continuance of current laws,
regulations, and operating costs in effect on the date of the Report. Future
net revenue calculated using constant prices and costs is based upon the price
assumptions set out below. The prices are founded upon the assumptions made by
Netherland Sewell as of December 31, 2005.
SUMMARY OF CONSTANT PRICING ASSUMPTIONS AS OF DECEMBER 31, 2005
- ---------------------------------------------------------------------------------------------------------------------
YEAR CRUDE OIL NATURAL GAS NGLS SULPHUR EXCHANGE
RATE
WTI CUSHING EDMONTON PAR AECO-C SPOT PROPANE BUTANE PENTANES+ PLANT GATE $CDN/$US
OKLAHOMA 40 DEGREES API ($CDN/MMBTU) ($CDN/BBL) ($CDN/BBL) ($CDN/BBL) ($CDN/LT)
$ US/BBL ($CDN/BBL)
- ---------------------------------------------------------------------------------------------------------------------
Dec. 31, 2005 $61.04 $67.85 $9.99 $51.59 $63.52 $71.03 $13.17 0.858
- ---------------------------------------------------------------------------------------------------------------------
FORECAST PRICES USED IN ESTIMATES
Future net revenue calculated using forecast prices and costs is based upon the
price assumptions set out below. Netherland Sewell incorporated price forecast
which were the average of the December 31, 2005 pricing forecasts prepared by
four major Canadian consulting firms in estimating Compton's reserves data
using forecast pricing and costs.
SUMMARY OF FORECAST PRICING AND INFLATION RATE ASSUMPTIONS AS OF DECEMBER 31, 2005 (1)
- -----------------------------------------------------------------------------------------------------------------------
YEAR CRUDE OIL NATURAL GAS NGLS SULPHUR INFLATION EXCHANGE
RATE (2) RATE
WTI CUSHING EDMONTON PAR AECO-C SPOT PROPANE BUTANE PENTANES+ PLANT GATE %/YEAR $CDN/$US
OKLAHOMA 40 DEGREES API ($CDN/MMBTU) ($CDN/BBL)($CDN/BBL) ($CDN/BBL) ($CDN/LT)
$US/BBL ($CDN/BBL)
- ---------------------------------------------------------------------------------------------------------------------------
FORECAST
2006 $58.83 $68.13 $10.93 $43.28 $50.13 $69.99 $33.67 2.0% 0.85
2007 $58.30 $67.55 $ 9.91 $42.48 $49.67 $69.55 $23.77 2.0% 0.85
2008 $55.14 $63.80 $ 8.47 $39.95 $47.08 $65.80 $16.70 2.0% 0.85
2009 $52.32 $60.49 $ 7.72 $37.59 $44.74 $62.39 $15.14 2.0% 0.85
2010 $50.18 $57.96 $ 7.50 $35.93 $42.89 $59.83 $15.68 2.0% 0.85
2011 $49.18 $56.78 $ 7.56 $35.18 $41.94 $58.59 $16.38 2.0% 0.85
2012 $49.96 $57.66 $ 7.68 $35.75 $42.59 $59.49 $16.92 2.0% 0.85
2013 $50.97 $58.80 $ 7.84 $36.40 $43.44 $60.68 $17.47 2.0% 0.85
2014 $51.96 $59.98 $ 8.01 $37.15 $44.30 $61.88 $18.18 2.0% 0.85
2015 $53.01 $61.22 $ 8.21 $37.93 $45.19 $63.17 $18.91 2.0% 0.85
2016 $54.07 $62.42 $ 8.38 $38.70 $46.08 $64.46 $19.47 2.0% 0.85
Thereafter 2.0% 2.0% 2.0% 2.0% 2.0% 2.0% 2.0% 2.0% 0.85
- ---------------------------------------------------------------------------------------------------------------------------
(1) Pricing assumptions are the average of four major Canadian oil and gas
evaluation firms.
(2) Inflation rates for forecasting operating costs and capital investments.
The weighted average realized sales price for Compton for the year ended
December 31, 2005 was $8.42/MCF for natural gas, $62.02/BBL for crude oil,
$47.34/BBL for ngls, and $12.63/LT for sulphur.
-23-
RECONCILIATIONS OF CHANGES IN RESERVES AND FUTURE NET REVENUE
RESERVES RECONCILIATION
The following table provides a summary of the changes in the Company's
reserves which occurred in the most recent fiscal year, based upon forecast
price and cost assumptions, net of applicable royalties.
RECONCILIATION OF NET RESERVES BY RESERVE TYPE USING FORECAST PRICES AND COSTS (NET OF APPLICABLE ROYALTIES) (1)
- -----------------------------------------------------------------------------------------------------------------
CRUDE OIL NGLS
NET NET NET PROVED NET NET NET PROVED
PROVED PROBABLE PLUS PROBABLE PROVED PROBABLE PLUS PROBABLE
(MBBL) (MBBL) (MBBL) (MBBL) (MBBL) (MBBL)
- -----------------------------------------------------------------------------------------------------------------
December 31, 2004 11,018 6,669 17,687 6,256 3,520 9,776
Extensions 1,532 359 1,891 431 1,921 2,352
Improved recovery 3,626 1,671 5,297 190 379 569
Technical revisions 4,057 (3,148) 909 614 (1,246) (632)
Discoveries 409 42 451 260 45 305
Acquisitions 514 169 683 208 10 218
Dispositions - - - (2) - (2)
Production (1,431) - (1,431) (516) - (516)
- -----------------------------------------------------------------------------------------------------------------
DECEMBER 31, 2005 19,725 5,762 25,488 7,441 4,629 12,070
- -----------------------------------------------------------------------------------------------------------------
- -----------------------------------------------------------------------------------------------------------------
NATURAL GAS SULPHUR
NET NET NET PROVED NET NET NET PROVED
PROVED PROBABLE PLUS PROBABLE PROVED PROBABLE PLUS PROBABLE
(MBCF) (MBCF) (MBCF) (MLT) (MLT) (MLT)
- -----------------------------------------------------------------------------------------------------------------
December 31, 2004 359,029 168,808 527,837 1,445 791 2,236
Extensions 33,694 118,596 152,290 9 353 362
Improved recovery 10,555 83,259 93,814 - - -
Technical revisions 61,544 (45,976) 15,568 191 (488) (297)
Discoveries 16,310 12,362 28,672 - - -
Acquisitions 5,564 670 6,234 - - -
Dispositions (56) - (56) - - -
Production (36,850) - (36,850) (80) - (80)
- -----------------------------------------------------------------------------------------------------------------
DECEMBER 31, 2005 449,790 337,719 787,509 1,565 656 2,221
- -----------------------------------------------------------------------------------------------------------------
(1) Prepared by Management. Numbers may not add due to rounding.
-24-
RECONCILIATION OF NET RESERVES BY RESERVE TYPE USING FORECAST PRICES AND COSTS (1)
- -----------------------------------------------------------------------------------------------------------------
TOTAL RESERVES
NET NET NET PROVED
PROVED PROBABLE PLUS PROBABLE
(MBOE) (MBOE) (MBOE)
- -----------------------------------------------------------------------------------------------------------------
December 31, 2004 78,557 39,115 117,672
Extensions 7,588 22,399 29,987
Improved recovery 5,575 15,927 21,502
Technical revisions 15,119 (12,545) 2,575
Discoveries 3,387 2,147 5,535
Acquisitions 1,649 291 1,940
Dispositions (11) - (11)
Production (8,169) - (8,169)
- -----------------------------------------------------------------------------------------------------------------
DECEMBER 31, 2005 103,696 67,334 171,031
- -----------------------------------------------------------------------------------------------------------------
(1) Prepared by Management. Numbers may not add due to rounding.
FUTURE NET REVENUE RECONCILIATION
The following table reconciles changes between the future net revenue estimates
at December 31, 2005 and the corresponding estimates in the prior year, using
constant prices and costs, discounted at 10%.
