Exhibit
1.1








ANNUAL
INFORMATION FORM
  
  
  (Except
as otherwise noted the
 information
herein is given
 as
at December 31, 2008)
  
  Dated:  April
29, 2009
    
   TABLE
OF CONTENTS
  
  ABBREVIATIONS
                      1CONVERSIONS
                      1CERTAIN
      DEFINITIONS
                      2GLOSSARY OF TECHNICAL
      TERMS
                      3CURRENCY OF
      INFORMATION
                      6FORWARD LOOKING
      STATEMENTS
                      6THE
    CORPORATION
                      7GENERAL DEVELOPMENT OF THE
      BUSINESS
                      8SIGNIFICANT
      ACQUISITIONS
                      12DESCRIPTION OF
      THE BUSINESS AND PRINCIPAL PROPERTIES
                      13STATEMENT OF
      RESERVES DATA AND OTHER OIL AND GAS INFORMATION
                      18INDUSTRY
      CONDITIONS
                      28RISK
      FACTORS
                      36DIVIDENDS
                      42DESCRIPTION OF
      CAPITAL STRUCTURE
                      43MARKET FOR
      SECURITIES
                      44DIRECTORS AND
      OFFICERS
                      45LEGAL
      PROCEEDINGS
                      47INTERESTS OF
      MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS
                      47TRANSFER AGENT
      AND REGISTRAR
                      48MATERIAL
      CONTRACTS
                      48INTERESTS OF
      EXPERTS
                      48AUDIT
      COMMITTEE
                      49ADDITIONAL
      INFORMATION
                      50
   1
 
   ABBREVIATIONS
  
 Oil and Natural Gas
      Liquids
              Natural
      GasBbl
              Barrel
              Mcf
              thousand
      cubic feetBbls
              Barrels
              MMcf
              million
      cubic feetMbbls
              thousand
      barrels
              Mcf/d
              thousand
      cubic feet per dayMMbbls
              million
      barrels
              MMcf/d
              million
      cubic feet per dayMstb
              1,000
      stock tank barrels
              MMbtu
              million
      British Thermal Unitsbbls/d
              barrels
      per day
              Bcf
              billion
      cubic feetbopd
              barrels
      of oil per day
              Tcf
              trillion
      cubic feetNGLs
              natural
      gas liquids
              GJ
              gigajouleSTB
              standard
      tank barrels
 
 
 Other
 
 AECO
              EnCana
      Corp.'s natural gas storage facility located at Suffield,
      Alberta.API
              American
      Petroleum Institute°API
              an
      indication of the specific gravity of crude oil measured on the API
      gravity scale. Liquid petroleum with a specified gravity of 28° API or
      higher is generally referred to as light crude oil.ARTC
              Alberta
      royalty tax creditBOE
      or boe
              barrel
      of oil equivalent of natural gas and crude oil on the basis of 1 BOE for 6
      Mcf of natural gas (this conversion factor is an industry accepted norm
      and is not based on either energy content or current
    prices)m3
              cubic
      metersMBOE
              1,000
      barrels of oil equivalentMstboe
              1,000
      stock tank barrels of oil equivalent$M
              thousands
      of dollars$MM
              millions
      of dollarsWTI
              West
      Texas Intermediate, the reference price paid in U.S. dollars at Cushing,
      Oklahoma for crude oil of standard gradepsi
              pounds
      per square inch
 
 The
following table sets forth certain conversions between Standard Imperial Units
and the International System of Units
(or metric units).
 
  CONVERSIONS
  
 To
      Convert From
                To
                Multiply
      ByMcf
                cubic
      meters
                0.28174cubic
      meters
                cubic
      feet
                35.494bbls
                cubic
      meters
                0.159cubic
      meters
                bbls
      oil
                6.293feet
                Meters
                0.305meters
                Feet
                3.281miles
                kilometres
                1.609kilometres
                Miles
                0.621acres
                Hectares
                0.405hectares
                Acres
                2.471gigajoules
                Mmbtu
                0.950
 
  In this
document, a boe conversion ratio of 6 Mcf = 1 bbl has been used. Boe's may be
misleading, particularly if used in isolation. A boe conversion ratio of 6 Mcf
to 1 bbl is based on an energy equivalency conversion method primarily
applicable at the burner tip and does not represent a value equivalency at the
wellhead.
   2
  CERTAIN
DEFINITIONS
  
  In this
Annual Information Form, the following words and phrases have the following
meanings, unless the context otherwise requires:
  "ASC" means the Alberta
Securities Commission.
  "Canada Southern" means Canada
Southern Petroleum Ltd.
  "Canadian Superior" or the
"Corporation" means Canadian Superior Energy Inc.
  "CBM" means coal bed
methane.
  "CNSOPB" means the Canada-Nova
Scotia Offshore Petroleum Board.
  "Common Shares" means the
common shares in the capital of the Corporation.
  "EPSA" means the Exploration and Production Sharing
Agreemententered into
between the Corporation andJoint Oil.
  "GLJ" means GLJ Petroleum
Consultants Ltd.
  "GLJ Report" means the report
dated March 27, 2009 prepared by GLJ evaluating the Corporation's proved and
proved plus probable reserves effective December 31, 2008.
  "Joint Oil" means the Tunisian/Libyan company'Joint Exploration, Production, and
Petroleum Services Company'
that isowned equally by
the Tunisian government via Entreprise Tunisienned'Activites Petrolieresand the Libyan government via Libya Oil
Holdings.
  "MEEI" means the Trinidad and
Tobago Ministry of Energy and Energy Industries.
  "NI 51-101" means National
Instrument 51-101 – Standards
of Disclosure for Oil and Gas Activities.
  "OSC" means the Ontario
Securities Commission.
  "Petrotrin" means Trinidad and
Tobago's National Oil Company.
  "Preferred Shares" means the
first preferred shares in the capital of the Corporation.
  "PSC" means the Production
Sharing Contract dated July 20, 2005 entered into between the Corporation and
the President and the Minister of Energy and Energy Industries of the Republic
of Trinidad and Tobago.
  "Rights Plan" means the
Corporation's shareholder rights plan.
  "Rights Plan Agreement" means
the shareholder's rights plan agreement in respective of the Rights Plan dated
effective as of January 22, 2001 between the Corporation and Valiant Trust
Company of Canada, as amended from time to time.
   3
    GLOSSARY
OF TECHNICAL TERMS
  As used
in this Annual Information Form, the following technical terms and acronyms have
the respective meanings specified below.
  1.
                "constant prices and
      costs" means prices and costs used in an estimate that
      are:
  (a)
                the
      Corporation'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;
  (b)
                if,
      and only to the extent that, there are fixed or presently determinable
      future prices or costs to which the Corporation 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 Corporation's prices will be the posted price for
oil and the spot price for gas, after historical adjustments for transportation,
gravity and other factors.
  2.
                "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.
  3.
                "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 and production
      storage tanks, natural gas cycling and processing plants, and central
      utility and waste disposal systems;
and
  (d)
                provide
      improved recovery systems.
  4.
                "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.
  5.
                "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
 4
 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 defence, and the maintenance of land and lease
    records;
  (c)
                dry
      hole contributions and bottom hole
  contributions;
  (d)
                costs
      of drilling and equipping exploratory wells;
and
  (e)
                costs
      of drilling exploratory type stratigraphic test
  wells.
  6.
                "exploratory well" means
      a well that is not a development well, a service well or a stratigraphic
      test well.
  7.
                "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 localized
      geological features, in contrast to broader terms such as "basin",
      "trend", "province", "play" or "area of
  interest".
  8.
                "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 Corporation 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).
  9.
                "future net revenue"
      means the estimated net amount to be received with respect to the
      development and production of reserves (including synthetic oil, coal bed
      methane and other non-conventional reserves) estimated using constant
      prices and costs or forecast prices and
costs.
  10.
                "gross"
      means:
  (a)
                in
      relation to the Corporation's interest in production or reserves, its
      "company gross reserves", which are its working interest (operating or
      non-operating) share before deduction of royalties and without including
      any royalty interests of the
Corporation;
  (b)
                in
      relation to wells, the total number of wells in which the Corporation has
      an interest; and
  (c)
                in
      relation to properties, the total area of properties in which the
      Corporation has an interest.
 5
 11.
                "natural 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.
  12.
                "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.
  13.
                "net"
    means:
  (a)
                in
      relation to the Corporation'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;
  (b)
                in
      relation to the Corporation's interest in wells, the number of wells
      obtained by aggregating the Corporation's working interest in each of its
      gross wells; and
  (c)
                in
      relation to the Corporation's interest in a property, the total area in
      which the Corporation has an interest multiplied by the working interest
      owned by the Corporation.
  14.
                "non-associated gas"
      means an accumulation of natural gas in a reservoir where there is no
      crude oil.
  15.
                "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
      and facilities and other costs of operating and maintaining those wells
      and related equipment and
facilities.
  16.
                "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.
  17.
                "property"
      includes;
  (a)
                fee
      ownership or a lease, concession, agreement, permit, license 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 the
      Corporation 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).
  but
does not include supply agreements, or contracts that represent a right to
purchase, rather than extract, oil or gas.
  18.
                "proved property" means a
      property or part of a property to which reserves have been specifically
      attributed.




6




19.
              "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.
  20.
              "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.
  21.
              "unproved property" means
      a property or part of a property to which no reserves have been
      specifically attributed.
  22.
              "well abandonment costs"
      means costs of abandoning a well (net of salvage value) and of
      disconnecting the well from the surface gathering system. They do not
      include costs of abandoning the gathering system or reclaiming the
      wellsite.
   CURRENCY
OF INFORMATION
  The
information in this Annual Information Form is stated as at December 31, 2008,
unless otherwise indicated. For an explanation of the capitalized terms and
expressions and certain defined terms, please refer to the "Glossary of
Technical Terms" in this Annual Information Form. Except as otherwise indicated,
all dollar amounts in this Annual Information Form are expressed in Canadian
dollars and references to $ are to Canadian dollars.
   FORWARD
LOOKING STATEMENTS
  Canadian
Superior Energy Inc. cautions that all statements in this document, other than
statements of historical fact, including statements regarding estimates of
reserves, estimates of future production as well as other statements about
anticipated future events or results are forward looking statements. Forward
looking statements often, but not always, are identified by the use of words
such as "seek", "anticipate", "believe", "continue", "plan", "estimate",
"expect", "target", and "intend" and statements that an event or result "may",
"will", "should", "could" or "might" occur or be achieved and other similar
expressions. Forward-looking statements in this document include, but are not
limited to, statements about:
  ·
              the
      future commercial success of the Corporation's oil and natural gas
      exploration, development and production
  activities;
  ·
              the
      stability of world-wide oil and natural gas
  prices;
  ·
              the
      Corporation's ability to make necessary capital expenditures for the
      acquisition, exploration, development and production of oil and natural
      gas reserves in the future;
  ·
              competition
      with and among other oil and gas companies for the acquisition,
      exploration, production and development of oil and natural gas
      properties;
  ·
              the
      Corporation's oil and natural gas
reserves;
  ·
              the
      Corporation's ability to obtain the required licenses and permits from
      governmental authorities for its exploration, development and production
      activities; and
  ·
              the
      Corporation's ability to successfully defend against pending or future
      litigation.
   7
  Statements
contained in this document relate to forward-looking information, including
estimates, projections, interpretations, prognoses and other information that
may relate to current, past or future production, development(s), testing, well
test results, resource potential and/or reserves, project start-ups and future
capital spending.  Forward looking information contained in this
document is as of the date of this document. The Company assumes no obligation
to update and/or revise this forward-looking information “except as required by
law”. Current, past and/or future actual results and/or reported results,
estimates, projections, resource potential and/or reserves, interpretations,
prognoses, and/or estimated results, well results, test results, reserves,
production, resource and/or resource potential, development(s), project
start-ups, and capital spending, plans and/or estimated results could differ
materially due to changes in project schedules, operating performance, demand
for oil and gas, commercial negotiations or other technical and economic factors
or revisions.  This document may contain the reference to the terms
discovery, reserves and/or resources or resource potential discovered and/or
undiscovered which are those quantities estimated to be contained in
accumulations.  There is no certainty that any portion of these
accumulations or estimated accumulations in this document may not change
materially; and that, if discovered, in any discovery, the accumulations or
estimated accumulations may not be economically viable or technically feasible
to produce.
  Statements
contained in this document relating to estimates, results, events and
expectations are forward-looking statements within the meaning of Section 27A of
the Securities Act of 1933, as amended and Section 21E of the Securities
Exchange Act of 1934, as amended.  These forward-looking statements
involve known and unknown risks, uncertainties, scheduling, re-scheduling and
other factors which may cause the actual results, performance, estimates,
projections, resource potential and/or reserves, interpretations, prognoses,
schedules or achievements of the Company, or industry results, to be materially
different from any future results, performance or achievements expressed or
implied by such statements.  Such factors include, among others, those
described in the Company’s’ annual reports on Form 40-F or Form 20-F on file
with the U.S. Securities and Exchange Commission.
  These
forward-looking statements involve known and unknown risks, uncertainties,
scheduling, re-scheduling and other factors which may cause the Corporation's
actual results, performance, estimates, projections, interpretations, prognoses
schedules or achievements, or the actual results, performance, schedules or
achievements of the industry in which the Corporation operates, to be materially
different from any future results, performance or achievements expressed or
implied by such statements.
  Readers
are cautioned not to place undue reliance on this forward-looking information,
which is given as of the date it is expressed in this Annual Information Form or
otherwise, and the Corporation undertakes no obligation to update publicly or
revise any forward-looking information, whether as a result of new information,
future events or otherwise except as required by securities law.
   THE
CORPORATION
  Canadian
Superior was incorporated as 297272 Alberta Ltd. by Articles of Incorporation
under the Business
Corporations Act (Alberta) on March 21, 1983. Canadian Superior amended
its articles: (i) on April 27, 1993, to change its name to "KapaIua Gold Mines
Ltd." and to remove the private company restrictions in its articles; (ii) on
November 16, 1993, to change its name to "Prize-Energy Inc." and to consolidate
its issued and outstanding Common Shares on a 1-for-5 basis; and (iii) on
January 19, 1999, to permit the appointment of additional directors between
annual meetings and to restate its articles in a consolidated form. On August
24, 2000, a further amendment changed the name of the Corporation to "Canadian
Superior Energy Inc." and consolidated its issued and outstanding Common Shares
on a 1-for-2 basis.
  Canadian
Superior is a reporting issuer, or the equivalent, in the provinces of British
Columbia, Alberta, Saskatchewan, Manitoba, Ontario, Quebec, Nova Scotia, Prince
Edward Island, and Newfoundland. The Common Shares are listed and posted for
trading on the Toronto Stock Exchange and the NYSE Euronext (successor to the
American Stock Exchange) under the symbol "SNG".
   8
  The Corporation's head office is
located at 3200, 500 – 4th Avenue S.W., Calgary, Alberta, T2P 2V6 and its
registered office is located at 3300, 421 - 7th Avenue S.W., Calgary, Alberta,
T2P 4K9. In addition, the Corporation has an east coast office located at 1409,
1959 Upper Water Street, Halifax, Nova Scotia, B3J 3N2, an office in New
Jersey at15 Exchange Place, Suite 1120, Jersey City, NJ,a field office at P.O. Box 2259
Drumheller, Alberta, T0J 0Y0, a field office in the West Indies located at 5
Herbert Street, St. Clair, Port of Spain, Trinidad & Tobago, West Indies,
and a field office in Tunisia at6 Rue Virgile,Gammarth, Tunis,
Tunisia.
  The
Corporation is the owner of 100% of all of the issued and outstanding shares of
Seeker Petroleum Ltd., a corporation incorporated under the laws of Canada and
continued in Alberta on August 25, 2008.
  The
Corporation has a total of 48 full-time staff, including 3 staff members in its
Halifax, Nova Scotia office, 4 staff members in its New Jersey office, 9 staff
members in its Drumheller, Alberta field office and 8 staff members in its
Trinidad and Tobago field office.
   GENERAL
DEVELOPMENT OF THE BUSINESS
  Canadian
Superior is engaged in the exploration for, and acquisition, development and
production of petroleum and natural gas, and LNG projects, with operations in
Western Canada, offshore Nova Scotia, offshore Trinidad and Tobago, the United
States and North Africa.
  The
most significant general conditions that have affected the Corporation's
business in the past three completed financial years have been the volatility of
commodities markets, and more recently the global economic recession and the
attendant drop in investment capital and in equity market capitalization. Like
all companies engaged in the business of exploring for and producing crude oil
and natural gas, the significant drop in the market price for oil and natural
gas in the past twelve months has affected revenue from the sale of these
commodities and also the economics of proposed exploration projects. The share
values of virtually all crude oil and natural gas exploration and production
companies have fallen as a result of these factors.
  The
most significant specific events in the development of the business of Canadian
Superior during the past three completed fiscal years are described
below
  On
April 29, 2009 Mr. Leif Snethun was named as the Corporation's COO, acting in
the capacity of principal executive officer.
 
 On
April 24, 2009 Messrs. Gregory Noval, the Executive Chairman of the Board, and
Michael Coolen, the President and CEO, departed as officers and employees of the
Corporation.  Mr. Jake Harp was named as Interim Chairman of the
Board.  In addition, Messrs Noval and Coolen no longer serve on the
Corporation's various Board committees.
 