RECONCILIATION OF CHANGES IN NET PRESENT VALUE DISCOUNTED AT 10% OF FUTURE NET REVENUE OF PROVED RESERVES (1)
- -----------------------------------------------------------------------------------------------------------------
2005
($000S) (2)
- -----------------------------------------------------------------------------------------------------------------
Estimated future net revenue at beginning of year $1,000,772
Sales and transfers of oil and gas produced, net of production costs and royalties 336,711
Net change in sales, prices, production costs and royalties related to future production 614,690
Changes in previously estimated development costs incurred during the period (306,199)
Changes in estimated future development costs (135,499)
Net change from extensions and improved recovery 265,868
Net change from discoveries 88,318
Acquisitions of reserves (7,749)
Dispositions of reserves 87
Net change resulting from revisions in quantity estimates 526,474
Accretion of discount 100,077
Net change in income taxes(3) (331,850)
- -----------------------------------------------------------------------------------------------------------------
Estimated future net revenue at end of year $2,151,700
- -----------------------------------------------------------------------------------------------------------------
(1) Prepared by Management.
(2) Except for "Net Change in Income Taxes," the amounts above are before
tax.
(3) Includes both income taxes incurred during the period and changes in
estimated future income tax expenses.
-25-
ADDITIONAL INFORMATION RELATING TO RESERVES DATA
UNDEVELOPED RESERVES
The following discussion generally describes the basis on which Compton
attributes proved and probable undeveloped reserves and its plans for
developing those undeveloped reserves.
PROVED UNDEVELOPED RESERVES
Proved undeveloped reserves are generally those reserves related to wells that
have been tested and not yet tied-in, wells drilled near the end of the fiscal
year, or wells further away from the Company's gathering systems. In addition,
such reserves may relate to planned infill drilling locations. The majority of
these reserves are planned to be on stream within a two year timeframe.
PROBABLE UNDEVELOPED RESERVES
Probable undeveloped reserves are generally those reserves tested or indicated
by analogy to be productive infill drilling locations and lands contiguous to
production. The majority of these reserves are planned to be on stream within a
two year timeframe.
SIGNIFICANT FACTORS OR UNCERTAINTIES AFFECTING RESERVES DATA
The process of estimating reserves is complex. Although every reasonable effort
is made to ensure that reserve estimates are accurate, reserve estimation is an
inferential science. It requires significant judgments and decisions based on
available geological, geophysical, engineering, and economic data. These
estimates may change substantially as additional data from ongoing development
activities and production performance becomes available and as economic
conditions impacting oil and natural gas prices and costs change. Estimates are
reviewed and revised, either upward or downward, as warranted by the new
information.
The reserve estimates contained herein are based on current production
forecasts, prices, and economic conditions. Compton's reserves are evaluated by
Netherland Sewell.
-26-
FUTURE DEVELOPMENT COSTS
The following table provides a summary of the development costs deducted in the
estimation of future net revenue attributable to each of the following reserves
categories:
DEVELOPMENT COSTS DEDUCTED IN ESTIMATING FUTURE NET REVENUES (1)
- ----------------------------------------------------------------------------------------------------------
YEAR PROVED PROVED PLUS PROBABLE
CONSTANT PRICES AND FORECAST PRICES AND FORECAST PRICES AND
COSTS/YEAR ($000S) COSTS/YEAR ($000S) COSTS/YEAR ($000S)
- ----------------------------------------------------------------------------------------------------------
Undiscounted
2006 $106,989 $107,976 $254,694
2007 45,136 46,541 222,114
2008 24,156 25,511 167,141
2009 2,362 2,805 70,830
2010 4,659 5,229 35,800
Remaining 26,599 42,215 123,2144
- ----------------------------------------------------------------------------------------------------------
Total undiscounted $209,901 $230,277 $873,724
Total discounted at 10% per year $171,801 $178,181 $683,029
- ----------------------------------------------------------------------------------------------------------
(1) Includes abandonment costs. Numbers may not add due to rounding.
Compton estimates that its internally generated cash flow will be sufficient to
fund the future development costs disclosed above. Compton typically has
available three sources of funding to finance its capital expenditure program:
(i) internally generated cash flow from operations; (ii) debt financing when
appropriate; and (iii) new equity issues, if available on favourable terms.
-27-
OTHER OIL AND GAS INFORMATION
OIL AND GAS PROPERTIES AND WELLS
The following table summarizes the location of the Company's interests as at
December 31, 2005, in crude oil and natural gas wells which are producing or
which the Company considers to be capable of production.
- -------------------------------------------------------------------------------------------------------------
AREA PRODUCING CRUDE SHUT-IN CRUDE PRODUCING SHUT-IN NATURAL TOTAL WELLS
OIL WELLS OIL WELLS NATURAL GAS GAS WELLS
WELLS
GROSS NET GROSS NET GROSS NET GROSS NET GROSS NET
- -------------------------------------------------------------------------------------------------------------
ALBERTA
South 108 48 32 12 820 525 216 176 1,176 761
Central 162 78 31 9 360 150 122 45 675 282
Peace River Arch 334 207 26 11 122 - 24 14 506 233
BC 6 - 2 - 42 2 12 1 62 3
- -------------------------------------------------------------------------------------------------------------
TOTAL WELLS 610 333 91 32 1,344 677 374 236 2,419 1,279
- -------------------------------------------------------------------------------------------------------------
The number of shut in oil and gas wells capable of production at December 31,
2005 increased from 2004 because well tie-ins were delayed as the result of
abnormally wet weather during the summer months of 2005.
PROPERTIES WITH NO ATTRIBUTED RESERVES
The following table sets forth the Company's undeveloped land holdings to which
no proved reserves have been attributed as at December 31, 2005.
- -------------------------------------------------------------------------------------------------------------
AREA GROSS ACRES NET ACRES
- -------------------------------------------------------------------------------------------------------------
British Columbia 34,019 5,390
Alberta 907,482 704,148
Saskatchewan 23,157 23,157
Manitoba 6,659 6,259
- -------------------------------------------------------------------------------------------------------------
TOTAL 971,317 738,954
- -------------------------------------------------------------------------------------------------------------
Approximately 211,270 net acres of undeveloped land could expire by December
31, 2006. However, the Company's 2006 exploration and development activities
may defer the expiry of a portion of these lands. Compton has $65 million of
work commitments associated with unproved properties.
FORWARD CONTRACTS
In 2005, Compton's realized average field price was $51.95/BOE, comprised of
$8.42/MCF for natural gas and $56.04/BBL for liquids. In 2004, the average
field prices of natural gas and liquids were $6.46/MCF and $43.21/BBL,
respectively, for an average price of $39.82/BOE.
Compton's natural gas production is sold under a combination of longer term
contracts with aggregators and short term daily or 30 day AECO indexed
contracts. Approximately 10% of the Company's natural gas production in 2005
was committed to aggregators. The average aggregator price realized was
$1.25/MCF less than the non-aggregator prices realized during the year.
-28-
Compton's crude oil sales are priced at Edmonton postings and are typically
sold on 30 day evergreen arrangements. Ngls are bid out on an annual basis to
establish the most competitive pricing. The Company sells crude oil and ngls
primarily to refineries and marketers of crude oil and ngls.
From time to time, Compton may enter into hedging arrangements to mitigate
commodity price risk and take advantage of opportunistic pricing. In accordance
with Compton's policy, hedging programs will not exceed 50% of non-contracted
production.
ADDITIONAL INFORMATION CONCERNING ABANDONMENT AND RECLAMATION COSTS
Compton is required to remove production equipment, batteries, pipelines, and
natural gas plants and to restore land at the end of oil and natural gas
operations. The Company estimates these costs in accordance with existing laws,
contracts and other policies. These obligations are initially measured at fair
value, which is the discounted future value of the liability. This fair value
is also capitalized as part of the cost of the related assets and amortized
over the useful life of the assets.
An independent environmental consulting firm was hired to assist Management in
the estimation of the Company's asset retirement obligations ("ARO"). ARO cost
calculations were derived from a combination of actual third party cost quotes,
EUB cost models and typical industry experience and practices. The deemed ARO
liability for Compton's 1,449 net well sites and facilities is the sum of the
calculated abandonment and reclamation liabilities adjusted for designated
status as active, inactive, abandoned, or problem site. Information regarding
environmental remediation costs and other liability issues for site specific
concerns were derived from a review of historical audit and assessment reports
of sites and facilities. An inflation rate of 2% and a credit adjusted risk
free rate of 10.7% was used in the fair value calculation.
Total asset retirement costs, net of estimated salvage values, is $77 million
or $6 million when discounted at 10%. The undiscounted ARO associated with
pipelines and facilities is $49 million and is not deducted in estimating total
future net revenue, as calculated in the Company's reserve report. The Company
expects to pay $2 million dollars in ARO costs between 2006 and 2009.