 On
April 22, 2009 the Corporation attended a hearing with the NYSE Alternext US LLC
(the “Exchange” or “NYSE Alternext US”) regarding the March 6th decision by the
Exchange's staff to file a delisting application with the
S.E.C.  Following the hearing the Exchange staff advised the
Corporation that it had decided to withdraw its proposed delisting application,
and that the Corporation's Common Shares would instead continue to be
halted/suspended from trading for an interim period pending the resolution of
the Corporation's protection under the Companies' Creditors Arrangement Act
(Canada) (“CCAA”).
 
 On
April 3, 2009 the committee of independent directors retained Jennings Capital
Inc. as its financial advisor pursuant to an engagement letter dated April 2,
2009.  Under this agreement Jennings Capital agrees to assist the
committee of independent directors in exploring and reviewing alternatives
potentially available to the Corporation including, but not limited to, a sale
of the Corporation, a recapitalization, an equity injection or a sale of certain
assets with a view to the Corporation's successful emergence from the CCAA
proceedings.
  9
  On
April 3, 2009, the Corporation announced that the membership of a committee of
independent directors, that was established to assist the board of directors in
fulfilling its oversight responsibilities, was amended by the addition to the
committee of Messrs. Alexander Squires and Charles Dallas.  The
committee of independent directors is now comprised of Messrs. T. Jake Harp
(Chair), Kaare Idland, Richard Watkins, Alex Squires and Charles
Dallas.
 
 On
March 26, 2009, the Corporation announced that its application of March 25,
2009, to the Court of Queen's Bench of Alberta for an Order under the CCAA, to
extend its CCAA protection was successful; allowing the Corporation to continue
to prepare a plan of arrangement for its creditors, and continuing to stay all
claims and actions against the Corporation and its assets.  The March
25th Order extended CCAA protection until May 4, 2009, at which time the matter
is scheduled to be reviewed by the court.  The Order permits the
Corporation to remain in possession and control of its property, carry on its
business, retain employees and other service providers.  While the
Order is in effect, the Corporation will work with a court-appointed Monitor and
it will continue to implement a plan of arrangement for its creditors, which
includes, among other things, the initiative to sell an undivided 25% or larger
interest in its "Intrepid" Block 5(c) in Trinidad and Tobago.
 
 On
March 11, 2009, the Corporation advised that the NYSE Alternext US LLC (the
“Exchange” or “NYSE Alternext US”) has halted trading in its common shares on
March 5, 2009. The NYSE Alternext US has advised the Corporation, in a letter
dated March 6, 2009, that the Exchange intends to file a delisting application
with the S.E.C. due to determinations by the Exchange staff that the Corporation
had continuing listing deficiencies.
 
 On
March 6, 2009, the Corporation announced that its application to the Court of
Queen's Bench of Alberta for an Order under the CCAA was successful, allowing
the Corporation to prepare a plan of arrangement for its creditors, and staying
all claims and actions against the Company and its assets. The Order was made
under section 11 of the CCAA and would be in effect until March 25, 2009, at
which time the matter would be reviewed by the court. While the Order is in
effect the Corporation would work with a court-appointed Monitor and continue to
implement a plan of arrangement for its creditors, which included the initiative
to sell an undivided 25% or larger interest in its “Intrepid” Block 5(c) in
Trinidad and Tobago. The Corporation advised that a successful sale of the
Trinidad asset could allow the Corporation to re-structure in an organized
manner and reemerge from CCAA in due course.
 
 On
March 5, 2009, the Corporation announced that it filed an application with the
Court of Queen's Bench of Alberta for an order allowing the Corporation to
prepare a plan of arrangement for its creditors, and staying all claims and
actions against the Corporation and its assets.
 
 On
March 3, 2009, the Corporation announced the successful flow testing of the
"Endeavour" well, the third well drilled by the Corporation offshore Trinidad,
and the discovery of quantities of natural gas.
  On
February 23, 2009, the Corporation advised that it had reached an accommodation
with Canadian Western Bank (“Bank”) whereby the demand for repayment of all
amounts outstanding under the Corporation's credit facility with the Bank was
extended to February 27, 2009 (further extended on March 2, 2009 to March 12,
2009). The credit facility had been permanently reduced the previous week from
$45 million to $37.5 million with a payment of approximately $9 million made to
the Bank by the Corporation from the sale of certain Western Canadian
properties.
 
 On
February 20, 2009, the Corporation announced that it had entered into an
agreement with Scotia Waterous (USA) Inc. (“Scotia Waterous”) under which Scotia
Waterous would immediately commence to act as advisor to the Corporation for the
sale of a 25% or larger interest in its “Intrepid” Block 5(c) in Trinidad and
Tobago. Among the services provided under the advisory agreement, Scotia
Waterous would identify and prioritize purchasers for the assets, develop
marketing and sales documentation, organize and facilitate access to all
technical data, and support and assist sales negotiations and
documentation.
  10
  On
February 17, 2009, the Corporation advised that it had received a demand letter
from the Canadian Western Bank (“Bank”) for repayment of all amounts outstanding
under Canadian Superior’s $45 million credit facility with the Bank by February
23, 2009. The Corporation advised that it was in discussions with the Bank to
extend the time for repayment in order to provide for the orderly and timely
repayment of the full credit facility.
 
 On
February 12, 2009, the Corporation announced the appointment, upon the
application of BG International Limited ("BG"), a wholly owned subsidiary of the
BG Group plc, of an interim Receiver of its participating interest in “Intrepid”
Block 5(c). Pursuant to the Court Order the Receiver, in conjunction with BG,
will operate the property and conduct the flow testing of the “Endeavour” well
which Canadian Superior believes will validate its operations to
date.  The Court Order allowed the Receiver to charge the
Corporation's interest in Block 5(c) with an amount up to U.S. $47 million to
pay for its share of the costs under the joint operating agreement with BG. The
Corporation announced that it would continue with the monetization of its
interest in Block 5(c) as previously announced and the proceeds from any sale
would be applied to its share of the costs charged against Block 5(c) and to
discharge the Receiver.
 