TAX HORIZON
Based upon planned capital expenditure programs and current commodity price
assumptions, it is anticipated the Company will not be cash taxable until at
least 2009.
CAPITAL EXPENDITURES
In 2005, Compton incurred $72 million of exploration costs and $424 million of
development costs. Additionally, $29 million was spent on proved property
acquisitions and $12 million was spent on unproved property acquisitions.
-29-
EXPLORATION AND DEVELOPMENT ACTIVITIES
The following table sets forth the number of crude oil and natural gas wells
drilled by the Company, or which the Company participated in drilling, that are
capable of production, as well as the number of dry and abandoned wells, all
expressed in terms of gross and net wells during the years ended December 31,
2005 and 2004. Four wells drilled in 2005, which are standing cased wells
awaiting completion and testing, are not included in the following table.
- -------------------------------------------------------------------------------------------------------------------
YEAR ENDED DECEMBER 31, 2005 YEAR ENDED DECEMBER 31, 2004(1)
DEVELOPMENT EXPLORATORY DEVELOPMENT EXPLORATORY
GROSS NET GROSS NET GROSS NET GROSS NET
- -------------------------------------------------------------------------------------------------------------------
Natural Gas 197 156 60 56 108 89 31 26
Crude Oil 104 96 10 9 29 17 - -
Dry and Abandoned 9 8 8 7 7 3 11 10
- -------------------------------------------------------------------------------------------------------------------
TOTAL 310 260 78 72 144 110 42 36
SUCCESS RATIO 96% 90%
- -------------------------------------------------------------------------------------------------------------------
(1) 2004 revised to include four wells previously classified as standing cased wells.
In 2006, the Company will continue to focus its resources in Alberta, Canada.
Compton's overall objective for 2006 is the recognition of its unbooked
resource potential. The Company has developed an aggressive $575 million
capital expenditure plan for 2006, encompassing up to 480 gross wells.
-30-
PRODUCTION HISTORY
The Company's average daily production volume of natural gas and liquids,
before deduction of royalties, for each of the periods indicated, is set forth
below.
GROSS NATURAL GAS AND LIQUIDS PRODUCTION
- ------------------------------------------------------------------------------------------------------------------
PRODUCT TYPE FISCAL 2005 THREE MONTHS ENDED
YEAR ENDED
MARCH 31, JUNE 30, SEPTEMBER 30, DECEMBER 31, DECEMBER 31,
2005 2005 2005 2005 2005
- ------------------------------------------------------------------------------------------------------------------
Natural gas (MMCF/D) 130 130 130 133 131
Natural gas (MMCF) 11,677 11,809 11,973 12,234 47,693
Liquids (BOE/D) 7,090 7,249 7,351 8,879 7,646
Liquids (MBBLS) 638 660 676 817 2,791
- ------------------------------------------------------------------------------------------------------------------
- ------------------------------------------------------------------------------------------------------------------
PRODUCT TYPE FISCAL 2004 THREE MONTHS ENDED
YEAR ENDED
MARCH 31, JUNE 30, SEPTEMBER 30, DECEMBER 31, DECEMBER 31,
2004 2004 2004 2004 2004
- ------------------------------------------------------------------------------------------------------------------
Natural gas (MMCF/D) 120 122 123 127 123
Natural gas (MMCF) 10,954 11,094 11,347 11,725 45,120
Liquids (BOE/D) 5,655 5,977 6,712 6,963 6,330
Liquids (MBBLS) 515 544 618 640 2,317
- ------------------------------------------------------------------------------------------------------------------
2006 PRODUCTION ESTIMATES
Production volumes in 2006 as estimated in the reserve forecast before
deduction of royalties are set forth below. Production volumes are the same in
both the constant price case and the forecast price case.
- ------------------------------------------------------------------------------------------------------------
RESERVES CATEGORY (1) CRUDE OIL NATURAL GAS NGLS SULPHUR TOTAL
(BBL/D) (MMCF/D) (BBL/D) (LT/D) (BOE/D)
- ------------------------------------------------------------------------------------------------------------
PROVED
Developed producing 4,944 99 1,726 178 23,267
Developed non-producing 1,394 14 230 3 3,934
Undeveloped 994 7 184 - 2,406
- ------------------------------------------------------------------------------------------------------------
TOTAL PROVED 7,332 120 2,140 181 29,606
PROBABLE 384 23 302 13 4,614
- ------------------------------------------------------------------------------------------------------------
TOTAL PROVED PLUS PROBABLE 7,716 143 2,442 194 34,221
- ------------------------------------------------------------------------------------------------------------
(1) Numbers may not add due to rounding. Based on estimates only. Variances may occur due to circumstances
beyond Compton's control.
-31-
The Company's field netbacks for natural gas and liquids for each of the
periods indicated is set forth below.
NATURAL GAS AND LIQUIDS FIELD NETBACKS
- -------------------------------------------------------------------------------------------------------------------
FISCAL 2005 THREE MONTHS ENDED
YEAR ENDED
MARCH 31, JUNE 30, SEPTEMBER 30, DECEMBER 31, DECEMBER 31,
2005 2005 2005 2005 2005
- -------------------------------------------------------------------------------------------------------------------
NATURAL GAS ($/MCF)
Revenue price $6.60 $7.28 $8.46 $11.20 $8.42
Royalties, net (1.66) (1.76) (2.23) (2.54) (2.06)
Operating costs (1.03) (1.01) (1.00) (1.10) (1.04)
Transportation costs (0.13) (0.17) (0.19) (0.18) (1.07)
- -------------------------------------------------------------------------------------------------------------------
Field netback $3.78 $4.34 $5.05 $ 7.38 $5.15
LIQUIDS ($/BBL)
Revenue price $46.23 $54.20 $64.75 $57.99 $56.04
Royalties, net (9.99) (10.53) (13.37) (15.24) (12.36)
Operating costs (6.15) (6.09) (5.98) (6.63) (6.22)
Transportation costs (0.80) (1.01) (1.13) (1.09) (1.01)
- -------------------------------------------------------------------------------------------------------------------
Field netback $29.29 $36.56 $44.28 $35.03 $36.45
- -------------------------------------------------------------------------------------------------------------------
- -------------------------------------------------------------------------------------------------------------------
FISCAL 2004 THREE MONTHS ENDED
YEAR ENDED
MARCH 31, JUNE 30, SEPTEMBER 30, DECEMBER 31, DECEMBER 31,
2004 2004 2004 2004 2004
- -------------------------------------------------------------------------------------------------------------------
NATURAL GAS ($/MCF)
Revenue price $6.25 $6.84 $6.48 $6.29 $6.46
Royalties, net (1.48) (1.57) (1.64) (1.64) (1.58)
Operating costs (0.91) (0.92) (0.93) (1.01) (0.94)
Transportation costs (0.14) (0.14) (0.13) (0.16) (0.15)
- -------------------------------------------------------------------------------------------------------------------
Field netback $3.72 $4.21 $3.78 $3.48 $3.79
LIQUIDS ($/BBL)
Revenue price $40.03 $42.75 $46.60 $42.88 $43.21
Royalties, net (8.88) (9.40) (9.82) (9.82) (9.50)
Operating costs (5.46) (5.51) (5.59) (6.05) (5.66)
Transportation costs (0.84) (0.86) (0.81) (0.98) (0.87)
- -------------------------------------------------------------------------------------------------------------------
Field netback $24.85 $26.98 $30.38 $26.03 $27.18
- -------------------------------------------------------------------------------------------------------------------
-32-
DIVIDENDS
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.
CAPITAL STRUCTURE
Compton is authorized to issue an unlimited number of common shares and an
unlimited number of preferred shares, of which 127,294,201 common shares are
issued and outstanding as fully paid and non-assessable share as at March 23,
2006. No preferred shares are issued and outstanding as at March 23, 2006. The
following is a description of Company's common and preferred shares.