 On
February 10, 2009, the Corporation announced its proposal to monetize a 25% or
larger interest in its “Intrepid” Block 5(c) offshore Trinidad and Tobago and
its related discoveries, subject to acceptable terms and conditions, and subject
to all required approvals.
  On
February 9, 2009 BG initiated arbitration proceedings under the provisions of
the Block 5(c) joint operating agreement, alleging various breaches of the joint
operating agreement by the Corporation.  As of the date of this Annual
Information Form BG and the Corporation have each nominated an arbitrator to
serve as two of the three members of an arbitration panel.
  On
February 8, 2009 BG served on the Corporation a default notice under the
provisions of the Block 5(c) joint operating agreement, alleging various
breaches of the joint operating agreement by the Corporation.  The
terms of the Block 5(c) joint operating agreement are complex and, in a
worst-case scenario, could have resulted in the forfeiture of the Corporation's
interest in Block 5(c) to BG.  The CCAA Order obtained by the
Corporation on March 6, 2009, and continued on March 25th, had the effect of
staying these provisions of the Block 5(c) joint operating
agreement.
  On
December 31, 2008, the Corporation entered into a settlement agreement with
Sinopec Star Petroleum Co. Ltd. for disputed drilling and related costs incurred
in 2008 for the net amounts of USD $3.3 million inclusive of VAT and UK £288,513
exclusive of VAT.
  On
December 8, 2008, the Corporation closed an underwritten private placement
consisting of 10,322,581 Common Shares issued on a "flow-through" basis at a
price of $1.55 per share for gross proceeds of $16.0 million.
  On
December 4, 2008, the Corporation announced the resignation of Mr. Craig
McKenzie as CEO and as a Director, and the appointment of Mr. M.E. Coolen as
CEO, in addition to his ongoing positions as President, COO and a
Director.
  On September 23,
2008 the Corporation entered into a $14,000,000 bridge financing agreement with
Challenger Energy Corp. ("Challenger"), to allow Challenger to close a
$30,000,000 prospectus financing.  The principal amount of this loan
is currently in default.
 On
September 3, 2008, the Corporation announced the execution of an Exploration and
Production Sharing Agreement with Joint Exploration, Production, and Petroleum
Services Company, which is owned jointly by the Tunisian and Libyan governments,
for the exploration and development of the offshore "7th of November Block" that
straddles the territorial waters of both Tunisia and Libya.
  On
August 26, 2008, the Corporation announced that it entered into an agreement for
a non-brokered private placement of $35 million USD, by the issuance of
8,750,000 $4.00 USD units. Each unit is comprised of one Common Share and
one-half of one Common Share purchase warrant, with each whole warrant
exercisable for a period of one year at a price of $4.75 USD. This private
placement successfully closed on September 4, 2008.
   11
  On
August 13, 2008, the Corporation announced the successful flow testing of the
"Bounty" well, the second well drilled by the Corporation offshore Trinidad, and
the discovery of significant quantities of natural gas.
  On May
20, 2008, the Corporation announced that it will participate in the a 50/50
joint venture for the proposed development of a USD $550 million LNG
regasification project, entitled "Liberty Natural Gas", to be located in US
federal waters offshore New Jersey.
  On
February 5, 2008, the Corporation announced that Robb Thompson and Leif Snethun
had joined as Chief Financial Officer and as Vice President, Western Canada,
respectively.
  On
January 16, 2008, the Corporation announced an agreement to acquire all of the
issued and outstanding shares of Seeker Petroleum Ltd., subject to certain
conditions, for total consideration of approximately $51.8 million, including
the assumption of approximately $8.5 million of net debt. This transaction was
successfully completed on March 26, 2009, with the issuance of approximately
7,651,866 Common Shares at $3.72 and the payment of $14.2 million cash to the
shareholders of Seeker Petroleum Ltd.
  On
January 14, 2008, the Corporation announced the successful flow testing of the
first zone of the "Victory" well, the first well drilled by the Corporation
offshore Trinidad, and the discovery of significant quantities of natural gas.
On January 28, 2008, the Corporation announced the successful flow testing of
the second zone of the "Victory" well, and the discovery of significant
quantities of natural gas in the second zone as well.
  On
November 19, 2007, the Corporation closed a private placement consisting of
6,472,500 Common Shares issued on a "flow-through" basis at a price of $3.50 per
share for gross proceeds of $22.7 million.
  On
October 1, 2007, the Corporation announced that Craig McKenzie, recent President
of BG Trinidad & Tobago, BG Group PLC, was appointed as Chief Executive
Officer of the Corporation, and on November 15, 2007, Mr. McKenzie, was named to
the board of directors of the Corporation.
  On
August 16, 2007, the Corporation announced that BG International Limited ("BG")
entered into a farm-in agreement and joint operating agreement to participate in
the exploration, drilling and development of the "Intrepid" Block
5(c).  Under the terms of the agreements BG acquired a 30% working
interest in Block 5(c).  In addition BG paid approximately US$39
million and on a go-forward basis paying approximately 40% of the exploration
costs associated with the drilling of the three commitment wells in Block
5(c).
  On June
26, 2007, Greg Noval was appointed to the new position of Executive Chairman of
the Corporation.
  On
January, 23, 2007, the Corporation announced that its offshore Nova Scotia
exploration acreage holdings have increased to 2.59 million net acres with the
addition of the EL2412 and EL2413 deepwater blocks previously held by a U.S.
company.
  On
December 29, 2006 the Corporation completed a private placement of 2,500,000
Common Shares at  a price of $2.37 per share for gross proceeds of
$5.9 million.
  On
December 13, 2006 the Corporation issued 6,000,000 Common Shares on a
"flow-through" basis at a price of $2.57 per Common Share for aggregate proceeds
of $15.4 million.
  In June
2006, Canadian Superior offered to acquire all of the issued and outstanding
shares of Canada Southern Petroleum Ltd. from existing shareholders. Canadian
Superior offered 2.75 Common Shares plus $2.50 cash for each issued and
outstanding share of Canada Southern. On July 17, 2006, Canadian Superior
revised its offer to two Common Shares, $2.50 cash and a 25% net profit interest
in Canada
   12
  Southern's
approximately 927 bcf of natural gas attributed to its interest in the Canadian
Arctic Islands. The minimum condition attached to the revised offer was not met.
171,495 Canada Southern shares were tendered to the original offer, for which
Canadian Superior issued 471,612 Common Shares and paid $0.4 million to take-up.
The costs incurred in relation to the offer, including the fair value of the
Common Shares issued upon take-up, exceeded the fair value of the Canada
Southern shares acquired. The difference has been recorded as a Loss on
Investment in the Corporation's financial statements. Canadian Superior
subsequently received US$2.2 million as a result of the sale of the Canada
Southern shares acquired.
  On
April 10, 2006, Michael (Mike) E. Coolen was appointed President and Chief
Operating Officer of the Corporation.
  On
February 9, 2006, the Corporation completed a private placement of 1,000,000
units at a price of $2.40 per unit for gross proceeds of $2.4 million. Each unit
consisted of one Common Share and one-half of one Common Share purchase warrant.
Each purchase warrant entitled the holder thereof to acquire an additional
Common Share at any time until December 31, 2006 at a price of $2.40 per Common
Share.
  On
February 1, 2006, the Corporation completed a private placement of US $15
million of preferred share purchase units.
  On
January 4, 2006, the Corporation announced that at year end 2005 it had closed,
by way of private placement, total "flow-through" share financings of 2,976,400
Common Shares at a price of $3.00 per share for gross proceeds of $8.9
million.
   SIGNIFICANT
ACQUISITIONS
  On
March 26, 2008 the Corporation completed a plan of arrangement (the
"Arrangement") with Seeker Petroleum Ltd. ("Seeker"), the result of which was
the acquisition by the Corporation of all the issued and outstanding shares of
Seeker for $51.2 million, by the issuance of approximately 7,651,866 Common
Shares at $3.72 a piece and the payment of $14.2 million cash. Seeker is a
wholly-owned subsidiary of the Corporation. A NI 51-102F4 Business Acquisition
Report regarding this acquisition was filed with Canadian securities regulators
via SEDAR on June 4, 2008.
  Seeker was a privately held corporation
incorporated under the laws ofCanada,engaged in petroleum and natural gas
exploration, development and production inWestern Canada.Pursuant to the Arrangement the
shareholders of Seeker received, for each outstanding common share of Seeker
held by them, $0.85 cash or 0.2285 Canadian Superior Common Shares issued from
treasury, subject to a maximum cash component of $14.2 million and maximum share
component of 7,651,866 Canadian Superior common shares. In addition, Canadian
Superior paid approximately $8.5 million to settle the outstanding amount of
Seekers revolving credit facility.
  With the closing of the Seeker
acquisition the Corporation acquired approximately 1,035 BOE/d (72.5%
natural gas, 27.5% oil & liquids), approximately 2,073 MBOE of proven plus
probable reserves and approximately 1,297 MBOE additional possible reserves,
55,385 net acres of undeveloped land, and 102 sq. km of proprietary 3D
seismic.
   DESCRIPTION
OF THE BUSINESS AND PRINCIPAL PROPERTIES
  Canadian
Superior is engaged in the exploration for, and acquisition, development and
production of, petroleum and natural gas, and LNG projects with operations in
Western Canada, offshore Nova Scotia, Canada, offshore Trinidad and Tobago, the
United States and North Africa. The Corporation also reviews potential
acquisitions and new international exploration blocks to supplement its
exploration and development activities.
   13
  Oil
and Gas Properties
  A summary description of the
Corporation's major producing and exploration properties is set out below.
References to gross volumes refer to total production. References to net volumes
refer to the Corporation's working interest share before the deduction of
royalties payable to others.
  Trinidad and Tobago
  On July 20, 2005, Canadian Superior
signed aProduction Sharing
Control ("PSC")for the 80,020 acre "Intrepid" Block
5(c), offshoreTrinidad and
Tobago, with the Government
of theRepublicofTrinidad and Tobago. The PSC provides Canadian Superior the
right to explore on "Intrepid" Block 5(c), which is located approximately 96
kilometers (60 miles) off the east coast of theislandofTrinidadwith water depths in the range of 150m
to 450m (500 to 1,500 feet). During 2005 and 2006, the Corporation actively
pursued various rig options for the “Intrepid” drilling and entered into a firm
drilling contract for the
Kan Tan IV Semi-Submersible
Drilling Rig to drill the first three exploration wells. These were planned to
evaluate three large separate potential hydrocarbon bearing structures,
“Victory”, “Bounty” and “Endeavour”. These had been delineated by Canadian
Superior following evaluation and interpretation of extensive 3D seismic over
the “Intrepid” Block 5(c).
  Following a scheduled refurbishment inBrownsville,Texas, the Kan Tan IV was moved to theportofChaguarmasinTrinidadand then to the first drilling location
on the "Victory" Prospect . The rig arrived on site June 19, 2007 and commenced
operations on June 25, 2007 when the drilling of a pilot hole at the "Victory-1"
well site commenced. On August 30, 2007, the "Victory" well site reached Total
Depth of 16,621 feet (subsea). While attempting to come out of the hole to
commence wireline logging and possible flow testing of the well, difficulties
were encountered which resulted in being unable to remove the full drillstring
from the well. Accordingly the well was plugged back to a depth of approximately
9,564 feet and re-drilled to a total depth of 16,150 feet.  On
December 17, 2007, the Corporation announced that it had unanimously agreed with
its partners to case and conduct flow tests on the "Victory"
well.
  The "Victory" well tested natural gas in
two main formations. The first test was conducted at rates of between 40 and 45
MMscf/d, and the second test was conducted at rates of over 30 MMscf/d. Both
tests were conducted on a restricted basis and had high flowing pressures. The
well was subsequently suspended with a number of cement plugs for future
re-entry.
  On February 20, 2008, the Kan Tan IV
spudded the "Bounty-1" well after moving approximately 2.2 miles from the
"Victory-1" well location. Drilling was temporarily suspended on June 26, 2008
to allow open-hole logging of a zone of interest, after which drilling resumed.
On July 9, 2008, the Corporation announced that the "Bounty" well reached Total
Depth of 17,360 feet (subsea) and that it had unanimously agreed with its
partners to case and conduct flow tests on the "Bounty-1"
well.
  The "Bounty-1" well successfully tested
natural gas in the main targeted formation. The results from the "Bounty" well
and interpretations of extensive 3-D seismic data and other data indicate a
natural gas resource potential of up to 2.6 TCF of natural gas from the tested
structure. During the testing of the "Bounty" well, production testing equipment
capacity was maximized resulting in flow testing being restricted to a
stabilized rate of 60 mmcf/d of natural gas with a flowing bottomhole pressure
of 7186 psi. The well was subsequently suspended with a number of cement plugs
for future re-entry.
  On August 28, 2008, the Kan Tan IV
spudded the "Endeavour-1" well, the third and final well of the initial
exploration program, approximately 5.2 miles north from the "Bounty-1" well
location. On December 29, 2008 the Corporation announced that, having reached
17,063 feet (subsea), the Corporation and its partners had decided to re-drill
the final section of the well with a mechanical sidetrack due to well bore
damage that had occurred during well control operations. On January 23, 2009,
the Corporation announced that the "Endeavour" well had reached Total Depth of
17,426 feet (subsea) and that it had unanimously agreed with its partners to
case and conduct flow tests on the "Endeavour" well.
   14
  The "Endeavour-1" well successfully
tested natural gas in the main targeted formation. During testing, production
testing equipment capacity was maximized resulting in flow testing being
restricted to a peak flow rate of 60.1 MMscf/d of natural gas with a flowing
wellhead pressure of 4122 psi. The well was subsequently suspended with a number
of cement plugs for future re-entry. The Kan Tan IV rig was subsequently
released from location and from contract.
  To assist Canadian Superior in going
forward with the “Intrepid” project inTrinidad, the Corporation had entered into a
participation agreement with a non-competitive industry financial
partner, Challenger Energy
Inc. The partner
participates on a promoted basis paying 1/3 of Canadian Superior's Block 5(c)
exploration program costs to obtain 25% of Canadian Superior's revenue share of
these prospects. In addition, in August, 2007, the Corporation announced that BG
International Ltd (BGIL), a wholly owned subsidiary of BG Group PLC, had entered
into a farm-in agreement and joint operating agreement. BGIL participated on a
promoted basis paying approximately 40% of Canadian Superior's Block 5(c)
exploration program costs to obtain a 30% working interest in the production
sharing contract. BGIL also paid approximately US$39 million, addressing BG's
share of previous incurred costs and a substantial entry bonus. The partners are
currently in dispute as detailed in theGeneral Developments of the
Businesssection.
  The Corporation also continues to
prepare for the first phase of operations on its Mayaro/Guayaguayare ("M/G")
"Tradewinds" project. On July 27, 2007, Canadian Superior, as operator, and its
joint venture partner, the Petroleum Company of Trinidad and Tobago Limited
("Petrotrin") received the Exploration and Production License for the near shore
Mayaro/Guayaguayare ("M/G") Block off the east coast of theislandofTrinidad and Tobagofrom the Trinidad and Tobago Ministry
of Energy and Energy Industries. This joint venture encompasses two near-shore
Blocks (58,080 gross acres) off the east coast ofTrinidadwhere management hopes to establish
significant oil reserves in the heart of a known producing hydrocarbons-bearing
structural trend. Utilising the existing 2D seismic date set, the Corporation
has identified four initial drilling prospects, two of which have been selected
for the first phase exploration drilling. Acquisition of 3D seismic may now be
deferred in favour of a more selective programme after the initial drilling
results are in hand. The Corporation has made application for the environmental
permits required for drilling to proceed and an Environmental Impact Assessment
is in progress. During 2009, the Corporation will conduct a shallow hazard
survey, including detailed investigation of the proposed well sites. Drilling is
expected to commence in the first half of 2010.
  Trinidad and Tobagohas a well educated labour force, good
transportation and communication links, a strong legal system, a well entrenched
stable democratic system of government, a soundly regulated financial system and
a very successful and growing oil and gas industry that accounts for
approximately 50% of total government revenue.
  North Africa-TunisiaandLibya
  On September 3, 2008, Canadian Superior
announced its "Oasis" Project, referring to the Corporation's entry intoNorth Africa. Oasis commenced with the formal
signing ceremonies for the offshore "7th of November Block" Exploration and
Production Sharing Agreement ("EPSA") that was conducted on Wednesday, August
27, 2008, inTunis,Tunisia. Canadian Superior Energy Inc. and the
Tunisian/Libyan company 'Joint Exploration, Production, and Petroleum Services
Company' ("Joint Oil") also signed a "Swap Agreement" awarding an overriding
royalty interest and optional participating interest to Joint Oil, in Canadian
Superior's "Mariner" Block, offshore, Nova Scotia, Canada. This represents the
first such agreement for eitherTunisiaorLibya. Joint Oil is owned equally by the
Tunisian government via Entreprise Tunisienne d'Activites Petrolieres ("ETAP")
and the Libyan government via Libya Oil Holdings. Under the terms of the EPSA,
Canadian Superior has been named Operator for the "7th of November Block" which
comprises an area of approximately 1200 square miles (768,000 acres), located
some 75 miles offshore the Mediterranean Gulf of Gabes, in water depths ranging
from 250-375 feet.
  The exploration work commitment for the
first phase (4 years) of the 7 year Exploration Period will include three
exploration wells, 300 square miles of 3D seismic, and one appraisal well. This
appraisal well is intended to be the first well in a fast-track drilling program
and will be a direct offset to two significant oil
   15
  and gas discoveries drilled in the
1990's on a feature known as "Zarat" in the adjacent contract area. Based on 3D
seismic acquired subsequent to the discoveries, a substantial portion of the
undeveloped "Zarat discovery area" is interpreted to extend north, into the
"7thof November Block.
  Tunisiais a stable democratic republic with a
well developed economy and an active oil and gas sector. It has close ties with
the European Union with which it has an Association Agreement that came in to
force in 1998. A number of international oil and gas companies are active in the
country. International relations withLibyahave been normalized over the past
decade and full diplomatic relations with theUSwere re-established in 2006. Major
international exploration and production companies such as Shell, ENI and Total
have re-entered the country and have active projects. The Corporation enjoys
good relationships with key stakeholders in both countries.
  The Corporation was awarded the EPSA
following success in a competitive process with other bidders for the
concession. Early production from Zarat will be liquids only which will find
ready access to nearby, well traded markets. There are alternative potential
export routes for gas from the block and an existing gas transportation network
with both domestic consumers and international connections to European
markets.
  OffshoreNova Scotia,Canada
  The Corporation is one of the few
operators involved in all three main play types in the offshoreNova Scotiabasin and currently holds the following
exploration licenses: "Mayflower" (EL2406); "Marauder" (EL2415); "Mariner"
(EL2409). Two of these licences, “Mariner” and Marauder”, are in theSableIslandarea which is an area of natural gas
supply that is very important and strategic for the North Eastern United States
gas supply. The Corporation relinquished EL2412 and EL2413 at the end of 2007.
"Marconi" (EL2416), "Marquis" (EL2402) and 50% of EL 2406 were relinquished at
the end of 2008.
  Canadian Superior's "Mariner" shallow
water block (EL2409) covers 100,656 acres and is located approximately nine
kilometres northeast of Sable Island, offshore Nova Scotia and directly offsets
five significant discoveries near Sable Island, including the ExxonMobil Venture
natural gas production field and other nearby Sable Offshore Energy Project
existing production infrastructure. Three large Cretaceous structures have been
identified for drilling on the “Mariner” block based on an evaluation of seismic
data. The first exploration well, Canadian Superior El Paso "Mariner" I-85, was
drilled on this block in November 2003 to March 2004 and encountered gas pay in
multiple zones. Two new prospective locations have been identified and further
drilling is planned by Canadian Superior on the “Mariner” Block in
2010. Front end geological and geophysical
analysis are complete and environmental approvals are in place.Under the "Swap Agreement" entered into
between the Corporation and Joint Oil in connection with the "Oasis" project, an
overriding royalty interest and optional participating interest was awarded to
Joint Oil in the "Mariner" Block.
  Canadian Superior's "Mayflower"
deepwater project exploration licence (EL2406) covers approximately 711,662
acres and mapping to date indicates the presence of several sizeable deepwater
prospects. These large prospects are structural and are typically formed by
mobile salt tectonics. The Corporation is planning to proceed in due course with
a high resolution seismic program over the "Mayflower" block to further define
targeted structures to enable future drilling.
  Canadian Superior has identified other
Cretaceous and Jurassic prospects on its 100% "Marauder" exploration lands which
cover an additional 370,890 acres offshore Nova Scotia, offsetting the Sable
Island area. The “Marauder” lands directly offsets three significant discovery
licences and have several seismically defined prospects, two of which lie on
trend with significant discoveries near existing production
infrastructure.
  Development of discoveries on Mariner
and Marauder will be facilitated by access to the nearby Sable Offshore Energy
facilities. The Corporation has approached the Sable operator, ExxonMobil, to
determine whether this would be feasible. The operator reverted in March 2009
indicating that Sable facilities would likely be able to accommodate the
proposed level of production subject to suitable flow
conditions.
   16
  Western
Canada
  The Corporation continued its successfulWestern Canadaexploration and development program in
2008.  Currently, the Corporation derives all of its production and
cash flow fromWestern
Canada.Approximately 64% of the Corporation's
production comes from the Drumheller area ofAlberta.The Corporationcompletedthe acquisition of a private company
called Seeker Petroleum Ltd in March of 2008. This gave theCorporationexposure to the Cabin/Petitot area of
NEBC and Kaybob and Sheldon areas ofAlberta. It also provided additional exposure
to the Parkland area of NEBC and the Windfall area ofAlberta.Productionfor the Corporationaveraged approximately3,442boe/d, average daily sales
volume.  During 2008, the Corporation drilled or participated in 33gross,30operated and3non-operated (total of27.5net wells) with an overall success rate
of 87%. In addition, the land picture for Canadian Superior continues to remain
steady as the Corporation makes strategic farmins and land sale acquisitions. At
December 31, 2008, the Corporation held inWestern Canada465,879gross acres (326,626net acres) of predominately Canadian
Superior operated lands with an average working interest of approximately 70%.
Net undeveloped land is178,713acres.
  The Corporationspent most of the drilling budget in
the second half of the year. While drilling results were positive a significant
portion of the new found reserves were not tied inDecember 31, 2008. This resulted in an exit productionrate of 3,165boe/d.Approximately800 boe/d was behind pipe at year end.Asignificant portion of these recently
completed wells will enjoy new reduced royalty incentives.
  Drumheller
Area
  In the Drumheller area of Central
Alberta, Canada, located approximately 60 miles N.E. of the City of Calgary, the
Corporation has major acreage and production holdings in both conventional
Cretaceous plays and in the Horseshoe Canyon and Mannville Coal Bed Methane
("CBM") plays; an area which has shallow low cost prospects and year-round
accessibility.
  The Drumheller area offers a multitude
of opportunities that include both oil and gas play types and these are
contained in six distinct stratigraphic zones.  The shallow targets
include the Second White Specks, Medicine Hat, Belly River Group, and Edmonton
Groups and range in depth from 300-1100 meters (980 - 3600
feet).  Well production in these zones range from 50 - 750 mcf/d with
associated reserve size of 0.1 - 1 Bcf.  Deeper targets in the
Drumheller area include the Mannville group and theBanffformation.  The Mannville
group typically encounters several stacked reservoirs such as the Colony,
Glauconitic, Ostracod, Ellerslie, and Detrital with average production rates for
these horizons ranging from 250 to over 1000 mcf/d and reserves of 0.5 to 2
Bcf.  TheBanffformation is a carbonate play which
ranges in depth from 1100 - 1400 meters (3600 - 4600 feet) and tend to be oil
prone.  On average theBanffcan produce oil rates of 20 - 200 bbl/d
with reserves ranging from 20 - 200 mbbl.
  The Corporation at the end of 2008 held
161,103gross acres (100,146net acres) of land in Drumheller.
Included in this number is 42,684 gross undeveloped acres(34,548 net undeveloped
acres).  This core area accounts for approximately 64% ofthe Corporation's production.  In 2008,
12gross (11.5net) wells weredrilled in the Drumheller
area.
  Coal bed methane has been recognized as
one of the emerging plays available to the oil and gas industry inCanada, which continue to add Proven and
Proven plus Probable Reserves to the Corporation.  The Drumheller area
is near the heart of recent coal bed methane (CBM) development in Western Canada
andthe
Corporationis fortunate to
have one of the largest concentrated high working interest land positions with
significant land holdings in both theHorseshoeCanyonand the Mannville stratigraphic
fairways.
  Due to lower gas prices in 2008, the
Corporation temporarily delayed some planned drilling of Horseshoe Canyon CBM
wells.As with all new plays, the development
strategy continues to be evolving with the more information we gain in order to
save capital and increase the amount of reserves available per well
bore.  One of these changes has been the commingling of the Horseshoe
Canyon CBM with the
   17
  Edmonton Sands.  Initial data
is suggesting that completing both the Horseshoe Canyon and the Edmonton Sands
together will both increase the flow rate and reserves per well.  The
successful results to date achieved bythe Corporationand its partners on a small portion ofthe Corporation's non-operated land will be utilized by
the Corporation to provide a solid foundation for development and operating
drilling on this large CBM potential that exists over our extensive operated
high working interest acreage base within our Drumheller core
area.
  The Corporation's total acreage for CBM
is126,372grossacres(75,258net)forbothHorseshoeCanyonand Mannville CBM
potential.The
Corporationholds105,732grossacres(55,546net)ofHorseshoeCanyonrights.  The Horseshoe Canyon
Coal depths range from 200 - 400 meters (650 - 1300 feet) and are typically
found in 8 - 10 coal seams with each seam averaging from 0.75 - 1.5 meters (2.5
- 5 feet).  These coals contain dry gas and produce little or no
water.
  An untapped resource that exists in the
Drumheller area is the Mannville coals.  These coals are between 1000
- 1300 meters (3300 - 4300 feet) in depth with each seam thicker (up to 4
meters) but less frequent (1 - 5 seams) than the Horseshoe
Canyon.  Resource potential estimates are still in the early stages
but Canadian Superior calculates it has over 1000 BCF (P50) of net sales
reserves in this area.  Currently the Corporation has 42 gross (41
net) sections of land in the Mannville CBM fairway.  Drilling for
these coals would include horizontal drilling techniques.  Plans for
development of Mannville CBM by Canadian Superior will be measured until the
reserve and production parameters are better defined.
  Windfall
  Canadian Superior drilled 4 wells in
2008.  One of
these wells is onnowproduction.  The
Seeker acquisition added production andundeveloped land inthis area.  TheBanff, Nordegg and Mannville are the main
drilling targets. The Corporation continues to look at this higher reward-medium
risk area with a view towards further expansion, using its current land base as
a nucleus.
  Boundary
Lake/Cecil/
  The Boundary Lake/Cecil area is a high
reward-medium risk that continues to gain momentum for exploration activity for
Canadian Superior.  It has multi-zone potential and year-round
access.  Following up successful wells in the area, the Corporation
drilled 2 wells in 2008 inBoundaryLake
  Kaybob
  During 2008 Canadian Superior drilled 2
wells in the Kaybob area ofAlberta. These wells have yet to be tied-in but
do provide theCorporationwith future drillinglocations. This area continues to be of interest
due to it’s muti-zone potential.
   STATEMENT
OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION
  General
  The
reserve disclosure presented below conforms with the requirements of NI 51-101.
Additional information not required by NI 51-101 has been presented to provide
continuity and additional information which management of the Corporation
believes is important to the readers of this information. Boe may be misleading,
particularly if used in isolation. A boe conversion ratio of 6 Mcf:1 bbl is
based on an energy equivalency conversion method primarily applicable at the
burner tip and does not represent a value equivalency at the wellhead. All of
the Corporation's reserves are in Canada, more specifically in the provinces of
British Columbia, Alberta and Saskatchewan.
   18
  Selected
Reserves Information
 The
following tables set forth certain information relating to the oil and natural
gas reserves of the Corporation's properties and the present value of the
estimated future net cash flow associated with such reserves as at December 31,
2008. The information set forth below is derived from the GLJ Report prepared by
GLJ evaluating the Corporation's proved and proved plus probable reserves. The
effective date of the GLJ Report is December 31, 2008. The GLJ Report has been
prepared in accordance with the standards contained in the COGE Handbook and the
reserves definitions contained in NI 51-101 and the COGE Handbook. All
evaluations and reviews of future net cash flow are stated prior to any
provision for interest costs or general and administrative costs and after the
deduction of estimated future capital expenditures for wells to which reserves
have been assigned. It should not be assumed that the estimated future net cash
flow shown below is representative of the fair market value of the Corporation's
properties. There is no assurance that such price and cost assumptions will be
attained and variances could be material. The recovery and reserve estimates of
crude oil, NGLs and natural gas reserves provided herein are estimates only and
there is no guarantee that the estimated reserves will be recovered. Actual
crude oil, NGLs and natural gas reserves may be greater or less than the
estimates provided herein.
  The
Corporation has a Reserves Committee consisting of Messrs Kaare Idland and
Thomas J. Harp, which reviews the qualifications and appointment of the
independent qualified reserves evaluators. The Reserves Committee also reviews
the procedures for providing information to the evaluators. All booked reserves
are based upon annual evaluation and review by the independent qualified
reserves evaluators.
  In
accordance with the requirements of NI 51-101, the Report on Reserves Data by
Independent Qualified Reserves Evaluator in Form 51-101F2 and the Report of
Management and Directors on Oil and Gas Disclosure in Form 51-101F3 are attached
as Appendices "A" and "B" hereto, respectively.
  Reserves Data – Forecast
Prices and Costs
  The
following table sets forth a summary of reserves and values using forecast
pricing and costs:
  Summary
of Oil and Gas Reserves: Effective December 31, 2008
  Gross
      Reserves
                                              Net
      ReservesLight
      and Medium Crude Oil
                                              Natural
      Gas Liquids
                                              Natural
      Gas
                                              Light
      and Medium Crude Oil
                                              Natural
      Gas Liquids
                                              Natural
      GasProved
                                              Mbbls
                                              Mbbls
                                              Mmcf
                                              Mbbls
                                              Mbbls
                                              MmcfDeveloped
    Producing
                                              933
                                              201
                                              21,013
                                              845
                                              133
                                              18,177Developed
      Non-Producing
                                              116
                                              74
                                              5,808
                                              103
                                              46
                                              4,711Undeveloped
                                              13
                                              3
                                              4,287
                                              8
                                              44
                                              5,600Total
      Proved
                                              1,062
                                              278
                                              31,109
                                              955
                                              224
                                              28,488Total
      Probable
                                              892
                                              155
                                              18,080
                                              744
                                              128
                                              16,398Total
      Proved Plus Probable(1)
                                              1,954
                                              433
                                              49,189
                                              1,699
                                              352
                                              44,885
  19
  Net
Present Value of Future Net Revenue of Oil and Gas Reserves
  Before
      Future Income Tax Expenses and Discounted at0%
                                            5%
                                            10%
                                            15%
                                            20%(M$)
                                            (M$)
                                            (M$)
                                            (M$)
                                            (M$)
 ProvedDeveloped
      Producing
                                        157,559
                                        128,628
                                        109,699
                                        96,236
                                        86,121Developed
      Non-Producing
                                        31,464
                                        26,531
                                        22,849
                                        20,011
                                        17,768Undeveloped
                                        32,383
                                        23,578
                                        17,762
                                        13,733
                                        10,829Total
      Proved
                                        221,406
                                        178,737
                                        150,310
                                        129,980
                                        114,717Total
      Probable
                                        158,788
                                        99,507
                                        69,442
                                        51,858
                                        40,557Total
      Proved Plus Probable
                                        380,194
                                        278,244
                                        219,752
                                        181,838
                                        155,274
   After
      Future Income Tax Expenses and Discounted at0%
                                                5%
                                                10%
                                                15%
                                                20%(M$)
                                                (M$)
                                                (M$)
                                                (M$)
                                                (M$)ProvedDeveloped
      Producing
                                                157,559
                                                128,628
                                                109,699
                                                96,236
                                                86,121Developed
      Non-Producing
                                                31,464
                                                26,531
                                                22,849
                                                20,011
                                                17,768Undeveloped
                                                32,383
                                                23,578
                                                17,762
                                                13,733
                                                10,829Total
      Proved
                                                221,406
                                                178,737
                                                150,310
                                                129,980
                                                114,717Total
      Probable
                                                123,499
                                                76,917
                                                53,798
                                                40,456
                                                31,939Total
      Proved Plus Probable
                                                344,905
                                                255,654
                                                204,108
                                                170,436
                                                146,656
 Additional
Information Concerning Future Net Revenue (Undiscounted)
  Revenue
                                Royalties
                                Operating
      Costs
                                Development
      Costs
                                Abandonment
      and Reclamation Costs
                                Future
      Net Revenue Before Income Taxes
                                Future
      Income Tax Expenses
                                Future
      Net Revenue After Income Taxes(M$)
                                (M$)
                                (M$)
                                (M$)
                                (M$)
                                (M$)
                                (M$)
                                (M$)Total
      Proved Reserves
                                402,498
                                49,269
                                109,950
                                13,679
                                8,195
                                221,406
                                -
                                221,406Total
      Proved Plus Probable
                                708,885
                                95,406
                                199,203
                                23,978
                                10,103
                                380,194
                                35,289
                                344,905
 