COMMON SHARES
Common shares have attached to them the following rights, privileges,
restrictions, and conditions: (i) except for meetings at which only holders of
another specified class or series of shares of the Company are entitled to vote
separately as a class or series, each holder of a common share is entitled to
receive notice of, to attend and to vote at all meetings of the shareholders of
the Company; (ii) subject to the rights, privileges, restrictions, and
conditions attached to any preferred shares, the holders of common shares are
entitled to receive dividends if, and when declared by the Directors of the
Company; and (iii) subject to the rights, privileges, restrictions, and
conditions attached to any other class of shares of the Company, the holders of
common shares are entitled to share equally in the remaining property of the
Company upon liquidation, dissolution, or winding-up of the Company.
PREFERRED SHARES
The preferred shares may be issued in one or more series, and the Directors are
authorized to fix the number of shares in each series and to determine the
designation, rights, privileges, restrictions, and conditions attached to the
shares of each series. The preferred shares are entitled to a priority over the
common shares with respect to the payment of dividends and the distribution of
assets upon the liquidation, dissolution, or winding-up of Compton.
SHAREHOLDER RIGHTS PLAN
Compton has a shareholder rights plan (the "RIGHTS PLAN") under the terms of a
shareholder rights plan agreement dated as of April 22, 2003 between the
Company and Computershare Trust Company of Canada, as rights agent. The Rights
Plan is designed to encourage the fair treatment of shareholders in connection
with a take-over bid for Compton. Rights issued under the Rights Plan become
exercisable when a person, and any related parties, acquires or announces its
intention to acquire 20% or more of the outstanding Common Shares without
complying with certain provisions set out in the Rights Plan or without
approval of the Board of Directors of Compton. Should such an acquisition or
announcement occur, each rights holder, other than the acquiring person and
related parties, will have the right to purchase Common Shares at a 50%
discount to the market price at that time.
-33-
MARKET FOR SECURITIES
The outstanding common shares of the Company are listed on the Toronto Stock
Exchange ("TSX") under the symbol CMT and on the New York Stock Exchange until
the symbol CMZ. The following table sets out the high and low closing prices
and average trading volume of common shares as reported by the TSX, for the
periods indicated.
- ------------------------------------------------------------------------------------------
PERIOD TSX HIGH CLOSE TSX LOW CLOSE TSX AVERAGE DAILY TRADING VOLUME
- ------------------------------------------------------------------------------------------
2005
January $11.65 $10.51 516,574
February $12.65 $11.46 667,961
March $13.74 $11.30 634,532
April $12.45 $10.26 549,281
May $10.82 $ 9.95 1,065,189
June $11.65 $10.70 842,449
July $13.70 $11.32 809,324
August $14.21 $13.10 835,428
September $15.90 $13.90 700,544
October $16.00 $12.90 562,113
November $15.40 $12.65 691,408
December $18.40 $16.69 951,082
2006
January $18.84 $17.01 743,850
February $18.92 $14.39 773,430
March 1-23 $15.87 $13.95 668,241
- ------------------------------------------------------------------------------------------
CONFLICTS OF INTEREST
The Directors and Officers of Compton are engaged in and will continue to
engage in other activities in the oil and natural gas industry and as a result
of these and other activities, the Directors and Officers of Compton may become
subject to conflicts of interest. The Business Corporations Act (Alberta) (the
"ACT") provides that in the event that a Director has an interest in a contract
or proposed contract or agreement, the Director shall disclose his interest in
such contract or agreement and shall refrain from voting on any matter in
respect of such contract or agreement unless otherwise provided under the Act.
To the extent that conflicts of interest arise, such conflicts will be resolved
in accordance with the provisions of the Act. As at the date hereof, Compton is
not aware of any existing or potential material conflicts of interest between
Compton and a Director or Officer of the Company.
INTERESTS OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS
None of the current executive Officers or Directors of Compton, and no person
or company owning or exercising control over more than 10% of the common shares
of Compton; nor any associate or affiliate of the foregoing has or has had, at
any time, any material interest, directly or indirectly, in any transaction or
proposed transaction that has materially affected or would materially affect
Compton.
-34-
MATERIAL CONTRACTS
Indenture dated as of November 22, 2005, among Compton Petroleum Finance
Corporation, Compton, as parent guarantor, Hornet Energy Ltd., Compton Petroleum
(partnership) and Compton Petroleum Holdings Corporation, as the initial
subsidiary guarantors, and The Bank of Nova Scotia Trust Company of New York, as
trustee, whereby, on November 22, 2005, Compton Petroleum Finance Corporation
issued and sold U.S.$300 million aggregate principal amount of senior term
notes, which are unsecured and bear interest semi-annually, in arrears on
December 1, and June 1 of each year, at a rate of 7 5/8% per year with principal
repayable on December 1, 2013. The senior notes are guaranteed by Compton and
the initial subsidiary guarantors.
INTERESTS OF EXPERTS
As at the date hereof, the partners and associates of Grant Thornton, LLP, the
auditors of Compton, as a group, did not beneficially own any of Compton's
outstanding shares. As at the date hereof, principals of Netherland Sewell
personally disclosed in certificates of qualification that they neither had,
nor expected to receive, any of the Company's outstanding shares.
RATINGS
Standard & Poor's Rating Services ("S&P") and Moody's Corporation ("MOODY'S")
have rated Compton's U.S. 300 million 7 5/8% Senior Notes as B stable and B2
stable respectively, as at December 31, 2005. A security rating is not a
recommendation to buy, sell, or hold securities and may be subject to revisions
or withdrawal at any time by the rating agency.
An S&P credit rating considers likelihood of payment, nature of and provisions
of the obligation, protection afforded by, and relative position of, the
obligation in the event of bankruptcy, reorganization, or other arrangement
under the laws of bankruptcy and other laws affecting creditors' rights. S&P's
credit ratings are on a long-term debt rating scale that ranges from AAA to D,
representing the range from highest to lowest quality of such securities rated.
The ratings from AA to CCC may be modified by the addition of a plus (+) or
minus (-) sign to show relative standing within the major rating categories.
According to the S&P rating system, debt securities rated B are vulnerable to
nonpayment, but the obligor currently has the capacity to meet its financial
commitment on the obligation. Adverse business, financial, or economic
conditions will likely impair the obligor's capacity or willingness to meet its
financial commitment on the obligation.
Moody's credit ratings on long-term structured finance obligations primarily
address the expected credit loss an investor might incur on or before the legal
final maturity of such obligations, incorporating the probability of default
and the severity of the loss. Moody's credit ratings are on a long-term debt
rating scale that ranges from Aaa to C, representing the range from least
credit risk to greatest credit risk of such securities rated. Moody's applies
numerical modifiers 1, 2 and 3 in each generic rating classification from Aa
through Caa in its long term debt rating system. The modifier 1 indicates that
the issue ranks in the higher end of its generic rating category, the modifier
2 indicates a mid-range ranking, and the modifier 3 indicates that the issue
ranks in the lower end of that generic rating category. According to the
Moody's rating system, debt securities rated B2 are considered speculative and
are subject to high credit risk.
-35-
DIRECTORS AND OFFICERS
DIRECTORS
Information is given below with respect to each of the current Directors of the
Company. All Directors of Compton stand for election at each annual meeting of
the Company. The next Annual Meeting of Shareholders is scheduled for May 10,
2006 at 3:30 pm. (Calgary time) in the Historical Ballroom on the 4th Floor of
the Calgary Chamber of Commerce, 517 - Centre Street South, Calgary, Alberta,
Canada.
The Board of Directors has established an Audit, Finance and Risk Committee; an
Engineering, Operations and Reserves Committee; a Human Resources,
Compensation, Environmental, Health and Safety Committee; and a Corporate
Governance Committee. All independent Directors sit on each of the Board
Committees. Mr. Sapieha does not sit on the Board Committees since he is a
non-independent Director due to his position as President & CEO with the
Company.
The name, city of residence, and principal occupation during the last five
years of each of the Directors of the Company are set forth in the following
table.
- ---------------------------------------------------------------------------------------------------------------------
NAME AND MUNICIPALITY OF PRINCIPAL OCCUPATION DIRECTOR SINCE
RESIDENCE
- ---------------------------------------------------------------------------------------------------------------------
Mel F. Belich, Q.C. Group Vice President, Corporate Law, of Enbridge Inc., an energy 1993
Calgary, AB, Canada transportation and distribution company. Mr. Belich has also been
Chairman and President of each of Enbridge International Inc.,
Enbridge Technology Inc., and a director of numerous Enbridge
affiliates, including those in Europe and Latin America.
Mr. Belich is the Chairman of the Board of
Directors of Compton and the Chairman of the
Corporate Governance Committee.
- ---------------------------------------------------------------------------------------------------------------------
Irvine J. Koop, P. Eng. Chairman and Chief Executive Officer, IKO Resources Inc., a petroleum 1996
Calgary, AB, Canada consulting firm and prior thereto, President and CEO, Pipelines and
Midstream of Westcoast Energy Inc.
Mr. Koop is the Chairman of the Human Resources,
Compensation, Environmental, Health and Safety
Committee.
- ---------------------------------------------------------------------------------------------------------------------
John W. Preston Account Executive, Sun Microsystems of Canada Inc., a computer 1993
Calgary, AB, Canada company.
- ---------------------------------------------------------------------------------------------------------------------
Ernie G. Sapieha, C.A. President & Chief Executive Officer of the Company. 1993
Calgary, AB, Canada
- ---------------------------------------------------------------------------------------------------------------------
Jeffrey T. Smith, P. Geol. Independent Businessman and prior thereto, Chief Operating Officer of 1999
Calgary, AB, Canada Northstar Energy Corporation.
Mr. Smith is Chairman of the Engineering,
Reserves and Operations Committee.
- ---------------------------------------------------------------------------------------------------------------------
-36-
- ---------------------------------------------------------------------------------------------------------------------
NAME AND MUNICIPALITY OF PRINCIPAL OCCUPATION DIRECTOR SINCE
RESIDENCE
- ---------------------------------------------------------------------------------------------------------------------
John A. Thomson, C.A. Independent Businessman. Mr. Thomson served as Vice President 2003
Calgary, AB, Canada Corporate Development from 2000 and as a director from 1999 to 2001,
of Avid Oil & Gas Ltd., an oil and gas company and prior thereto, he
was Senior Vice President and Chief Financial Officer of Renaissance
Energy Ltd., an oil and gas Company.
Mr. Thomson is the Chairman of the Audit,
Finance and Risk Committee.
- ---------------------------------------------------------------------------------------------------------------------
Further information about the Directors and the committees of the Board of
Directors is set forth under the heading "Election of Directors" in the
Company's Management Proxy Circular dated March 15, 2006 relating to the Annual
Meeting of Shareholders to be held on May 10, 2006, which sections are
incorporated by reference into this Annual Information Form.
OFFICERS
The name, city of residence, and principal occupation during the last five
years of each of the Officers of the Company are set forth in the following
table.
- ----------------------------------------------------------------------------------------------------------------
NAME AND MUNICIPALITY OF RESIDENCE PRINCIPAL OCCUPATION
- ----------------------------------------------------------------------------------------------------------------
Ernie G. Sapieha, C.A. President & Chief Executive Officer of the Company.
Calgary, Alberta
Norman G. Knecht, C.A. Vice President Finance & Chief Financial Officer of the Company.
Calgary, Alberta
Tim G. Millar, LL.B. Vice President, General Counsel & Corporate Secretary of the Company; prior
Calgary, Alberta to 2003, Senior Partner of Fraser Milner Casgrain LLP, Barristers and
Solicitors.
Murray J. Stodalka, P. Eng. Vice President Operations & Engineering of the Company.
Calgary, Alberta
Marc R. Junghans, P. Geol. Vice President Exploration; prior to 2002, Manager of Exploration of the
Calgary, Alberta Company.
- ----------------------------------------------------------------------------------------------------------------
As at March 23, 2006, the Directors and officers of Compton as a group
beneficially owned or controlled, directly or indirectly, 12,920,564 common
shares of Compton, representing approximately 10.2% of the issued and
outstanding common shares of the Company. None of the Directors or Officers
held a sufficient number of common shares to materially affect the control of
Compton.
-37-
AUDIT, FINANCE AND RISK COMMITTEE INFORMATION
The Charter of the Audit, Finance and Risk Committee is set forth in Schedule
C.
COMPOSITION OF AUDIT, FINANCE AND RISK COMMITTEE
Chairman: John A. Thomson
Members: Mel F. Belich, Irvine J. Koop, John W. Preston, and Jeffrey T. Smith
Based upon applicable Canadian and United States securities laws and the New
York Stock Exchange corporate governance rules, Compton has adopted "Standards
of Independence," which may be viewed in full on the Company's website. The
Board affirmatively determines on an annual basis the independence of its
members. Messrs. Belich, Koop, Preston, Smith, and Thomson have been determined
to be independent Directors. Mr. Sapieha is not an independent Director because
of his position as President & CEO of the Company.
Mr. Thomson is considered to be a "financial expert", as defined in National
Instrument 52-110, due to his experience in the oil and natural gas industry as
a Chartered Accountant, as Chief Financial Officer of a major public oil and
natural gas company, and as a board member and Officer for other public
reporting oil and natural gas companies. All other Committee members are
"financially literate", as defined in National Instrument 52-110, due to their
experience in various management positions.
EXTERNAL AUDITOR FEES
The aggregate amounts paid or accrued by the Company with respect to fees
payable to Grant Thornton LLP for audit and audit-related (including separate
audits of subsidiary entities, financings, and regulatory reporting
requirements), tax and other services in the fiscal years ended December 31,
2005 and 2004 were as follows:
- --------------------------------------------------------------------------------
TYPE OF SERVICE FISCAL 2005 FISCAL 2004 (1)
- --------------------------------------------------------------------------------
Audit $481,230 $350,455
Audit related 221,997 131,315
Tax 10,000 9,000
Other non-audit 41,930 49,598
- --------------------------------------------------------------------------------
Total $755,157 $540,368
- --------------------------------------------------------------------------------
(1) 2004 amounts have been updated to account for differences between accrued
costs and actual billings.
The audit related fees incurred in fiscal 2005 related to the Company's equity
offering in February 2005 and the issuance of the Company's U.S. dollar Senior
Notes in November 2005. Tax fees incurred in fiscal 2005 related to the review
of tax forms and the fees for other non-audit services in fiscal 2005 were
incurred to translate the Company's quarterly and annual reports into French.
The audit related fees incurred in fiscal 2004 related to discussions regarding
the accounting treatment for the Mazeppa Processing Partnership. Tax fees
incurred in fiscal 2004 related to the review of tax forms and the fees for
other non-audit services in fiscal 2004 were incurred to translate the
Company's quarterly and annual reports into French and discussions regarding
requirements of the Sarbanes Oxley Act of 2002.
The Audit, Finance and Risk Committee of the Company considered these fees and
determined that they were reasonable and do not impact the independence of the
Company's auditors. Further, such Committee determined that in order to ensure
the continued independence of the auditors, only limited non-audit related
services would be provided to the Company by Grant Thornton LLP and in such
case, only with the prior approval of the Audit, Finance and Risk Committee.
The Committee has pre-approved Management to retain Grant Thornton LLP to
provide miscellaneous, minor, non-audit services in circumstances where it is
not feasible or practical to convene a meeting of the Audit, Finance and Risk
Committee, subject to an aggregate limit of $20,000 per quarter.
-38-
TRANSFER AGENT AND REGISTRAR
The transfer agent and registrar for the Company's shares is Computershare
Trust Company of Canada at its office in Calgary, Alberta.
ADDITIONAL INFORMATION
Additional information including Directors' and Officers' remuneration,
principal holders of the Company's common shares, options to acquire common
shares, and interests of insiders in material transactions (if applicable) is
contained in the Management Proxy Circular issued by Management dated March 15,
2006, relating to the Annual and Special Meeting of Shareholders to be held on
May 10, 2006. Additional financial information is also provided in the
consolidated financial statements and MD&A of the Company for the year ended
December 31, 2005 included in the Company's 2005 Annual Report. Copies of these
documents have been filed with the Canadian Securities Administrators' System
for Electronic Document Analysis and Retrieval ("SEDAR") at www.sedar.com.
Additional copies of this Annual Information Form are available to the public
and may be obtained by contacting:
Compton Petroleum Corporation
Suite 3300, 425 - 1st Street S.W.