 Future
Net Revenue By Production Group
  Future
      Net Revenue Before
                                Income
      Taxes and Discounted at 10%(3)(M$)ProvedLight
      and Medium Crude Oil(1)
                              39,793Natural
      Gas(2)
                              100,742Non-Conventional
      Oil and Gas Activities (CBM)
                              9,774Total
                              150,310
 20
 Proved
      Plus ProbableLight
      and Medium Crude Oil(1)
                            59,119Natural
      Gas(2)
                            142,281Non-Conventional
      Oil and Gas Activities (CBM)
                            18,353Total
                            219,752
 Notes:
 (1)
              Including
      solution gas and other by-products.
  (2)
              Including
      by-products but excluding solution
gas.
  (3)
              Other
      company revenue and cost not related to a specific production group have
      been allocated proportionately to production
  groups.
  Pricing Assumptions -
Forecast Prices and Costs
  GLJ
employed the following pricing, exchange rate and inflation rate assumptions as
of December 31, 2008 in estimating the Corporation's reserves data using
forecast prices and costs.
  Table
      1
                              GLJ
      Petroleum Consultants
                              Crude
      Oil and Natural Gas Liquids
                              Price
      Forecast
                              Effective
      January 1, 2009Bank
      of Canada Average Noon Ex-change Rate
                            NYMEX
      WTI Near Month Futures Contract Crude Oil at Cushing
    Oklahoma
                            ICE
      BRENT Near Month Futures Contract Crude Oil FOB North Sea
                            Light
      Sweet Crude Oil (40 API, 0.3%S) at Edmonton
                            Bow
      River Crude Oil Stream Quality at Hardisty
                            Lloyd
      Blend Crude Oil  Stream Quality at Hardisty
                            WCS
      Crude Oil Stream Quality at Hardisty
                            Heavy
      Crude Oil Proxy (12 API) at Hardisty
                            Light
      Crude Oil (35 API, 1.2 %S) at Cromer
                            Medium
      Crude Oil (29 API, 2.0%S) at Cromer
                            Alberta
      Natural Gas Liquids
                              (Then
      Current Dollars)Year
                            Inflla-
                              tion
                              %
                            Constant
      2009
                            Then
      Current
                            Then
      Current
                            Then
      Current
                            Then
      Current
                            Then
      Current
                            Then
      Current
                            Then
      Current
                            Then
      Current
                            Then
      Current
                            Spec
      Ethane
                            Edmonton
      Propane
                            Edmonton
      Butane
                            Edmonton
      Pentanes Plus$US/$Cdn
                            $US/bbl
                            $US/bbl
                            $US/bbl
                            $Cdn/bbl
                            $Cdn/bbl
                            $Cdn/bbl
                            $Cdn/bbl
                            $Cdn/bbl
                            $Cdn/bbl
                            $Cdn/bbl
                            $Cdn/bbl
                            $Cdn/bbl
                            $Cdn/bbl
                            $Cdn/bbl1996
                            1.6
                            0.733
                            28.67
                            21.98
                            20.31
                            29.38
                            25.12
                            21.55
                            n/a
                            20.06
                            28.41
                            26.08
                            n/a
                            23.13
                            17.83
                            30.051997
                            1.6
                            0.722
                            26.46
                            20.62
                            19.32
                            27.85
                            21.18
                            20.55
                            n/a
                            14.41
                            26.52
                            23.72
                            n/a
                            19.41
                            19.76
                            30.911998
                            1.0
                            0.675
                            18.23
                            14.44
                            13.34
                            20.36
                            14.53
                            15.38
                            n/a
                            9.45
                            19.31
                            16.96
                            n/a
                            11.74
                            12.69
                            21.871999
                            1.7
                            0.673
                            24.13
                            19.25
                            17.99
                            27.63
                            22.78
                            22.14
                            n/a
                            19.49
                            26.97
                            25.37
                            n/a
                            15.86
                            18.65
                            27.642000
                            2.7
                            0.673
                            37.19
                            30.23
                            28.41
                            44.57
                            35.28
                            32.61
                            n/a
                            27.49
                            43.28
                            39.92
                            n/a
                            32.15
                            35.59
                            46.312001
                            2.5
                            0.646
                            31.15
                            26.00
                            24.87
                            39.44
                            27.69
                            23.47
                            n/a
                            16.77
                            35.22
                            31.58
                            n/a
                            31.92
                            31.25
                            42.482002
                            2.3
                            0.637
                            30.47
                            26.08
                            25.02
                            40.33
                            31.83
                            30.60
                            n/a
                            26.57
                            37.43
                            35.48
                            n/a
                            21.39
                            27.08
                            40.732003
                            2.8
                            0.716
                            35.48
                            31.07
                            28.47
                            43.66
                            32.11
                            31.18
                            n/a
                            26.26
                            40.09
                            37.55
                            n/a
                            32.14
                            34.36
                            44.232004
                            1.8
                            0.770
                            46.02
                            41.38
                            38.02
                            52.96
                            37.43
                            36.31
                            n/a
                            29.11
                            49.14
                            45.64
                            n/a
                            34.70
                            39.97
                            53.942005
                            2.2
                            0.826
                            61.78
                            56.58
                            55.14
                            69.02
                            44.73
                            43.03
                            43.74
                            34.07
                            62.18
                            56.77
                            n/a
                            43.04
                            51.80
                            69.572006
                            2.0
                            0.882
                            70.72
                            66.22
                            66.16
                            73.21
                            51.82
                            50.36
                            50.66
                            41.84
                            66.38
                            62.26
                            n/a
                            43.85
                            60.17
                            75.412007
                            2.2
                            0.935
                            75.80
                            72.39
                            72.71
                            77.06
                            53.64
                            52.03
                            52.38
                            43.42
                            71.13
                            65.71
                            n/a
                            49.56
                            61.78
                            77.382008
      (e)
                            2.4
                            0.943
                            101.99
                            99.48
                            97.96
                            103.44
                            84.70
                            83.06
                            85.34
                            75.54
                            96.73
                            93.74
                            n/a
                            57.82
                            76.91
                            104.462009
      Q1
                            2.0
                            0.825
                            50.00
                            50.00
                            48.50
                            59.52
                            43.15
                            41.96
                            42.36
                            35.33
                            54.16
                            51.18
                            22.62
                            37.49
                            45.23
                            60.712009
      Q2
                            2.0
                            0.825
                            55.00
                            55.00
                            53.50
                            65.58
                            49.18
                            47.87
                            48.27
                            41.17
                            59.67
                            56.40
                            25.75
                            41.31
                            49.84
                            66.892009
      Q3
                            2.0
                            0.825
                            60.00
                            60.00
                            58.50
                            71.64
                            55.16
                            53.73
                            54.13
                            46.92
                            65.19
                            61.61
                            23.46
                            45.13
                            54.44
                            73.072009
      Q4
                            2.0
                            0.825
                            65.00
                            65.00
                            63.50
                            77.70
                            58.27
                            56.72
                            57.12
                            48.96
                            70.70
                            66.82
                            30.35
                            48.95
                            59.05
                            79.252009
                              Full
      Year
                            2.0
                            0.825
                            57.50
                            57.50
                            56.00
                            68.61
                            51.44
                            50.07
                            50.47
                            43.10
                            62.43
                            59.00
                            25.55
                            43.22
                            52.14
                            69.982010
                            2.0
                            0.850
                            66.67
                            68.00
                            66.50
                            78.94
                            59.21
                            57.63
                            58.03
                            49.76
                            72.63
                            68.68
                            26.80
                            49.73
                            61.57
                            80.522011
                            2.0
                            0.850
                            71.13
                            74.00
                            72.50
                            85.54
                            63.49
                            62.24
                            62.64
                            54.35
                            77.69
                            73.52
                            28.19
                            52.63
                            65.16
                            85.212012
                            2.0
                            0.875
                            80.10
                            85.00
                            83.50
                            90.92
                            69.10
                            67.73
                            68.13
                            59.23
                            84.55
                            80.01
                            29.43
                            57.28
                            70.92
                            92.742013
                            2.0
                            0.925
                            85.00
                            92.01
                            90.51
                            95.91
                            72.89
                            71.45
                            71.85
                            62.54
                            89.19
                            84.40
                            30.27
                            60.42
                            74.81
                            97.822014
                            2.0
                            0.950
                            85.00
                            93.85
                            92.35
                            97.84
                            74.36
                            72.89
                            73.29
                            63.82
                            90.99
                            86.10
                            30.94
                            61.64
                            76.32
                            99.80
 21
 Table
      1
                          GLJ
      Petroleum Consultants
                          Crude
      Oil and Natural Gas Liquids
                          Price
      Forecast
                          Effective
      January 1, 2009Bank
      of Canada Average Noon Ex-change Rate
                        NYMEX
      WTI Near Month Futures Contract Crude Oil at Cushing
    Oklahoma
                        ICE
      BRENT Near Month Futures Contract Crude Oil FOB North Sea
                        Light
      Sweet Crude Oil (40 API, 0.3%S) at Edmonton
                        Bow
      River Crude Oil Stream Quality at Hardisty
                        Lloyd
      Blend Crude Oil  Stream Quality at Hardisty
                        WCS
      Crude Oil Stream Quality at Hardisty
                        Heavy
      Crude Oil Proxy (12 API) at Hardisty
                        Light
      Crude Oil (35 API, 1.2 %S) at Cromer
                        Medium
      Crude Oil (29 API, 2.0%S) at Cromer
                        Alberta
      Natural Gas Liquids
                          (Then
      Current Dollars)Year
                        Inflla-
                          tion
                          %
                        Constant
      2009
                        Then
      Current
                        Then
      Current
                        Then
      Current
                        Then
      Current
                        Then
      Current
                        Then
      Current
                        Then
      Current
                        Then
      Current
                        Then
      Current
                        Spec
      Ethane
                        Edmonton
      Propane
                        Edmonton
      Butane
                        Edmonton
      Pentanes Plus$US/$Cdn
                        $US/bbl
                        $US/bbl
                        $US/bbl
                        $Cdn/bbl
                        $Cdn/bbl
                        $Cdn/bbl
                        $Cdn/bbl
                        $Cdn/bbl
                        $Cdn/bbl
                        $Cdn/bbl
                        $Cdn/bbl
                        $Cdn/bbl
                        $Cdn/bbl
                        $Cdn/bbl
 2015
                        2.0
                        0.950
                        85.00
                        95.73
                        94.23
                        99.82
                        75.86
                        74.36
                        74.76
                        65.13
                        92.83
                        87.84
                        31.62
                        62.89
                        77.86
                        101.812016
                        2.0
                        0.950
                        85.00
                        97.64
                        96.14
                        101.83
                        77.39
                        75.87
                        76.27
                        66.46
                        94.70
                        89.61
                        32.31
                        64.15
                        79.43
                        103.872017
                        2.0
                        0.950
                        85.00
                        99.59
                        98.09
                        103.89
                        78.96
                        77.40
                        77.80
                        67.83
                        96.62
                        91.42
                        33.02
                        65.45
                        81.03
                        105.972018
                        2.0
                        0.950
                        85.00
                        101.59
                        100.09
                        105.99
                        80.55
                        78.96
                        79.36
                        69.22
                        98.57
                        93.27
                        33.74
                        66.77
                        82.67
                        108.102019+
                        2.0
                        0.950
                        85.00
                        +2.0%/yr
                        +2.0%/yr
                        +2.0%/yr
                        +2.0%/yr
                        +2.0%/yr
                        +2.0%/yr
                        +2.0%/yr
                        +2.0%/yr
                        +2.0%/yr
                        +2.0%/yr
                        +2.0%/yr
                        +2.0%/yr
                        +2.0%/yrHistorical
      futures contract price is an average of the daily settlement price of the
      near month contract over the calendar
month.
 Table
      2
                  GLJ
      Petroleum Consultants
                  Natural
      Gas and Sulphur Price Forecast
                  Effective
      January 1, 2009Year
                Henry
      Hub NYMEX
                Midwest
                AECO/NIT
      Spot
                Alberta
      Plant Gate
                Saskatchewan
      Plant Gate
                