Fifth Avenue Place, East Tower
Calgary, Alberta, Canada
T2P 3L8
Attention: Mr. T.G. Millar
Vice President, General Counsel & Corporate Secretary
Telephone: (403) 237-9400
Fax: (403) 237-9410
-39-
SCHEDULE A
REPORT ON RESERVES DATA BY INDEPENDENT
QUALIFIED RESERVES EVALUATOR
To the Board of Directors of Compton Petroleum Corporation (the "COMPANY"):
1. We have evaluated the Company's reserves data as at December 31, 2005. The
reserves data consist of the following:
(a) (i) proved and proved plus probable oil and gas
reserves estimated as at December 31, 2005 using
forecast prices and costs; and
(ii) the related estimated future net revenue; and
(b) (i) proved and proved plus probable oil and gas
reserves estimated as at December 31, 2005 using
constant prices and costs; and
(ii) the related estimated future net revenue.
2. The reserves data are the responsibility of the Company's Management. Our
responsibility is to express an opinion on the reserves data based on our
evaluation.
We carried out our evaluation in accordance with standards set out in the
Canadian Oil and Gas Evaluation Handbook (the "COGE Handbook") prepared
jointly by the Society of Petroleum Evaluation Engineers (Calgary Chapter)
and the Canadian Institute of Mining, Metallurgy & Petroleum (Petroleum
Society).
3. Those standards require that we plan and perform an evaluation to obtain
reasonable assurance as to whether the reserves data are free of material
misstatement. An evaluation also includes assessing whether the reserves
data are in accordance with principles and definitions presented in the
COGE Handbook.
4. The following table sets forth the estimated future net revenue (before
deduction of income taxes) attributed to proved plus probable reserves,
estimated using forecast prices and costs and calculated using a discount
rate of 10 percent, included in the reserves data of the Company evaluated
by us for the year ended December 31, 2005 and identifies the respective
portions thereof that we have audited, evaluated and reviewed and reported
on to the Company's Board of Directors:
Description and Net Present Value of Future Net Revenue (before
Independent Qualified Preparation Date Location Canadian federal income taxes, 10% discount rate)(C$)
Reserves Evaluator or of Evaluated of -----------------------------------------------------
Auditor Report Reserves Audited Evaluated Reviewed Total
------------------------------------------------------------------------------------------------------------
Netherland, Sewell & February 24, 2006 Canada nil 2,492,645.40 nil 2,492,645.40
Associates, Inc.
5. In our opinion, the reserves data respectively evaluated by us have, in
all material respects, been determined and are in accordance with the COGE
Handbook. We express no opinion on the reserves data that we reviewed but
did not audit or evaluate.
6. We have no responsibility to update our reports referred to in paragraph 4
for events and circumstances occurring after their respective preparation
dates.
-40-
7. Because the reserves data are based on judgements regarding future events,
actual results will vary and the variations may be material.
Executed as to our report referred to above:
NETHERLAND, SEWELL, & ASSOCIATES, INC.
Dallas, Texas, USA
March 14, 2006
By: /s/ Frederic D. Sewell
------------------------------------
Frederic D. Sewell
Chairman and Chief Executive Officer
Please be advised that the digital document you are viewing is provided by
Netherland, Sewell & Associates, Inc. (NSAI) as a convenience to our clients.
The digital document is intended to be substantively the same as the original
signed document maintained by NSAI. The digital document is subject to the
parameters, limitations, and conditions stated in the original document. In the
event of any differences between the digital document and the original
document, the original document shall control and supersede the digital
document.
-41-
SCHEDULE B
REPORT OF MANAGEMENT AND DIRECTORS
ON RESERVES ON OIL AND GAS DISCLOSURE
Management of Compton Petroleum Corporation (the "COMPANY") are responsible for
the preparation and disclosure of information with respect to the Company's oil
and gas activities in accordance with securities regulatory requirements. This
information includes reserves data, which consist of the following:
(a) (i) proved and proved plus probable oil and gas
reserves estimated as at December 31, 2005 using
forecast prices and costs; and
(ii) the related estimated future net revenue; and
(b) (i) proved oil and gas reserves estimated as at December 31,
2005 using constant prices and costs; and
(ii) the related estimated future net revenue.
An independent qualified reserves evaluator has evaluated the Company's
reserves data. The report of the independent qualified reserves evaluator will
be filed with securities regulatory authorities concurrently with this report.
The Engineering, Reserves and Operations Committee of the Board of Directors of
the Company has:
(c) reviewed the Company's procedures for providing information to
the independent qualified reserves evaluator;
(d) met with the independent qualified reserves evaluator to
determine whether any restrictions affected the ability of the
independent qualified reserves evaluator to report without
reservation; and
(e) reviewed the reserves data with Management and the independent
qualified reserves evaluator.
The Engineering, Reserves and Operations Committee of the Board of Directors
has reviewed the Company's procedures for assembling and reporting other
information associated with oil and gas activities and has reviewed that
information with Management. The Board of Directors has, on the recommendation
of the Engineering, Reserves and Operations Committee approved:
(f) the content and filing with securities regulatory authorities of
the reserves data and other oil and gas information;
(g) the filing of the report of the independent qualified reserves
evaluator on the reserves data; and
(h) the content and filing of this report.
-42-
Because the reserves data are based on judgments regarding future events,
actual results will vary and the variations may be material.
(signed) "Ernie Sapieha" (signed) "Murray Stodalka"
Ernie Sapieha Murray Stodalka
President & CEO Vice President Operations & Engineering
(signed) "Jeffrey Smith" (signed) "Mel Belich"
Jeffrey Smith Mel Belich
Chairman of the Engineering, Reserves Chairman of the Board
and Operations Committee
March 23, 2006
-43-
SCHEDULE C
CHARTER OF THE AUDIT, FINANCE AND RISK COMMITTEE
MANDATE OF THE COMMITTEE
The Audit, Finance and Risk Committee (the "COMMITTEE") of the Board of
Directors (the "BOARD") of Compton Petroleum Corporation (the "COMPANY") shall,
as permitted by the Business Corporations Act (Alberta) (the "ABCA") and the
Articles and By-Laws of the Company, have the responsibility to oversee that
management has applied due diligence in creating and maintaining an effective
risk management and control framework. This framework should provide reasonable
assurance that the financial, operational, and regulatory objectives of the
Company are achieved and that the statutory responsibilities of the Board are
discharged. The Committee fulfils its role on behalf of the Board, by
overseeing:
1. the integrity of the Company's financial statements, financial information
and accounting, financial reporting (including MD&A, as hereinafter
defined), and auditing processes;
2. the external auditor's qualifications, independence, and performance;
3. the Company's compliance with legal and regulatory requirements; and
4. risk management, management information systems, governmental legislation,
and external business of the Company.
While the Committee has the responsibilities and powers set forth in this
Charter, it is not the duty of the Committee to plan or conduct audits, to
determine that the Company's financial statements are complete, accurate, and
in accordance with generally accepted accounting principles, or to certify the
Company's financial statements. Management is responsible for preparing the
Company's financial statements and the Company's external auditor is
responsible for auditing the annual financial statements and for reviewing the
interim financial statements. The Committee shall however; assist the Board in
overseeing that management and the external auditor fulfill their
responsibilities in the Company's financial reporting process.
The Committee has the authority to obtain independent outside accounting and
other advisors as deemed appropriate to perform its duties and
responsibilities. The Company shall provide appropriate funding to compensate
the external auditor and any advisors that the Committee chooses to engage. The
Committee is authorized to communicate directly with the external auditor to
discuss and review specific issues as necessary.
The Committee will primarily fulfil its responsibilities by carrying out the
activities enumerated in the following sections of this Charter. The Committee
will report regularly to the Board regarding the execution of its duties and
responsibilities.
In fulfilling its mandate, the Committee has the responsibility to, without
limitation:
(A) INTERNAL AND DISCLOSURE CONTROLS
1. review the effectiveness and integrity of the Company's system of
disclosure controls and system of internal controls regarding finance,
accounting, compliance, and ethics that management and the Board have
established;
2. where the Committee considers it necessary and appropriate, set up and
review an internal audit process and review any appointment or dismissal
of senior internal audit personnel appointed in connection therewith;
-44-
3. review the evaluation of internal controls by the external auditor with
management and the Company's subsequent follow-up to any identified
weaknesses;
4. review, in conjunction with the Human Resources, Compensation,
Environmental, Health and Safety Committee of the Board, the appointment
of the Chief Financial Officer;
5. determine the appropriate resolution of conflicts of interest in respect
of audit, finance, and risk matters properly directed to the Committee;
6. review with management and the external auditor:
(a) in conjunction with the report of the external auditor, the
Company's audited annual financial statements, including related
footnotes and management's discussion and analysis of financial
conditions and results of operations ("MD&A") and quarterly
financial statements,
(b) the significant accounting judgments and reporting principles,
practices, and procedures applied by the Company in preparing its
financial statements including any newly adopted accounting
policies,
(c) significant changes to the audit plan, if any, and any serious
disputes or difficulties with management encountered during the
audit,
(d) the co-operation received by the external auditor during the
audit, including access to all requested records, data and
information,
(e) any correspondence with regulatory or governmental authorities
which raises material issues regarding the Company's financial
statements or accounting policies, and
(f) any other matters not described above that are required to be
communicated by the external auditors to the Committee pursuant
to applicable law and regulation;
7. obtain an explanation from management of all significant variances between
comparative reporting periods. The Committee shall review all financial
statements prior to their presentation to the Board for approval;
8. review and recommend for approval by the Board, all documents to be
publicly disclosed, prior to their release, which contain audited or
unaudited financial information. Such documents include any prospectuses,
interim unaudited financial statements, year end audited financial
statements, the annual report, the annual management proxy circular, the
annual information form, all press releases, and disclosures made under
MD&A;
9. review with management the procedures that exist for the review of
financial information extracted or derived from financial statements which
is publicly disclosed by the Company other than in the documents listed in
section 8 above and periodically, at least annually, assess the adequacy
of those procedures, as required by Multilateral Instrument 52-110,
section 2.3;
10. review with management and the external auditor all off-balance sheet
financing mechanisms being used by the Company, their risks, and the clear
disclosure of those risks and all other material financial risks to the
Company's business;
11. discuss with the Company's General Counsel, at least annually, legal and
regulatory matters that may have a material impact on the financial
statements;
12. review with the Chief Financial Officer and the Chief Executive Officer of
the Company their respective disclosures made to the Committee during the
certification process as required by Multilateral Instrument 52-109, and
in addition:
-45-
(a) any significant deficiencies or material weaknesses in the design
or operation of internal controls,
(b) any fraud involving management or other employees who have a
significant role in the Company's internal controls,
(c) any other obligations arising from certification, and
(d) any significant changes in the internal controls;
13. review with management and the external auditor and as required by the
Corporate Governance Committee, the Company's Code of Business Conduct and
Ethics;
14. establish and maintain procedures for:
(a) the receipt, retention, and treatment of complaints received by
the Company regarding the Company's accounting, internal
accounting controls, or auditing matters, and
(b) the confidential and anonymous submission by Company employees of
concerns regarding questionable accounting or auditing matters,
and review all matters relating thereto; and
15. review with management the details of all transactions between the Company
and parties related to the Company.
(B) OVERSIGHT OF THE EXTERNAL AUDITOR
1. recommend to the Board and to the Shareholders the nomination of the
external auditor, who shall be a "Registered Public Accounting Firm"
within the meaning of applicable securities legislation, for the purpose
of preparing or issuing an auditor's report or performing other audit,
review, or attestation services for the Company;
2. review the qualifications and independence of the external auditor during
the year;
3. at least annually, obtain and review a report by the independent auditor
describing the firm's internal quality control procedures; any material
issues raised by the most recent internal quality-control review, or peer
review, of the firm, or by any inquiry or investigation by governmental or
professional authorities, within the preceding five years, respecting one
or more independent audits carried out by the firm, and any steps taken to
deal with any such issues; and (to assess the auditor's independence) all
relationships between the independent auditor and the listed company;
4. maintain a clear understanding with the external auditor that it is to
have an open and transparent relationship with the Committee and that it
is to report directly to the Committee;
5. provide a scheduled opportunity to meet with the external auditor for
full, frank and timely discussions of all material issues, without
management present;
6. discuss with the external auditor the scope and timing of the audit work
with particular reference to high risk areas or areas of Board concern;
7. inquire as to whether the audit partner receives compensation based on the
audit partner procuring engagements to provide services other than audit,
review, or attest services to the Company;
8. review all reportable events, including disagreements, unresolved issues,
and consultations, as defined in National Instruments 51-102, on a routine
basis, whether or not there is to be a change of external auditor;
-46-
9. review all issues and documentation related to a change of external
auditor, including information to be included in the Change of Auditor
Notice and documentation called for under National Instruments 51-102 and
the planned steps for an orderly transition period;
10. appropriately supervise and evaluate the performance of the external
auditor and lead audit partner, and report conclusions to the Board;
11. review and approve the Company's hiring policies regarding partners,
employees, former partners, and former employees of the current and
previous external auditors of the Company;
12. oversee the rotation of audit partners as required by applicable
regulation and, in order to ensure continuing auditor independence,
consider annually whether it is appropriate to adopt a policy of rotating
the Company's external auditing firm on a regular basis;
13. pre-approve the nature of, and fees for, all audit, review, attestation,
and significant non-audit services provided by the external auditor, prior
to engagement, and disclose such pre-approvals in accordance with
applicable securities law;
14. consider the effect of significant non-audit engagements on the
independence of the external auditor; and
15. provide to the external auditor any information and explanations, and
access to records, documents, books, accounts, and vouchers of the Company
that are, in the opinion of the external auditor, necessary to make the
examinations and reports required under legislation or regulation.
(C) OVERSIGHT OF FINANCIAL REPORTING AND ACCOUNTING POLICIES
1. review with management and the external auditor significant financial
reporting issues arising during the fiscal period and the methods of
resolution;
2. prior to the issuance of the external auditor's report on the Company's
financial statements, discuss the following with the external auditor:
(a) all critical accounting policies and practices applied in the
financial statements,
(b) all alternative accounting and disclosure treatments of financial
information within generally accepted accounting principles that
have been discussed with management, ramifications of the use of
such alternate treatments and disclosures, and the treatment
preferred by the external auditor, and
(c) other material written communications between the external
auditor and management, such as the post audit or management
letter and schedule of unadjusted differences;
3. inquire of the external auditor as to the quality of the Company's
accounting estimates, discussing significant judgments made in connection
with the preparation of the financial statements;
4. review with management any proposed changes in major accounting policies,
the impact and clear disclosure of significant risks and uncertainties,
and key estimates and judgments of management that may be material to
financial reporting;
5. prepare such reports and letters or other disclosure documents as are
required to be prepared by the Committee under applicable securities
legislation; and
6. review any notice received by the Committee with respect to an error or
misstatement of which a director or officer becomes aware;
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(D) ADDITIONAL DUTIES AND RESPONSIBILITIES
1. review the appointments of any other key financial executives who are
involved in the financial reporting process;
2. review derivative and hedging policies of the Company and make
recommendations to the Board in respect of gas contracts, hedging
agreements, and other similar financial transactions;
3. review risk assessment and risk management policies. Such review should
include the Company's major financial and accounting risk exposures, the
steps management has undertaken to control them, and the clear disclosure
of such material risks as part of the Company's continuous disclosure
requirements; and
4. review the amount and terms of any insurance to be obtained or maintained
by the Company, including insurance with respect to potential liabilities
incurred by the directors or officers in the discharge of their duties and
responsibilities;
(E) GENERAL
The Committee also has the responsibility to:
1. with the approval of the Board or the Corporate Governance Committee of
the Board retain and compensate independent advisors (including legal
counsel), as deemed necessary by the Committee;
2. meet separately with senior management, employees or independent advisors
in respect of audit, finance and risk matters, as deemed necessary by the
Committee;
3. review and assess annually the adequacy of this Charter and recommend any
approved changes to the Corporate Governance Committee and the Board;
4. annually evaluate the performance of the Committee and Committee Chair;
5. prepare the Committee's report or reports for publication in applicable
disclosure documents, including the Audit Committee Report for publication
in the annual Management Information Circular;
6. report regularly to the Board through the Chair of the Committee or
through such other person appointed by the Committee the conclusions
reached and issues considered by the Committee;
7. fulfill its responsibilities and duties by:
(a) inspecting any and all of the books, records, and financial
affairs of the Company, its subsidiaries and affiliates, and
(b) meeting with any executive or employee of the Company with or
without management to review such accounts, records and other
matters as any member of the Committee considers necessary and
appropriate;
8. review when deemed necessary by the Committee any of the financial affairs
of the Company, its subsidiaries or affiliates and make recommendations to
the Board, to the external auditor, or to management, as appropriate;
9. consider and make recommendations to the Board with respect to any matters
properly referred to the Committee by the Board;
10. perform any other activities consistent with this Charter as the Committee
deems necessary or appropriate in order to carry out its mandate.