                British
      Columbia
                Sulphur
      FOB Vancouver
                Alberta
      Sulphur at Plant GateNear
      Month  Contract
                Price
      @ Chicago
                Spot
                ARP
                Aggre-
                  gator
                Alliance
                Sask
                  Energy
                Spot
                Sumas
      Spot
                Westcoast
      Station 2
                Spot
      Plant GateConstant
      2009 $
                Then
      Current
                Then
      Current
                Then
      Current
                Constant
      2009 $
                Then
      Current$US/
                  mmbtu
                $US/
                  mmbtu
                $US/
                  mmbtu
                $Cdn/
                  mmbtu
                $mmbtu
                $mmbtu
                $mmbtu
                $mmbtu
                $mmbtu
                $mmbtu
                $mmbtu
                $mmbtu
                $mmbtu
                $mmbtu
                $US/LT
                $Cdn/LT1996
                3.27
                2.51
                2.73
                1.39
                1.64
                1.26
                1.63
                N/A
                N/A
                1.52
                1.28
                1.32
                1.49
                1.47
                36.28
                6.481997
                3.18
                2.47
                2.75
                1.85
                2.18
                1.70
                1.97
                N/A
                N/A
                1.85
                1.75
                1.71
                1.90
                1.98
                34.75
                5.121998
                2.73
                2.16
                2.20
                2.03
                2.37
                1.87
                1.94
                N/A
                N/A
                2.05
                2.13
                1.60
                2.15
                2.00
                24.59
                (6.51)1999
                2.90
                2.31
                2.33
                2.92
                3.45
                2.75
                2.48
                N/A
                N/A
                2.82
                2.97
                2.15
                2.93
                2.78
                33.74
                6.932000
                5.31
                4.32
                3.96
                5.08
                6.06
                4.93
                4.50
                4.44
                N/A
                4.79
                5.16
                4.15
                5.06
                4.88
                38.14
                13.592001
                4.83
                4.03
                4.45
                6.23
                7.27
                6.07
                5.41
                4.97
                5.29
                5.72
                6.20
                4.57
                6.32
                6.29
                18.29
                (14.67)2002
                3.92
                3.36
                3.25
                4.04
                4.53
                3.88
                3.88
                3.64
                3.66
                4.04
                4.08
                2.68
                4.18
                3.93
                29.38
                3.042003
                6.25
                5.47
                5.46
                6.66
                7.42
                6.49
                6.13
                5.87
                6.15
                6.41
                6.68
                4.66
                6.45
                6.32
                59.81
                39.832004
                6.87
                6.18
                6.13
                6.88
                7.45
                6.70
                6.31
                6.16
                6.39
                6.48
                6.85
                5.26
                6.56
                6.45
                62.99
                38.612005
                9.82
                9.00
                8.24
                8.58
                9.18
                8.42
                8.30
                8.27
                8.29
                8.36
                8.31
                7.13
                8.22
                8.12
                63.50
                33.772006
                7.46
                6.99
                6.93
                7.16
                7.42
                6.96
                6.57
                6.36
                6.34
                6.67
                6.97
                6.27
                6.58
                6.45
                55.07
                19.272007
                7.45
                7.12
                6.83
                6.65
                6.73
                6.43
                6.20
                6.13
                5.86
                6.18
                6.40
                6.52
                6.40
                6.25
                81.66
                42.032008
      (e)
                9.14
                8.92
                8.91
                8.16
                8.12
                7.92
                7.78
                7.82
                7.83
                8.03
                7.84
                8.33
                8.11
                7.97
                464.73
                448.282009
      Q1
                6.30
                6.30
                6.30
                6.73
                6.50
                6.50
                6.43
                6.20
                5.96
                6.56
                6.64
                5.75
                6.53
                6.33
                50.00
                17.612009
      Q2
                7.05
                7.05
                7.05
                7.64
                7.40
                7.40
                7.32
                7.06
                6.83
                7.45
                7.55
                6.50
                7.44
                7.23
                50.00
                17.612009
      Q3
                6.50
                6.50
                6.50
                6.97
                6.74
                6.74
                6.66
                6.43
                6.19
                6.79
                6.88
                5.95
                6.77
                6.57
                50.00
                17.612009
      Q4
                8.15
                8.15
                8.15
                8.97
                8.72
                8.72
                8.62
                8.32
                8.10
                8.75
                8.88
                7.60
                8.77
                8.56
                50.00
                17.612009
                  Full
      Year
                7.00
                7.00
                7.00
                7.58
                7.34
                7.34
                7.26
                7.00
                6.77
                7.39
                7.49
                6.45
                7.38
                7.17
                50.00
                17.612010
                7.35
                7.50
                7.50
                7.94
                7.55
                7.70
                7.63
                7.43
                7.13
                7.76
                7.85
                6.95
                7.74
                7.54
                65.00
                33.472011
                7.69
                8.00
                8.10
                8.34
                7.78
                8.10
                8.03
                7.81
                7.58
                8.16
                8.25
                7.45
                8.14
                7.94
                75.00
                42.712012
                8.25
                8.75
                8.85
                8.70
                7.97
                8.46
                8.38
                8.16
                7.95
                8.51
                8.61
                8.20
                8.50
                8.29
                75.00
                38.082013
                8.50
                9.20
                9.30
                8.95
                8.04
                8.70
                8.62
                8.39
                8.19
                8.75
                8.86
                8.65
                8.75
                8.54
                75.00
                35.952014
                8.50
                9.38
                9.48
                9.14
                8.05
                8.89
                8.81
                8.57
                8.37
                8.94
                9.05
                8.83
                8.94
                8.73
                75.00
                35.952015
                8.50
                9.57
                9.67
                9.34
                8.07
                9.09
                9.00
                8.76
                8.56
                9.13
                9.25
                9.02
                9.14
                8.92
                75.00
                35.952016
                8.50
                9.76
                9.86
                9.54
                8.08
                9.28
                9.20
                8.96
                8.75
                9.33
                9.45
                9.21
                9.34
                9.12
                75.00
                35.952017
                8.50
                9.96
                10.06
                9.75
                8.10
                9.49
                9.40
                9.15
                8.95
                9.53
                9.66
                9.41
                9.55
                9.33
                75.00
                35.952018
                8.50
                10.16
                10.26
                9.95
                8.11
                9.70
                9.61
                9.35
                9.15
                9.74
                9.86
                9.61
                9.75
                9.54
                75.00
                35.952019+
                8.50
                +2.0%/yr
                +2.0%/yr
                +2.0%/yr
                +2.0%/yr
                +2.0%/yr
                +2.0%/yr
                +2.0%/yr
                +2.0%/yr
                +2.0%/yr
                +2.0%/yr
                +2.0%/yr
                +2.0%/yr
                +2.0%/yr
                +2.0%/yr
                +2.0%/yr
 
  22
  Unless
otherwise stated, the gas price reference point is the receipt point on the
applicable provincial gas transmission system known as the plant
gate.
 The
plant gate price represents the price before raw gas gathering and processing
charges are deducted.
 AECO – C
Spot refers to the one month price averaged for the year.
 The
weighted average realized sales prices by the Corporation for the year ended
December 31, 2008 was $8.58/Mcf for natural gas, $91.32/Bbl for crude oil and
NGL's.
 Reconciliations of Changes
in Reserves and Future Net Revenue
  Reserves
Reconciliation
  The
following table sets forth a reconciliation of the Corporation's total net
proved, probable and total net proved plus probable reserves as at December 31,
2008 against such reserves as at December 31, 2007 based on forecast price and
cost assumptions.
  RECONCILIATION
      OF COMPANY GROSS RESERVES AT DECEMBER 31, 2008
                    BY
      PRINCIPAL PRODUCT TYPE
                    FORECAST
      PRICES AND COSTSFactors
                  Light
      and Medium Oil
                  Unconventional
      Gas (CBM)
                  Conventional
      Natural Gas
                  Natural
      Gas Liquids
                  BOEProved
                  Probable
                  Proved
      Plus Probable
                  Proved
                  Probable
                  Proved
      Plus Probable
                  Proved
                  Probable
                  Proved
      Plus Probable
                  Proved
                  Probable
                  Proved
      Plus Probable
                  Proved
                  Probable
                  Proved
      Plus Probable(Mbbl)
                  (Mbbl)
                  (Mbbl)
                  (MMcf)
                  (MMcf)
                  (MMcf)
                  (MMcf)
                  (MMcf)
                  (MMcf)
                  (Mbbl)
                  (Mbbl)
                  (Mbbl)
                  (Mboe)
                  (Mboe)
                  (Mboe)Dec.
      31, 2007
                  817
                  848
                  1,665
                  4,685
                  5,197
                  9,882
                  20,648
                  8,693
                  29,341
                  192
                  87
                  279
                  5,231
                  3,250
                  8,481Extensions
                  26
                  12
                  38
                  -
                  -
                  -
                  3,734
                  3,212
                  6,946
                  50
                  50
                  100
                  698
                  597
                  1,296Improved
      Recovery*
                  131
                  44
                  175
                  78
                  15
                  93
                  2,539
                  885
                  3,424
                  34
                  12
                  46
                  601
                  206
                  807Technical
      Revisions
                  108
                  (67)
                  41
                  341
                  (424)
                  (83)
                  590
                  (1,077)
                  (487)
                  (18)
                  (20)
                  (37)
                  246
                  (337)
                  (91)Discoveries
                  -
                  -
                  -
                  -
                  -
                  -
                  -
                  -
                  -
                  -
                  -
                  -
                  -
                  -
                  -Acquisitions
                  152
                  44
                  196
                  -
                  -
                  -
                  4,382
                  1,496
                  5,878
                  74
                  25
                  99
                  956
                  318
                  1,275Dispositions
                  -
                  -
                  -
                  -
                  -
                  -
                  -
                  -
                  -
                  -
                  -
                  -
                  -
                  -
                  -Economic
      Factors
                  11
                  11
                  22
                  28
                  31
                  59
                  124
                  52
                  176
                  1
                  1
                  2
                  37
                  25
                  63Production
                  (183)
                  -
                  (183)
                  (260)
                  -
                  (260)
                  5,780
                  -
                  (5,780)
                  (55)
                  -
                  (55)
                  (1,245)
                  -
                  (1,245)Dec.
      31, 2008
                  1,062
                  892
                  1,954
                  4,872
                  4,819
                  9,691
                  26,237
                  13,261
                  39,498
                  278
                  155
                  433
                  6,525
                  4,060
                  10,585*includes
      folloing infill drilling:131
                  44
                  175
                  -
                  -
                  -
                  2034
                  664
                  2698
                  24
                  8
                  32
                  494
                  163
                  657
 
  Undeveloped
Reserves
  Proved
and probable undeveloped reserves have been estimated in accordance with
procedures and standards contained in the COGE Handbook.
  Significant Factors or
Uncertainties Affecting Reserves Data
  The
process of estimating reserves is complex. 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 gas prices and costs change. The reserve
estimates contained herein are based on current production forecasts, prices and
economic conditions. The Corporation's reserves are evaluated by GLJ, an
independent engineering firm.
   23
  Although
every reasonable effort is made to ensure that reserve estimates are accurate,
reserve estimation is an inferential science. As a result, the subjective
decisions, new geological or production information and a changing environment
may impact these estimates. Revisions to reserve estimates can arise from
changes in year-end oil and gas prices, and reservoir performance. Such
revisions can be either positive or negative.
  Future Development
Costs
  The
table below sets out the development costs deducted in the estimation of future
net revenue attributable to proved reserves (using both constant prices and
costs and forecast prices and costs) and proved plus probable reserves (using
forecast prices and costs only).
  Forecast
      Prices and CostsTotal
      Proved Reserves
                                Total
      Proved Plus Probable Reserves(M$)
                                (M$)2009
                                8,951
                                11,4792010
                                3,921
                                9,9132011
                                546
                                1,672Remaining
      Years
                                261
                                914Total
      Undiscounted
                                13,679
                                23,978Total
      Discounted 10% Per Year
                                12,510
                                21,404
 
 The
Corporation expects to fund its future development from internally generated
cash flow from operations, debt (where deemed appropriate) and new equity issues
(if available on favourable terms). In addition, the Corporation may consider
farm-out arrangements for certain projects. The Corporation does not expect that
the cost of funding could make the development of a property uneconomic for the
Corporation, nor is it expected that the cost of such funding will impact the
Corporation's reserves or future net revenue.
  Oil and Gas
Wells
  The
following table sets forth the number and status of wells in which the
Corporation has a working interest as at December 31, 2008.
  Oil
      Wells
                                          Natural
      Gas WellsProducing
                                          Non-Producing
                                          Producing
                                          Non-ProducingGross
                                          Net
                                          Gross
                                          Net
                                          Gross
                                          Net
                                          Gross
                                          NetAlberta
                                          84
                                          61.6
                                          41
                                          28.7
                                          286
                                          133.25
                                          164
                                          102.4British
      Columbia
                                          -
                                          -
                                          -
                                          -
                                          6
                                          2.15
                                          -
                                          -Saskatchewan
                                          -
                                          -
                                          1
                                          1
                                          -
                                          -
                                          6
                                          6Total
                                          84
                                          61.6
                                          42
                                          29.7
                                          292
                                          135.4
                                          170
                                          108.4
 
 Properties With No
Attributed Reserves
  The
following table sets out the Corporation's undeveloped land holdings as at
December 31, 2008.
 24
   Undeveloped
      AcresGross
                      NetBritish
      Columbia
                      34,760
                      12,256Alberta
                      170,527
                      129,995Saskatchewan
                      36,462
                      36,462Offshore
      Nova Scotia(1)
                      1,197,070
                      1,197,070Offshore
      Trinidad and Tobago
                      102,292
                      71,604Total
                      1,541,111
                      1,447,387
 
 Note:
  (1)
              The
      Corporation can extend the expiration dates under various
      terms.
  Expirations and Work
Commitments
  The
following table sets forth the expirations and work commitment for the
undeveloped lands of the Corporation, as at December 31, 2008:
  Work
Commitments Offshore Nova Scotia (Mariner, Mayflower, Marauder)
  Gross
      Acres
                  1,197,070Net
      Acres
                  1,197,070Work
      Expenditure Commitment
                  $55,069,046Deposits
      Tendered
                  $15,166,700
 
 Note:
              In
      Trinidad and Tobago, for Block 5(c), there is a confidential work
      commitment guarantee that is part of the confidential PSC between the
      Government of the Republic of Trinidad and Tobago and Canadian Superior.
      It is anticipated that this work commitment will be more than fully met
      during the ongoing drilling
program.
  Undeveloped Land Due To
Expire
  The
following table represents the undeveloped land of the Corporation due to expire
in 2009:
  Gross
                  Undeveloped
      Acres
                Net
                  Undeveloped
      AcresAlberta
                16,600
                14,658British
      Columbia
                3,575
                1,642Offshore
      Nova Scotia*
                726,721
                726,721Total
                746,896
                743,021
 
 * The
Corporation can extend the expiration dates under various terms.
 
 Forward Contracts and Future
Commitments
  The
Corporation periodically enters into commodity sales agreements and certain
derivative financial instruments to reduce its exposure to commodity price
volatility. These financial instruments are entered into solely for hedging
purposes and are not used for trading or other speculative purposes. At December
31, 2008, the Corporation had no contracts in place.
   25
  Additional Information
Concerning Abandonment and Reclamation Costs
 The following table
represents the Corporation's projected abandonment costs for existing and future
reserve wells, in thousands of dollars, using forecast
prices:
  Annual
      Abandonment CostsProved
      Producing
                Total
      Proved
                Total
      Proved Plus Probable2009
                165
                165
                1652010
                151
                151
                1192011
                321
                352
                2542012
                394
                463
                2912013
                429
                532
                1502014
                753
                923
                5042015
                412
                607
                6002016
                456
                503
                8182017
                266
                349
                5422018
                780
                880
                4282019
                200
                441
                3682020
                192
                213
                238Subtotal
                4,518
                5,579
                4,478Remainder
                1,776
                2,617
                5,626Total
                6,295
                8,195
                10,10310%
      Discounted
                2,929
                3,634
                3,305
 
 The
Corporation estimates the costs to abandon and reclaim all its shut in and
producing wells, facilities, gas plants and pipelines. The Corporation's model
for estimating the amount and timing of future abandonment and reclamation
expenditures was done on an operating area level. Estimated expenditures for
each operating area are based on the Alberta Energy and Utilities Board
methodology, which details the cost of abandonment and reclamation in each
specific geographic region. Each region was assigned an average cost per well to
abandon and reclaim the wells in that area. Facility reclamation costs are
scheduled to be incurred in the year following the end of the reserve life of
its associated reserves. The Corporation will be liable for its share of ongoing
environmental obligations and for the ultimate reclamation of the properties
held by it upon abandonment. Ongoing environmental obligations are expected to
be funded out of cash flow. As at December 31, 2008, the Corporation expected to
incur reclamation and abandonment costs in respect of 623 gross (381.6 net)
wells located on its properties and assets.
  Tax
Horizon
  The
Corporation does not expect to be cash taxable in 2009 or 2010 and with
continued exploration activity, we could push our tax horizon
further.
  Drilling
Activity
  The
following table summarizes the Corporation's drilling results for the year ended
December 31, 2008.
  2008Gross
                          NetOil
                          6
                          5.1
 26
 Natural
      Gas (1)
                              21
                              16.7Coal
      Bed Methane
                              -
                              -Dry
      and Abandoned
                              6
                              5.7Total
                              33
                              27.5
 
 Note:
 
 (1)
              Natural
      Gas wells includes 2 gross wells drilled to earn a 10%
    GORR.
 
 Production
Estimates
  The
following tables set out the volume of the Corporation's production estimated
using both constant and forecast prices and costs for the year ended December
31, 2008, which is reflected in the estimate of future net revenue disclosed in
the tables contained under "Disclosure of Reserves Data".
  2009
      Estimated Daily ProductionEntity
      Description
                                                      Light
      and Medium Oil
                                                      Natural
      Gas
                                                      Natural
      Gas Liquids
                                                      Oil
      EquivalentGross
                                                      Net
                                                      Gross
                                                      Net
                                                      Gross
                                                      Net
                                                      Gross
                                                      Netbbl/d
                                                      bbl/d
                                                      mcf/d
                                                      mcf/d
                                                      bbl/d
                                                      bbl/d
                                                      bbl/d
                                                      bbl/dProved
      ProducingAerial-Michichi
                                                      82
                                                      65
                                                      3.494
                                                      2,885
                                                      41
                                                      26
                                                      705
                                                      572Other
      Properties
                                                      390
                                                      356
                                                      9.920
                                                      7,699
                                                      102
                                                      69
                                                      2,146
                                                      1,708Total:
      Conventional
                                                      472
                                                      421
                                                      13,414
                                                      10,583
                                                      143
                                                      96
                                                      2,851
                                                      2,281Non-Conventional
      Others
                                                      0
                                                      0
                                                      599
                                                      531
                                                      0
                                                      0
                                                      100
                                                      89Total:   Proved
      Producing
                                                      472
                                                      421
                                                      14,012
                                                      11,115
                                                      143
                                                      96
                                                      2,951
                                                      2,369Proved
      Developed Non-ProducingAerial-Michichi
                                                      25
                                                      21
                                                      729
                                                      495
                                                      9
                                                      6
                                                      156
                                                      110Other
      Properties
                                                      36
                                                      28
                                                      2,663
                                                      1,756
                                                      24
                                                      15
                                                      504
                                                      335Total:
      Conventional
                                                      62
                                                      49
                                                      3,392
                                                      2,251
                                                      33
                                                      21
                                                      660
                                                      445Non-Conventional
      Others
                                                      0
                                                      0
                                                      23
                                                      20
                                                      0
                                                      0
                                                      4
                                                      3Total:Proved
      Developed Non-Producing
                                                      62
                                                      49
                                                      3,415
                                                      2,271
                                                      33
                                                      21
                                                      664
                                                      448Proved
      UndevelopedAerial-Michichi
                                                      0
                                                      0
                                                      0
                                                      0
                                                      0
                                                      0
                                                      0
                                                      0Other
      Properties
                                                      21
                                                      12
                                                      152
                                                      419
                                                      1
                                                      8
                                                      47
                                                      89Total:
      Conventional
                                                      21
                                                      12
                                                      152
                                                      419
                                                      1
                                                      8
                                                      47
                                                      89Non-Conventional
      Others
                                                      0
                                                      0
                                                      201
                                                      174
                                                      0
                                                      0
                                                      33
                                                      29Total:Proved
      Undeveloped
                                                      21
                                                      12
                                                      352
                                                      592
                                                      1
                                                      8
                                                      81
                                                      118Total
      ProvedAerial-Michichi
                                                      107
                                                      87
                                                      4,222
                                                      3,380
                                                      50
                                                      32
                                                      860
                                                      682Other
      Properties
                                                      448
                                                      395
                                                      12,735
                                                      9,873
                                                      128
                                                      92
                                                      2,698
                                                      2,133Total:
      Conventional
                                                      555
                                                      482
                                                      16.958
                                                      13,253
                                                      177
                                                      124
                                                      3,558
                                                      2,815Non-Conventional
      Others
                                                      0
                                                      0
                                                      822
                                                      725
                                                      0
                                                      0
                                                      137
                                                      121Total:Total
      Proved
                                                      555
                                                      482
                                                      17,780
                                                      13,978
                                                      177
                                                      124
                                                      3,695
                                                      2,936Total
      ProbableAerial-Michichi
                                                      3
                                                      2
                                                      190
                                                      113
                                                      2
                                                      1
                                                      37
                                                      22Other
      Properties
                                                      20
                                                      13
                                                      2,807
                                                      1,815
                                                      23
                                                      16
                                                      511
                                                      332Total:
      Conventional
                                                      23
                                                      15
                                                      2,997
                                                      1,928
                                                      26
                                                      18
                                                      548
                                                      354Non-Conventional
      Others
                                                      0
                                                      0
                                                      17
                                                      15
                                                      0
                                                      0
                                                      3
                                                      3
  
 27
  
 2009
      Estimated Daily ProductionEntity
      Description
                                                    Light
      and Medium Oil
                                                    Natural
      Gas
                                                    Natural
      Gas Liquids
                                                    Oil
      EquivalentGross
                                                    Net
                                                    Gross
                                                    Net
                                                    Gross
                                                    Net
                                                    Gross
                                                    Netbbl/d
                                                    bbl/d
                                                    mcf/d
                                                    mcf/d
                                                    bbl/d
                                                    bbl/d
                                                    bbl/d
                                                    bbl/dTotal:Total
      Probable
                                                    23
                                                    15
                                                    3,014
                                                    1,943
                                                    26
                                                    18
                                                    551
                                                    357Total
      Proved Plus ProbableAerial-Michichi
                                                    110
                                                    89
                                                    4,412
                                                    3,493
                                                    52
                                                    33
                                                    897
                                                    704Other
      Properties
                                                    468
                                                    409
                                                    15,542
                                                    11,688
                                                    151
                                                    108
                                                    3,209
                                                    2,456Total:
      Conventional
                                                    578
                                                    497
                                                    19,955
                                                    15,181
                                                    203
                                                    141
                                                    4,106
                                                    3,169Non-Conventional
      Others
                                                    0
                                                    0
                                                    840
                                                    740
                                                    0
                                                    0
                                                    140
                                                    123Total:Total
      Proved Plus Probable
                                                    578
                                                    497
                                                    20,794
                                                    15,921
                                                    203
                                                    141
                                                    4,246
                                                    3,292
 
 
 Production History, Prices
Received and Capital Expenditures
  The
following tables summarize certain information in respect of production, product
prices received, royalties paid, operating expenses and resulting netback for
the periods indicated below:
  Quarter
      Ended 2008Dec.
      31
                  Sept.
      30
                  June
      30
                  Mar.
      31Average
      Daily Production(1)Light
      Medium Crude Oil & NGL's (Bbls/d)
                  599
                  689
                  766
                  590Gas
      (Mcf/d)
                  15,726
                  17,268
                  18,626
                  15,123Combined
      (BOE/d)
                  3,220
                  3,567
                  3,871
                  3,110Average
      Price ReceivedLight
      Medium Crude Oil & NGL's/Bbl
                  $50.25
                  $108.99
                  $110.23
                  $88.02Gas
      ($/Mcf) After Hedging
                  $7.22
                  $8.55
                  $10.11
                  $8.14Combined
      ($/BOE) After Hedging
                  $44.48
                  $62.45
                  $70.47
                  $56.29Royalties
      Paid ($/BOE)
                  $11.04
                  $10.24
                  $12.63
                  $11.74Operating
      Expenses ($/BOE)
                  $10.07
                  $14.44
                  $12.45
                  $7.39Netback
      Received ($/BOE)(2)
                  $23.51
                  $37.77
                  $45.39
                  $37.16
 
 Notes:
  (1)
              Before
      deduction of royalties.
 (2)
              Netbacks
      are calculated by subtracting royalties and operating costs from
      revenues.
  For the
year ended December 31, 2008, net average daily production for the Corporation's
was 661 bbls/d light oil and 16,685 mmcf/d natural gas, or 3,442
boe/d.
   INDUSTRY
CONDITIONS
  The oil
and natural gas industry is subject to extensive controls and regulations
governing its operations (including land tenure, exploration, development,
production, refining, transportation, and marketing) imposed by legislation
enacted by various levels of government and with respect to pricing and taxation
of oil and natural gas by agreements among the governments of Canada, Alberta,
British Columbia,
   28
  Saskatchewan,
Nova Scotia and Trinidad and Tobago, all of which should be carefully considered
by investors in the oil and gas industry. It is not expected that any of these
controls or regulations will affect the Corporation's operations in a manner
materially different from how they would affect other oil and gas companies of
similar size. All current legislation is a matter of public record and the
Corporation is unable to predict what additional legislation or amendments may
be enacted. Outlined below are some of the principal aspects of legislation,
regulations and agreements governing the oil and gas industry.
  Pricing and Marketing - Oil
and Natural Gas
  The
producers of oil are entitled to negotiate sales contracts directly with oil
purchasers, with the result that the market determines the price of oil. Oil
prices are primarily based on worldwide supply and demand. The specific price
depends in part on oil quality, prices of competing fuels, distance to market,
the value of refined products, the supply/demand balance, and other contractual
terms. Oil exporters are also entitled to enter into export contracts with terms
not exceeding one year in the case of light crude oil and two years in the case
of heavy crude oil, provided that an order approving such export has been
obtained from the National Energy Board of Canada (the "NEB"). Any oil export to
be made pursuant to a contract of longer duration (to a maximum of 25 years)
requires an exporter to obtain an export licence from the NEB and the issuance
of such licence requires the approval of the Governor in Council.
  The
price of natural gas is determined by negotiation between buyers and sellers.
Natural gas exported from Canada is subject to regulation by the NEB and the
Government of Canada. Exporters are free to negotiate prices and other terms
with purchasers, provided that the export contracts must continue to meet
certain other criteria prescribed by the NEB and the Government of Canada.
Natural gas exports for a term of less than two years or for a term of two to 20
years (in quantities of not more than 30,000 m3/day), must be made pursuant to
an NEB order. Any natural gas export to be made pursuant to a contract of longer
duration (to a maximum of 25 years) or a larger quantity requires an exporter to
obtain an export licence from the NEB and the issuance of such licence requires
the approval of the Governor in Council.
  The
governments of Alberta, British Columbia, Saskatchewan and Nova Scotia also
regulate the volume of natural gas that may be removed from those provinces for
consumption elsewhere based on such factors as reserve availability,
transportation arrangements, and market considerations.
  Pipeline
Capacity
  Although
pipeline expansions are ongoing, the lack of firm pipeline capacity continues to
affect the oil and natural gas industry and limit the ability to produce and to
market natural gas production. In addition, the pro-rationing of capacity on the
inter-provincial pipeline systems also continues to affect the ability to export
oil and natural gas.
  The North American Free
Trade Agreement
  The
North American Free Trade Agreement ("NAFTA") among the governments of Canada,
United States of America, and Mexico became effective on January 1, 1994. NAFTA
carries forward most of the material energy terms that are contained in the
Canada United States Free Trade Agreement. In the context of energy resources,
Canada continues to remain free to determine whether exports of energy resources
to the United States or Mexico will be allowed, provided that any export
restrictions do not: (i) reduce the proportion of energy resources exported
relative to domestic use (based upon the proportion prevailing in the most
recent 36 month period); (ii) impose an export price higher than the domestic
price subject to an exception with respect to certain voluntary measures which
only restrict the volume of exports; and (iii) disrupt normal channels of
supply. All three countries are prohibited from imposing minimum or maximum
export or import price requirements, provided, in the case of export price
requirements, prohibition in any circumstances in which any other form of
quantitative restriction is prohibited, and in the case of import-price
requirements, such requirements do not apply with respect to enforcement of
countervailing and anti-dumping orders and undertakings.
   29
  NAFTA
contemplates the reduction of Mexican restrictive trade practices in the energy
sector by 2010 and prohibits discriminatory border restrictions and export
taxes. NAFTA also contemplates clearer disciplines on regulators to ensure fair
implementation of any regulatory changes and to minimize disruption of
contractual arrangements and avoid undue interference with pricing, marketing
and distribution arrangements, which is important for Canadian natural gas
exports.
  Provincial Royalties and
Incentives
  General
  In
addition to federal regulation, each province has legislation and regulations
which govern land tenure, royalties, production rates, environmental protection,
and other matters. The royalty regime is a significant factor in the
profitability of crude oil, natural gas liquids, sulphur, and natural gas
production. Royalties payable on production from lands other than Crown lands
are determined by negotiations between the mineral freehold owner and the
lessee, although production from such lands may be subject to certain provincial
taxes. Crown royalties are determined by governmental regulation and are
generally calculated as a percentage of the value of the gross production. The
rate of royalties payable generally depends in part on prescribed reference
prices, well productivity, geographical location, field discovery date, method
of recovery, depth of well, and the type or quality of the petroleum product
produced.
  Other
royalties and royalty-like interests are, from time to time, carved out of the
working interest owner's interest through non-public transactions. These are
often referred to as overriding royalties, gross overriding royalties, net
profits interests, or net carried interests.
  Occasionally
the governments of the western Canadian provinces create incentive programs for
exploration and development. Such programs provide for royalty rate reductions,
royalty holidays, and tax credits, and are generally introduced when commodity
prices are low. The programs are designed to encourage exploration and
development activity by improving earnings and cash flow within the industry.
Royalty holidays and reductions would reduce the amount of Crown royalties paid
by oil and gas producers to the provincial governments and would increase the
net income and funds from operations of such producers. However, the trend in
recent years has been for provincial governments to revise existing incentive
programs and royalty structures, which have generally resulted in increases to
the amounts of royalties ultimately payable.
  The
Canadian federal corporate income tax rate levied on taxable income is 22.1%
effective January 1, 2007 for active business income including resource income.
With the elimination of the corporate surtax effective January 1, 2008 and other
rate reductions introduced in the October 2007 Economic Statement, the federal
corporate income tax rate will decrease to 15% in five steps: 19.5% on January
1, 2008, 19% on January 1, 2009, 18% on January 1, 2010, 16.5% on January 1,
2011 and 15% on January 2012.
  Alberta
  In
Alberta, companies are granted the right to explore, produce and develop
petroleum and natural gas resources in exchange for royalties, bonus bid
payments and rents. On October 25, 2007, the Alberta government released a
report entitled "The New Royalty Framework" containing the government's
proposals for Alberta's new royalty regime, and was followed by the Mines and Minerals (New Royalty
Framework) Amendment Act, 2008, which was given Royal Assent on December
2, 2008. The New Royalty Framework and the applicable new legislation became
effective on January 1, 2009. Prior to the New Royalty Framework, the amount of
conventional oil royalties that were payable was influenced by the oil
production, density of the oil, and the vintage of the oil (the "Generic
Regime"). Originally, the vintage classified oil was "new oil" and "old oil"
depending on when the oil pools were discovered. If the pool was discovered
prior to March 31, 1974 it was considered "old oil", and if it was discovered
after March 31, 1974 and before September 1, 1992, it was considered "new oil".
The Alberta government introduced in 1992 a Third Tier Royalty with a base rate
of 10% and a rate cap of 25% for oil pools discovered after September 1, 1992.
The new oil royalty reserved to the Crown had a base rate of 10% and a rate cap
of 30%. The old oil royalty reserved to the Crown had a base rate of 10% and a
rate cap of
   30
  35%.
The New Royalty Framework eliminates this classification and establishes new
royalty rates for conventional oil, natural gas and oil sands. At that time, the
new royalty rates for conventional oil are set by a single sliding rate formula
which is applied monthly and increases the old royalty from 30%-35% applied to
the old and new tiers, to up to 50% and with rate caps once the price of
conventional oil reaches Cdn$120 per barrel.
  The
sliding rate formula includes in its calculation the price of oil and well
production. With respect to natural gas, and similar to the conventional oil
framework, the royalties outlined in the New Royalty Framework are set by a
single sliding rate formula ranging from 5% to 50% with a rate cap once the
price of natural gas reaches Cdn$16.59/Gigajoule. The New Royalty Framework
determined rate is based on well depth, production rate, gas price and gas
quality.
  Prior
to the New Royalty Framework, the royalty reserved to the Crown in respect of
natural gas production, subject to various incentives, was up to 30% in the case
of new natural gas, and up to 35% in the case of old natural gas, depending upon
a prescribed or corporate average reference price. In response to the drop in
commodity prices experienced during the second half of 2008, the Government of
Alberta announced on November 19, 2008, the introduction of a five year program
of transitional royalty rates with the intent of promoting new drilling, which
program became effective January 1, 2009. Under this new program companies
drilling new natural gas or conventional oil deep wells (between 1,000 and 3,500
metres) will be given a one-time option, on a well by well basis, to adopt
either the new transitional royalty rates or those outlined in the New Royalty
Framework. In order to qualify for this program wells must be drilled during the
period starting on January 1, 2009 and ending in December 31, 2013.
  Following
this period all new wells drilled will automatically be subject to the New
Royalty Framework. Oil sands projects are now subject to the New Royalty
Framework, and regulated by, among others, the Oil Sands Royalty Regulation, 2009approved by the Government of Alberta on December 10, 2008. Royalties on
our current Firebag In-Situ project were under the 1997 Generic Regime until the
end of 2008, and assessed based on bitumen value. In December 2008, the
Government of Alberta enacted the New Royalty Framework, which increased royalty
rates from the 1997 Generic Regime to a sliding-scale royalty of 25% to 40% of R
– C, subject to minimum royalty of 1% to 9% of R, depending on oil price. In
both cases, a sliding-scale royalty moves with increases in WTI prices from
Cdn$55\bbl to the maximum rate at a WTI price of Cdn$120\bbl.
  On
April 10, 2008, the Government of Alberta introduced two new royalty programs to
encourage the development of deep oil and gas reserves, and these
are:
  (a) a
five-year oil program for exploration wells over 2,000 metres that will provide
royalty adjustments to offset higher drilling costs and provide a greater
incentive for producers to continue to pursue new, deeper oil plays (these oil
wells will qualify for up to a $1 million or 12 months of royalty offsets,
whichever comes first); and
  (b) a
five-year natural gas deep drilling program that will replace the existing
program in order to encourage continued deep gas exploration for wells deeper
than 2,500 metres (the program will create a sliding scale of royalty credit
according to depth, of up to $3,750 per metre). These new programs are to be
implemented along with the New Royalty Framework.
  Regulations
made pursuant to the Mines and
Minerals Act(Alberta) provided various incentives for exploring and
developing oil reserves in Alberta. However, the Alberta Government announced in
August of 2006 that four royalty programs were to be amended, a new program was
to be introduced and the Alberta Royalty Tax Credit Program was to be
eliminated, effective January 1, 2007. The programs affected by this
announcement were:
   (i)
              Deep
      Gas Royalty Holiday;
  31
  (ii)
              Low
      Productivity Well Royalty
Reduction;
 (iii)
              Reactivated
      Well Royalty Exemption; and
 (iv)
              Horizontal
      Re-Entry Royalty Reduction.
 