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COMPOSITION OF THE COMMITTEE
1. The Committee shall be comprised of at least three directors.
2. Each member of the Committee shall be "independent" as affirmatively
determined by the Board, and as defined in the Company's Standards of
Independence attached hereto.
3. At least half of the members of the Committee must be resident Canadians,
as that term is defined in the ABCA.
4. The Board shall appoint the members of the Committee at the first meeting
of the Board following each annual meeting ("ANNUAL MEETING") of the
shareholders of the Company.
5. The Board shall appoint one member of the Committee to be the Chair of the
Committee.
6. A director appointed by the Board to the Committee shall be a member of
the Committee until the next Annual Meeting or until his or her earlier
resignation or removal by the Board. A member shall cease to be a member
of the Committee upon ceasing to be a director of the Company.
7. The Board may remove or replace any member of the Committee at any time.
8. The Company's Corporate Secretary, or in his or her absence, one of the
members chosen by the Committee shall be the Secretary of the Committee.
9. Members of the Committee may not serve on the audit committee of more than
two additional public companies without the prior approval of the Board.
10. (a) Each member of the Committee shall be financially literate. An
individual is financially literate if he or she has the ability
to read and understand a set of financial statements that present
a breadth and level of complexity of accounting issues that are
generally comparable to the breadth and complexity of the issues
that can reasonably be expected to be raised by the Company's
financial statements;
(b) A Committee member who is not financially literate may be
appointed to the Committee provided that the member becomes
financially literate within a reasonable period of time following
his or her appointment; and
(c) At least one member of the Committee shall have accounting or
related financial management expertise and, where possible, at
least one member of the Committee shall qualify as an "audit
committee financial expert" within the meaning of applicable
securities legislation.
MEETINGS OF THE COMMITTEE
1. The Committee shall convene at such times and places designated by the
Chair of the Committee, at least on a quarterly basis, and whenever a
meeting is requested by the Board, a member of the Committee, the external
auditor, or a senior officer of the Company. The Committee shall meet in
separate sessions with management and the external auditor at each
regularly scheduled meeting.
2. Notice of each meeting of the Committee shall be given to each member and
to the external auditor, who shall be entitled to attend each meeting of
the Committee.
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3. Notice of a meeting of the Committee shall:
(a) be in writing (which may be communicated by electronic facsimile
or other communication facilities),
(b) state the nature of the business to be transacted at the meeting
in reasonable detail,
(c) to the extent practicable, be accompanied by copies of
documentation to be considered at the meeting, and
(d) be given at least 24 hours preceding the time stipulated for the
meeting.
4. A quorum for the transaction of business at a meeting of the Committee
shall consist of a majority of the members of the Committee.
5. A member of the Committee may participate in a meeting of the Committee by
means of such telephonic, electronic, or other communication facilities as
permit all persons participating in the meeting to communicate adequately
with each other. A member participating in such a meeting by any such
means is deemed to be present at that meeting.
6. In the absence of the Chair of the Committee, the members of the Committee
shall choose one of the members present to be Chair of the meeting and, in
the absence of the Secretary of the Committee; the members shall choose
one of the persons present to be the Secretary of the meeting.
7. Management of the Company may attend meetings of the Committee as deemed
appropriate by the Committee, and shall attend meetings of the Committee
when requested to do so by the Committee.
8. Minutes shall be kept of all meetings of the Committee and shall be signed
by the Chairman and Secretary of the meeting. The minutes shall be
maintained with the Company's records, shall include copies of all
resolutions passed at each meeting, and shall be available for review by
members of the Committee, the Board, Management and external auditor.
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COMPTON PETROLEUM CORPORATION
STANDARDS OF INDEPENDENCE
Compton Petroleum Corporation ("Compton" or "the Company") has adopted the
following standards for determining whether a director is independent within
the meaning of applicable Canadian and United States securities laws and the
New York Stock Exchange corporate governance rules.
These Standards will be periodically reviewed and may be modified by Compton's
Board of Directors ("the Board"). Except where required by applicable law or
the rules of the New York Stock Exchange, the criteria set forth in these
standards are not intended to constitute rigid rules that govern the Board's
determination of whether a director is independent from the Company or an
interpretation of any applicable law, rule or regulation.
To be considered independent for purposes of these standards, the Board must
affirmatively determine on an annual basis that the director being reviewed has
no direct or indirect material relationship with the Company. A "material
relationship" is a relationship which could, in the view of the Company's
Board, be reasonably expected to interfere with the exercise of a member's
independent judgment. In each case, the Board shall consider all relevant facts
and circumstances.
Additionally, a director will not be deemed to be independent if:
(a) the director is, or has been within the last three years, an employee or
executive officer of the Company, or an immediate family member(1) of the
director is, or has been within the last three years, an executive officer
of the Company;
(b) the director is a current partner or employee of a firm that is the
Company's internal or external auditor, or was within the last three
years, a partner(2) or employee of that firm and personally worked on the
Company's audit within that time;
(c) an immediate family member of the director is a current partner of a firm
that is the Company's internal or external auditor, or is a current
employee of that firm and participates in its audit, assurance or tax
compliance (but not tax planning) practice, or was, within the last three
years a partner or employee of that firm and personally worked on the
Company's audit within that time;
(d) the director, or an immediate family member of the director, is or has
been within the last three years, an executive officer of an entity on
which any of the Company's current executive officers serves or served at
that same time on the entity's compensation committee;
(e) the director or an immediate family member of the director who is employed
as an executive officer of the Company has received, during any twelve
month period within the last three years, more than $75,000 in direct
compensation from the Company, other than 1) director and committee fees,
2) pension or other forms of deferred compensation for prior service
provided that such compensation is not contingent in any way on continued
service and 3) compensation for previously acting as an interim chief
executive officer of the Company or previously acting as a chairman of the
board on a part-time basis;
(f) the director is a current employee, or an immediate family member is a
current executive officer, of a company that has made payments to, or
received payments from, the Company for property or services in an amount
which, in any of the last three fiscal years, exceeds the greater of $1
million, or 2% of such other company's consolidated gross revenues;
(g) the director accepts, directly or indirectly, any consulting, advisory or
other compensatory fee from the Company or any subsidiary entity of the
Company, other than as remuneration for acting in the director's capacity
as a member of the board or any board committee, or as a part-time chair
or vice-chair of the board or any board committee; or is an affiliated
entity of the Company or any of its subsidiary entities.
Other compensatory fees includes acceptance of a fee by an immediate
family member or an entity in which the director is a partner, member, an
officer such as a managing director occupying a comparable position or
executive officer, or occupies a similar position (except limited
partners, non-managing members and those
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occupying similar positions who, in each case, have no active role in
providing services to the entity) and which provides accounting,
consulting, legal, investment banking or financial advisory services to
the Company or any subsidiary entity of the Company. Compensatory fees do
not include the receipt of fixed amounts of compensation under a
retirement plan (including deferred compensation) for prior service with
the Company if the compensation is not contingent in any way on continued
service.
(h) the director is an affiliated(3) person of the Company.
(1) An immediate family member is defined as a director's spouse, parents,
children, siblings, mothers and fathers-in-law, sons and daughters-in-law,
brothers and sisters-in-law, and anyone (other than domestic employees)
who shares the director's home.
(2) A partner does not include a fixed income partner whose interest in the
firm that is the internal or external auditor is limited to the receipt of
fixed amounts of compensation (including deferred compensation) for prior
service with that firm if the compensation is not contingent in any way on
continued service.
(3) Affiliated person of another person means:
(a) any person directly or indirectly owning, controlling, or holding
with power to vote, 5% or more of the outstanding voting securities
of such other person;
(b) any person 5% or more of whose outstanding voting securities are
directly or indirectly owned, controlled, or held with power to vote,
by such other person;
(c) any person directly or indirectly controlling, controlled by, or
under common control with, such other person;
(d) any officer, director, partner, copartner, or employee of such other
person;
(e) if such other person is an investment company, any investment adviser
thereof or any member of an advisory board thereof; and
(f) if such other person is an unincorporated investment company not
having a board of directors, the depositor thereof.