  The
program introduced was the Innovative Energy Technologies Program (the "IETP")
which has a stated objective of promoting the producers' investment in research,
technology and innovation for the purposes of improving environmental
performance while creating commercial value. The IETP provides royalty
reductions which are presumed to reduce financial risk. Alberta Energy decides
which projects qualify and the level of support that will be provided. The
deadline for the IETP's final round of applications was September 20, 2008. The
successful applicants for the first two rounds have been announced, and those
for the third round selection are scheduled to be announced in the first half of
2009. The technical information gathered from this program is to be made public
once a two-year confidentiality period expires.
  The New
Royalty Framework includes a policy of "shallow rights reversion". The
Government of Alberta stated that it will implement this policy in order to
maximize the development of currently undeveloped resources that is consistent
with the Government of Alberta's objective of maximizing recovery of known gas
resources, while increasing royalty revenues. The policy's stated objective is
for the mineral rights to shallow gas geological formations that are not being
developed to revert back to the government and be made available for resale, and
in the event of non-productive shallow wells, to sever the rights from shallow
zones and encourage increased production from up-hole zones. In December 2008,
the Government of Alberta proclaimed an amendment to the Mines and Minerals Act(Alberta) with respect to shallow rights reversion. This amendment
affects leases issued after January 1, 2009, with phased-in application for
leases entered into prior to January 1, 2009.
  British
Columbia
  Producers
of oil and natural gas in British Columbia are required to pay annual rental
payments with respect to the Crown leases and royalties and freehold production
taxes in respect of oil and gas produced from Crown and freehold lands. The
amount payable as a royalty in respect of oil depends on the type of oil, the
value of the oil, the quantity of oil produced in a month, and the vintage of
the oil. Generally, the vintage of oil is based on the determination of whether
the oil is produced from a pool discovered before October 31, 1975 (old oil),
between October 31, 1975 and June 1, 1998 (new oil), or after June 1, 1998
(third-tier oil). The royalty rates are calculated in three stages, which take
into account the vintage of the oil, if the oil produced has already been sold
and any royalty exempt value applicable (exempt wells). Oil produced from newly
discovered pools may be exempt from the payment of a royalty for the first 36
months of production or 11,450m3 produced, whichever comes first; and the
royalties for third-tier oil are the lowest reflecting the higher costs of
exploration and extraction that the producers incur. The royalty payable on
natural gas is determined by a sliding scale based on a reference price, which
is the greater of the price obtained by the producer, and a prescribed minimum
price.
  However,
when the reference price is below the select price (a parameter used in the
royalty rate formula), the royalty rate is fixed. As an incentive for the
production and marketing of natural gas, which may have been flared, natural gas
produced in association with oil has a lower royalty than the royalty payable on
non-conservation gas.
  On May
30, 2003, the Ministry of Energy and Mines for British Columbia announced an Oil
and Gas Development Strategy for the Heartlands ("Strategy"). The Strategy is a
comprehensive program to address road infrastructure, targeted royalties and
regulatory reduction, and British Columbia service sector opportunities. In
addition, the Strategy is intended to result in economic and employment
opportunities for communities in British Columbia's heartlands.
  Some of
the financial incentives in the Strategy include:
   32
 
 ·
                Royalty credits towards the construction, upgrading, and
      maintenance of road infrastructure in support of resource exploration and
      development. Funding will be contingent upon an equal contribution from
      industry. This program has evolved over past years as a result of the
      Province's stated objective to increase competitiveness. On March 2, 2009,
      the Government of British Columbia announced the 2009 Infrastructure
      Royalty Credit Program ("Program"), which
      allocates $120 million in royalty credits for oil and gas companies. The
      Program provides access to royalty credits to oil and gas companies with
      respect to certain approved road construction or pipeline infrastructure
      projects intended to improve, or make possible, the access to new and
      underdeveloped oil and gas areas. Companies must apply to the Ministry of
      Energy and Mines for British Columbia prior to 2:00 p.m. on April 30, 2009
      to be considered for approval under the
program
 ·
              Changes
      to provincial royalties: new royalty rates for low productivity natural
      gas to enhance marginally economic resources plays, royalty credits for
      deep gas exploration to locate new sources of natural gas, and royalty
      credits for summer drilling to expand the drilling
  season.
 
  The
British Columbia Energy Plan announced on February 27, 2007 outlines the
requirements for the development of goals for conservation, energy efficiency
and clean energy. In addition, its stated goals include to promote
competitiveness through the implementation of a Net Profit Royalty Program
("NPRP") and facilitate
the development of the oil and gas industry.
  The
NPRP's objective is to share the capital risk of successful developments.
Pursuant to the Net Profit Royalty Regulation, the holder of a lease can apply
to pay monthly net profit royalties on production of oil and for natural gas
wells within a proposed project. The amount paid is calculated on the producer's
interest in the project, and it ranges from 2% to 5% of the gross revenue and
15% to 35% of the net revenues received. In addition, it depends on which stage
the well is at, which may be either pre-payout, after-payout or already
producing marketable gas.
  The
Government of British Columbia has introduced a few more royalty programs, in
addition to the ones previously mentioned, including a royalty program for deep
discovery wells, royalty programs with a stated goal of attracting investment to
less productive shallow gas wells (Ultra-Marginal Royalty Program), and the
implementation of royalty credits to assist the development of the coal-bed gas
reserves found in the Province of British Columbia.
  Saskatchewan
  In
Saskatchewan, the amount payable as a royalty in respect of oil depends on the
vintage of the oil, the type of oil, the quantity of oil produced in a month,
and the value of the oil. For Crown royalty and freehold production tax
purposes, crude oil is considered "heavy oil", "southwest designated oil", or
"non-heavy oil other than southwest designated oil". The conventional royalty
and production tax classifications of oil production are applicable to each of
the three crude oil types.
  The
Crown royalty and freehold production tax structure for crude oil is price
sensitive and varies between the base royalty rates of 5% for all "fourth tier
oil" to 20% for "old oil". Marginal royalty rates are 30% for all "fourth tier
oil" to 45% for "old oil".
  The
amount payable as a royalty in respect of natural gas is determined by a sliding
scale based on a reference price (which is the greater of the amount obtained by
the producer and a prescribed minimum price), the quantity produced in a given
month, the type of natural gas, and the vintage of the natural gas. As an
incentive for the production and marketing of natural gas which may have been
flared, the royalty rate on natural gas produced in association with oil is less
than on non-associated natural gas. The royalty and production tax
classifications of gas production are "fourth tier gas" introduced October 1,
2002, "third tier gas", "new gas", and "old gas". The Crown royalty and freehold
production tax for gas is
   33
  price
sensitive and varies between the base royalty rate of 5% for "fourth tier gas"
and 20% for "old gas". The marginal royalty rates are between 30% for "fourth
tier gas" and 45% for "old gas".
  On
October 1, 2002, the following changes were made to the royalty and tax regime
in Saskatchewan:
  ·
              A
      new Crown royalty and freehold production tax regime applicable to
      associated natural gas (gas produced from oil wells) that is gathered for
      use or sale and is produced from:
  (a) oil
wells with a finished drilling date on or after October 1, 2002;
and
  (b) oil
wells with a finished drilling date prior to October 1, 2002, where the
individual oil well has a gas-oil production ratio in any month of more than
3,500 cubic metres of gas for every cubic metre of oil.
 The royalty/tax is payable on associated natural gas
      produced from an oil well that exceeds approximately 65,000 cubic metres
      in a month. The associated natural gas royalty/tax regime will apply to
      gas produced from oil wells affected by concurrent production approvals
      after October 1, 2002 if the oil wells meet the criteria in paragraphs (a)
      or (b) above.
 ·
              A
      modified system of incentive volumes and maximum royalty/tax rates
      applicable to the initial production from oil wells and gas wells with a
      finished drilling date on or after October 1, 2002 was introduced. The
      incentive volumes are applicable to various well types and are subject to
      a maximum royalty rate of 2.5% and a freehold production tax rate of zero
      percent.
 
 ·
              The
      elimination of the re-entry and short section horizontal oil well
      royalty/tax categories. All horizontal oil wells with a finished drilling
      date on or after October 1, 2002 will receive the "fourth tier" royalty/
      tax rates and new incentive
volumes.
 
 ·
              A
      horizontal oil well with a finished drilling date on or after October 1,
      2002 that is a non-deep oil well qualifies for a 6,000 cubic metre
      incentive volume.
 
 ·
              A
      horizontal oil well with a finished drilling date on or after October 1,
      2002 that is a deep oil well qualifies for a 16,000 cubic metre incentive
      volume.
 
  In
1975, the Government of Saskatchewan introduced a Royalty Tax Rebate ("RTR") as a response to the
Government of Canada disallowing crown royalties and similar taxes as a
deductible business expense for income tax purposes. As of January 1, 2007, the
remaining balance of any unused RTR will be limited in its carry forward to
seven years since the Government of Canada's initiative to reintroduce the full
deduction of provincial resource royalties from federal and provincial taxable
income. Saskatchewan's RTR will be wound down as a result of the Government of
Canada's plan to reintroduce full deductibility of provincial resource royalties
for corporate income tax purposes.
  On June
19, 2007, the Government of Saskatchewan introduced the Orphan Well and Facility
Liability Management Program pursuant to the amendment of the Oil and Gas Conservation Actand the Oil and Gas
Conservation Regulations, 1985. The program includes a security deposit,
which has two purposes:
  (i)
              preventing
      any person with insufficient financial capability from acquiring oil and
      gas wells or facilities; and
 (ii)
              in
      the case of a bankrupt company, the funds cover the decommissioning and
      reclaiming of orphan properties. An additional change introduced is the
      mandatory licensing of all upstream oil and gas facilities in
      Saskatchewan.
  34
  Land
Tenure
  Crude
oil and natural gas located in the western provinces is owned predominantly by
the respective provincial governments. Provincial governments grant rights to
explore for and produce oil and natural gas pursuant to leases, licences, and
permits for varying terms from two years, and on conditions set forth in
provincial legislation including requirements to perform specific work or make
payments. Oil and natural gas located in such provinces can also be privately
owned and rights to explore for and produce such oil and natural gas are granted
by lease on such terms and conditions as may be negotiated.
  Environmental
Regulation
  The oil
and natural gas industry is currently subject to environmental regulations
pursuant to a variety of provincial and federal legislation. Such legislation
provides for restrictions and prohibitions on the release or emission of various
substances produced in association with certain oil and gas industry operations.
In addition, such legislation requires that well and facility sites be abandoned
and reclaimed to the satisfaction of provincial authorities.
  Compliance
with such legislation can require significant expenditures and a breach of such
requirements may result in suspension or revocation of necessary licenses and
authorizations, civil liability for pollution damage, and the imposition of
material fines and penalties.
  Environmental
legislation in the Province of Alberta has been consolidated into the
Environmental Protection and Enhancement Act (Alberta) (the "EPEA"), which came
into force on September 1, 1993, and the Oil and Gas Conservation Act (Alberta)
(the "OGCA"). The EPEA and OGCA impose stricter environmental standards, require
more stringent compliance, reporting and monitoring obligations, and
significantly increased penalties. In 2006, the Alberta Government enacted
regulations pursuant to the EPEA to specifically target sulphur oxide and
nitrous oxide emissions from industrial operations including the oil and gas
industry. No additional expenses are foreseen that are associated with complying
with the new regulations. The Corporation will be committed to meeting its
responsibilities to protect the environment wherever it operates and anticipates
making increased expenditures of both a capital and an expense nature as a
result of the increasingly stringent laws relating to the protection of the
environment, and will be taking such steps as required to ensure compliance with
the EPEA and similar legislation in other jurisdictions in which it operates. We
believe that we are in material compliance with applicable environmental laws
and regulations. We also believe that it is reasonably likely that the trend
towards stricter standards in environmental legislation and regulation will
continue.
  British
Columbia's Environmental Assessment Act became effective June 30, 1995. This
legislation rolls the previous processes for the review of major energy projects
into a single environmental assessment process with public participation in the
environmental review process.
  In
December, 2002, the Government of Canada ratified the Kyoto Protocol
("Protocol"). The Protocol calls for Canada to reduce its greenhouse gas
emissions to 6% below 1990 "business-as-usual" levels between 2008 and 2012.
Given revised estimates of Canada's normal emissions levels, this target
translates into an approximately 40% gross reduction in Canada's current
emissions. It remains uncertain whether the Kyoto target of 6% below 1990
emission levels will be enforced in Canada. The Federal Government has
introduced legislation aimed at reducing greenhouse gas emissions using an
"intensity based" approach, the specifics of which have yet to be determined.
Bill C-288, which is intended to ensure that Canada meets its global climate
change obligations under the Kyoto Protocol, was passed by the House of Commons
on February 14, 2007. As details of the implementation of this legislation have
not yet been announced, the effect on our operations cannot be determined at
this time.
  Trends
  There
are a number of trends that have been developing in the oil and gas industry
during the past several years that appear to be shaping the near future of the
business.
   35
  The
first trend is the volatility of commodity prices. Natural gas is a commodity
influenced by factors within North America. A tight supply-demand balance for
natural gas causes significant elasticity in pricing, whereas higher than
average storage levels tend to depress natural gas pricing. Drilling activity,
weather, fuel switching and demand for electrical generation are all factors
that affect the supply-demand balance. Changes to any of these or other factors
create price volatility.
  Crude
oil is influenced by the world economy, Organization of the Petroleum Exporting
Countries' ability to adjust supply to world demand, and weather. Until July
2008,crude oil prices had increased as a result of political events causing
disruptions in the supply of oil, and increasing demand from countries like
China and India that had been experiencing rapid industrial growth , and these
upward price pressures may have been amplified by investment activities by
commodity speculators. Since July 2008 the market price for crude oil has fallen
drastically, as a result of a developing global recession that has reduced the
consumption of crude oil and also reduced expectations for future crude oil
consumption. The global recession is generally expected to last for an extended
period of time, so barring unexpected political developments that could affect
the supply or delivery of crude oil its price is not expected to increase
significantly in the near term.
  The
impact on the oil and gas industry from commodity price volatility is
significant. During periods of high prices, producers generate sufficient cash
flows to conduct active exploration programs without external capital. Increased
commodity prices frequently translate into very busy periods for service
suppliers triggering premium costs for their services. Purchasing land and
properties similarly increase in price during these periods. During low
commodity price periods, acquisition costs drop, as do internally generated
funds to spend on exploration and development activities. With decreased demand,
the prices charged by the various service suppliers also decline.
  A
second trend within the Canadian oil and gas industry is the fairly consistent
"renewal" of private and small junior oil and gas companies starting up
business. These companies often have experienced management teams from previous
industry organizations that have disappeared as a part of the ongoing industry
consolidation. Many are able to raise capital and recruit well qualified
personnel. The Corporation will have to compete with these companies and others
to attract qualified personnel.
  A third
trend currently affecting the oil and gas industry is the impact on capital
markets caused by investor uncertainty in the North American economy. The
capital market volatility in Canada has also been affected by uncertainties
surrounding the US recession, the market-wide declines in the share values of
publicly traded companies, the economic impact that the Protocol, and other
environmental initiatives, will have on the sector. On October 31, 2006 the
federal government imposed a distribution tax on distributions to investors in
income trusts and publicly traded partnerships (also known as "specified
investment flow-through" entities, or "SIFTs"), and thereby effectively
eliminated the tax efficacy of SIFTS as investment vehicles.  Existing
SIFTs were generally grandfathered until 2011. These business structures had
been attractive to investors primarily because distributions were not taxed
prior to receipt by the investors, which enabled the investors to obtain a
greater return on their invested funds. Under the October 31, 2006 distribution
tax, SIFTs will be liable for tax at a rate consistent with the taxes currently
imposed on corporations commencing in January 2011, provided that the SIFT
experiences only "normal growth" and no "undue expansion" before then, in which
case the tax could be imposed prior to the January 2011 deadline. Although the
October 31, 2006 distribution tax will not affect the method in which the
Corporation will be taxed, it may have an impact on the ability of a SIFT to
purchase producing assets from junior oil and gas companies (as well as the
price that a SIFT is willing to pay for such an acquisition) thereby affecting
exploration and production companies' ability to be sold to a SIFT, a plan which
has been a common "exit strategy" in recent years for small to mid-sized oil and
gas companies. This may be a benefit for the Corporation as it will compete with
SIFTs for the acquisition of oil and gas properties from junior producers.
However, it may also limit the Corporation's ability to sell producing
properties or pursue an exit strategy.
  As a
result of the above factors, access to investment capital for oil and gas
exploration and for acquisitions will likely be more difficult than in recent
years. The Corporation will have to compete with existing companies and with
numerous new companies and their new management teams and
   36
  development
plans to successfully access new investment capital. The Corporation may have to
rely on internally generated funds to conduct their exploration and
developmental programs.
   RISK
FACTORS
  A
number of factors, including but not limited to, those discussed in this section
could cause the Corporation's results to differ materially from its
expectations.
  Exploration, Development and
Production Risks
  An
investment in the Corporation's securities would be speculative due to the
nature of the Corporation's involvement in the exploration, development and
production of oil and natural gas and its present stage of
development.
  Oil and
natural gas exploration involves a high degree of risk and there is no assurance
that expenditures made on future exploration by the Corporation will result in
new discoveries of oil or natural gas in commercial quantities. It is difficult
to project the costs of implementing an exploratory drilling program due to the
inherent uncertainties of drilling in unknown formations, the costs associated
with encountering various drilling conditions, such as over pressured zones and
tools lost in the hole, and changes in drilling plans and locations as a result
of prior exploratory wells or additional seismic data and interpretations
thereof.
  Management
will evaluate exploration and development prospects on an ongoing basis in a
manner consistent with industry standards. The long-term commercial success of
the Corporation depends on its ability to find, acquire, develop and
commercially produce oil and natural gas reserves. No assurance can be given
that the Corporation will be able to locate satisfactory properties for
acquisition or participation. Moreover, if such acquisitions or participations
are identified, the Corporation may determine that current markets, terms of
acquisition and participation or pricing conditions make such acquisitions or
participations uneconomic.
  Future
oil and gas exploration may involve unprofitable efforts, not only from dry
wells, but from wells that are productive but do not produce sufficient net
revenues to return a profit after drilling, operating and other costs.
Completion of a well does not assure a profit on the investment or recovery of
drilling, completion and operating costs. In addition, drilling hazards or
environmental damage could greatly increase the cost of operations, and various
field operating conditions may adversely affect the production from successful
wells. These conditions include delays in obtaining governmental approvals or
consents, shut-ins of connected wells resulting from extreme weather conditions,
insufficient storage or transportation capacity or other geological and
mechanical conditions. 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.
  In
addition, oil and gas operations are subject to the risks of exploration,
development and production of oil and natural gas properties, including
encountering unexpected formations or pressures, premature declines of
reservoirs, blow-outs, cratering, sour gas releases, fires and spills. Losses
resulting from the occurrence of any of these risks could have a materially
adverse effect on future results of operations, liquidity and financial
condition.
  Substantial Capital
Requirements and Liquidity
  The
Corporation anticipates that it will make substantial capital expenditures for
the acquisition, exploration, development and production of oil and natural gas
reserves in the future. Recent market events and conditions, including
disruptions in the international credit markets and other financial systems and
the deterioration of global economic conditions, have caused significant
volatility in commodity prices
   37
  and the
rates at which the Corporation is able to borrow funds for its capital programs.
These conditions worsened in 2008 and are continuing in 2009, causing a loss of
confidence in the broader Canadian, U.S. and global credit and financial markets
and resulting in the collapse of, and government intervention in, major banks,
financial institutions and insurers and creating a climate of greater
volatility, less liquidity, widening of credit spreads, a lack of price
transparency, increased credit losses and tighter credit conditions, including
higher borrowing rates. Despite the various actions taken by governments around
the world, concerns about the general condition of the capital markets,
financial instruments, banks, investment banks, insurers and other financial
institutions caused the broader credit markets to further deteriorate and stock
markets to decline substantially. These factors have negatively impacted company
valuations and will impact the performance of the global economy going
forward.
  As a
result of this weakened global economic situation, the Corporation along with
all other oil and gas entities will have restricted access to capital and
increased borrowing costs. Although our business and asset base have not
changed, the lending capacity of all financial institutions has diminished and
risk premiums have increased. As future capital expenditures will be financed
out of cash generated from operations, borrowings and possible future equity
sales, the Corporation's ability to do so is dependent on, among other factors,
the overall state of the capital markets and investor appetite for investments
in the energy industry generally and our securities in particular.
  To the
extent that external sources of capital become limited or unavailable or
available on onerous terms, the Corporation's ability to make capital
investments and maintain existing properties may be impaired, and the
Corporation's business, financial condition, results of operations and cash flow
may be materially adversely affected as a result. If cash flow from operations
is lower than expected or 2009 capital expenditures exceed current estimates, or
if the Corporation incurs major unanticipated expenses related to development or
maintenance of its existing properties, the Corporation may be required to seek
additional capital to maintain our capital expenditures at planned levels and
the Corporation's debt ratings may be adversely affected.
  Additional Funding
Requirements
  The
Corporation's cash flow from its reserves may not be sufficient to fund its
ongoing activities at all times. From time to time, the Corporation may require
additional financing in order to carry out its oil and natural gas acquisition,
exploration and development activities. Failure to obtain such financing on a
timely basis could cause the Corporation to forfeit its interest in certain
properties, miss certain acquisition opportunities and reduce or terminate its
operations. If the Corporation's revenues from its reserves decrease as a result
of lower oil and natural gas prices or otherwise, it will affect the
Corporation's ability to expend the necessary capital to replace its reserves or
to maintain its production. If the Corporation's cash flow from operations is
not sufficient to satisfy its capital expenditure requirements, there can be no
assurance that additional debt or equity financing will be available to meet
these requirements or available on favourable terms.
  Issuance of
Debt
  From
time to time the Corporation may enter into transactions to acquire assets or
the shares of other corporations. These transactions may be financed partially
or wholly with debt, which may increase the Corporation's debt levels above
industry standards for oil and natural gas companies of similar size. Depending
on future development plans, we may require additional debt financing that may
not be available or, if available, may not be available on favourable terms.
Neither the company’s articles nor its by-laws limit the amount of indebtedness
that we may incur. The level of our indebtedness from time to time, could impair
our ability to obtain additional financing on a timely basis to take advantage
of business opportunities that may arise and could negatively effect our debt
ratings. This in turn, could have a material adverse effect on our business,
financial condition, results of operations and cash flow.
   38
  Prices, Markets and
Marketing of Crude Oil and Natural Gas
 Oil and
natural gas are commodities whose prices are determined based on world demand,
supply and other factors, all of which are beyond the control of the
Corporation. World prices for oil and natural gas have fluctuated widely in
recent years. Any material decline in prices could result in a reduction of net
production revenue. Certain wells or other projects may become uneconomic as a
result of a decline in world oil prices and natural gas prices, leading to a
reduction in the volume of the Corporation's oil and gas reserves. The
Corporation might also elect not to produce from certain wells at lower prices.
All of these factors could result in a material decrease in the Corporation's
future net production revenue, causing a reduction in its oil and gas
acquisition and development activities. In addition, bank borrowings available
to the Corporation are in part determined by the borrowing base of the
Corporation. A sustained material decline in prices from historical average
prices could limit the Corporation's borrowing base, therefore reducing the bank
credit available to the Corporation, and could require that a portion of any
then existing bank debt of the Corporation be repaid.
  In
addition to establishing markets for its oil and natural gas, the Corporation
must also successfully market its oil and natural gas to prospective buyers. The
marketability and price of oil and natural gas which may be acquired or
discovered by the Corporation will be affected by numerous factors beyond its
control. The Corporation will be affected by the differential between the price
paid by refiners for light quality oil and the grades of oil produced by the
Corporation. The ability of the Corporation to market its natural gas may depend
upon its ability to acquire space on pipelines which deliver natural gas to
commercial markets. The Corporation will also likely be affected by
deliverability uncertainties related to the proximity of its reserves to
pipelines and processing facilities and related to operational problems with
such pipelines and facilities and extensive government regulation relating to
price, taxes, royalties, land tenure, allowable production, the export of oil
and natural gas and other aspects of the oil and natural gas
business.
  Insurance
  The
Corporation's involvement in the exploration for and development of oil and
natural gas properties may result in the Corporation becoming subject to
liability for pollution, blow-outs, property damage, personal injury or other
hazards. Although the Corporation has obtained insurance in accordance with
industry standards to address such risks, such insurance has limitations on
liability that may not be sufficient to cover the full extent of such
liabilities. In addition, such risks may not, in all circumstances be insurable
or, in certain circumstances, the Corporation may elect not to obtain insurance
to deal with specific risks due to the high premiums associated with such
insurance or other reasons. The payment of such uninsured liabilities would
reduce the funds available to the Corporation. The occurrence of a significant
event that the Corporation is not fully insured against, or the insolvency of
the insurer of such event, could have a material adverse effect on the
Corporation's financial position, results of operations or
prospects.
  Legal
Proceedings
  Litigation
may be time consuming, expensive, and distracting from the conduct of our
business, and the outcome of litigation may be difficult to predict. The
Corporation is unable to determine the ultimate aggregate amount of monetary
liability or financial impact in these legal matters, which unless otherwise
specified, seek damages of indeterminate amounts. The Corporation cannot
determine whether these matters will, individually or collectively, have a
material adverse effect on our business, results or operations and financial
condition. To the extent expenses incurred in connection with litigation or any
potential regulatory proceeding or action (which may include substantial fees of
attorneys and other professional advisors and potential obligations to indemnify
officers and directors who may be parties to such actions) are not covered by
available insurance, such expenses could adversely affect our cash position. The
Corporation, and any of our named directors or officers, intend to vigorously
defend these actions suits, claims, proceedings and investigations. The
Corporation may in the future be subject to other litigation arising in the
normal course of our business.
   39
  Environmental
Risks
 All
phases of the oil and natural gas business present environmental risks and
hazards and are subject to environmental regulation pursuant to a variety of
international conventions and national, provincial and municipal laws and
regulations. Environmental legislation provides for, among other things,
restrictions and prohibitions on spills, releases or emissions of various
substances produced in association with oil and gas operations. The legislation
also requires that wells and facility sites be operated, maintained, abandoned
and reclaimed to the satisfaction of applicable regulatory authorities.
Compliance with such legislation can require significant expenditures and a
breach may result in the imposition of fines and penalties, some of which may be
material. The Corporation believes that it is in substantial compliance with
existing legislation. Environmental legislation is evolving in a manner expected
to result in stricter standards and enforcement, larger fines and liability and
potentially increased capital expenditures and operating costs. The discharge of
oil, natural gas or other pollutants into the air, soil or water may give rise
to liabilities to governments and third parties and may require the Corporation
to incur costs to remedy such discharge. No assurance can be given that
environmental laws will not result in a curtailment of production or a material
increase in the costs of production, development or exploration activities or
otherwise adversely affect the Corporation's financial condition, results of
operations or prospects.
  In
2002, the Government of Canada ratified the Kyoto Protocol, which calls for
Canada to reduce its greenhouse gas emissions to specified levels. There has
been much public debate with respect to Canada's ability to meet these targets
and the Government's strategy or alternative strategies with respect to climate
change and the control of greenhouse gases. Implementation of strategies for
reducing greenhouse gases whether to meet the limits required by the Protocol or
as otherwise determined, could have a material impact on the nature of oil and
natural gas operations, including those of the Corporation. Given the evolving
nature of the debate related to climate change and the control of greenhouse
gases and resulting requirements, it is not possible to predict either the
nature of those requirements or the impact on the Corporation and its operations
and financial condition.
  Canadian Tax
Considerations
  As the
Corporation is engaged in the oil and natural gas business its operations are
subject to certain unique provisions of the Income Tax Act (Canada) and
applicable provincial income tax legislation relating to characterization of
costs incurred in their businesses which effects whether such costs are
deductible and, if deductible, the rate at which they may be deducted for the
purposes of calculating taxable income. The Corporation has reviewed its
historical income tax returns with respect to the characterization of the costs
incurred in the oil and natural gas business as well as other matters generally
applicable to all corporations including the ability to offset future income
against prior year losses. The Corporation has filed or will file all required
income tax returns and believes that it is full compliance with the provisions
of the Income Tax Act (Canada) and applicable provincial income tax legislation,
but such returns are subject to reassessment. In the event of a successful
reassessment of the Corporation it may be subject to a higher than expected past
or future income tax liability as well as potentially interest and penalties and
such amount could be material.
  Exchange Rate
Risks
  The
Canadian to U.S. dollar exchange rate has recently stabilized at about
CDN$1:USD$0.80, however this rate will certainly fluctuate as the various
effects of the global recession play out in the Canadian and U.S. economies.
Crude oil and natural gas prices are generally U.S. dollar based, so exchange
rate fluctuations will affect the Corporation's sales revenue.  The
Corporation's exposure to currency exchange rate risks are reduced to the extent
that its Canadian capital expenditures, Canadian operating costs and the
majority of the Corporation's general and administrative expenses are paid for
in Canadian dollars.
   40
  Competition
 The
Corporation actively competes for reserve acquisitions, exploration leases,
licences and concessions and skilled industry personnel with a substantial
number of other oil and gas companies, many of which have significantly greater
financial resources than the Corporation. The Corporation's competitors include
major integrated oil and natural gas companies and numerous other independent
oil and natural gas companies and individual producers and
operators.
  The oil
and gas industry is highly competitive. The Corporation's competitors for the
acquisition, exploration, production and development of oil and natural gas
properties, and for capital to finance such activities, include companies that
have greater financial and personnel resources available to them than the
Corporation.
  Certain
of the Corporation's customers and potential customers are themselves exploring
for oil and gas, and the results of such exploration efforts could affect the
Corporation's ability to sell or supply oil or gas to these customers in the
future. The Corporation's ability to successfully bid on and acquire additional
property rights, to discover reserves, to participate in drilling opportunities
and to identify and enter into commercial arrangements with customers will be
dependent upon developing and maintaining close working relationships with its
future industry partners and joint operators and its ability to select and
evaluate suitable properties and to consummate transactions in a highly
competitive environment.
  Reserve
Replacement
  The
Corporation's future oil and natural gas reserves, production, and cash flows to
be derived therefrom are highly dependent on the Corporation successfully
acquiring or discovering new reserves. Without the continual addition of new
reserves, any existing reserves the Corporation may have at any particular time
and the production therefrom will decline overtime as such existing reserves are
exploited. A future increase in the Corporation's reserves will depend not only
on the Corporation's ability to develop any properties it may have from time to
time, but also on its ability to select and acquire suitable producing
properties or prospects. There can be no assurance that the Corporation's future
exploration and development efforts will result in the discovery and development
of additional commercial accumulations of oil and natural gas.
  Reliance on Operators and
Key Employees
  To the
extent the Corporation is not the operator of its oil and natural gas
properties, the Corporation will be dependent on such operators for the timing
of activities related to such properties and will largely be unable to direct or
control the activities of the operators. In addition, the success of the
Corporation will be largely dependent upon the performance of its management and
key employees. The Corporation has no key-man insurance policies, and therefore
there is a risk that the death or departure of any member of management or any
key employee could have a material adverse effect on the
Corporation.
  Permits and
Licenses
  The
operations of the Corporation may require licenses and permits from various
governmental authorities. There can be no assurance that the Corporation will be
able to obtain all necessary licenses and permits that may be required to carry
out exploration and development at its projects.
  Royalties, Incentives and
Production Taxes
  In
addition to federal regulations, each province has legislation and regulations
which govern land tenure, royalties, production rates, environmental protection
and other matters. The royalty regime is a significant factor in the
profitability of oil and natural gas production. Royalties payable on production
from lands other than Crown lands are determined by negotiations between the
mineral owner and the lessee. Crown royalties are determined by government
regulation and are generally calculated as a percentage
   41
  of the
value of the gross production, and the rate of royalties payable generally
depends in part on prescribed reference prices, well productivity, geographical
location, field discovery date and the type or quality of the petroleum product
produced.
  From
time to time, the Governments of Canada, Alberta, British Columbia and
Saskatchewan have established incentive programs which have included royalty
rate reductions, royalty holidays and tax credits for the purpose of encouraging
oil and natural gas exploration or enhanced planning projects.
  Land
Tenure
  Crude
oil and natural gas located in the western provinces is owned predominantly by
the respective provincial governments. Provincial governments grant rights to
explore for and produce oil and natural gas pursuant to leases, licences and
permits for varying terms and on conditions set forth in provincial legislation
including requirements to perform specific work or make payments. Oil and
natural gas located in such provinces can also be privately owned and rights to
explore for and produce such oil and natural gas are granted by lease on such
terms and conditions as may be negotiated.
  Title to
Properties
  The
Corporation has not obtained a legal opinion as to the title to its freehold
properties and cannot guarantee or certify that a defect in the chain of title
may not arise to defeat the Corporation's interest in certain of such
properties. Remediation of title problems could result in additional costs and
litigation. If title defects are unable to be remedied, the Corporation may lose
some of its interest in the disputed properties resulting in reduced
production.
  Although
title reviews have been conducted for past purchases, and may be conducted prior
to the purchase of other oil and natural gas producing properties or the
commencement of drilling wells, such reviews may not discover unforeseen title
defects that could adversely affect the Corporation's title to or proportionate
interest in the property or entitlement to revenue from the
property.
  Multi-Jurisdictional Legal
Risks
  The
Corporation is incorporated under the laws of the Province of Alberta, Canada,
and all but one of the Corporation's directors and all of its officers are
residents of Canada. Consequently, it may be difficult for United States
investors to effect service of process within the United States upon the
Corporation or upon those directors or officers who are not residents of the
United States, or to realize in the United States upon judgments of United
States courts predicated upon civil liabilities under the Securities Exchange
Act of 1934, as amended (United States). Furthermore, it may be difficult for
investors to enforce judgments of the U.S. courts based on civil liability
provisions of the U.S. federal securities laws in a Canadian court against the
Corporation or any of the Corporation's non-U.S. resident executive officers or
directors. There is substantial doubt whether an original lawsuit could be
brought successfully in Canada against any of such persons or the Corporation
predicated solely upon such civil liabilities.
  Reserve
Information
  The
reserve and recovery information contained in the GLJ Report are only estimates
and the actual production and ultimate reserves from the Corporation's
properties may be greater or less than the estimates prepared in such report.
The GLJ Report has been prepared using certain commodity price assumptions which
are described in the notes to the reserve tables. If lower prices for crude oil,
natural gas liquids and natural gas are realized by the Corporation and
substituted for the price assumptions utilized in the report, the present value
of estimated future net cash flows for the Corporation's reserves would be
reduced and the reduction could be significant, particularly based on the
constant price case assumptions. Exploration for oil and natural gas involves
many risks, which even a combination of experience and careful evaluation may
not be able to overcome. There is no assurance that further commercial
quantities of oil and natural gas will be discovered by the
Corporation.
   42
  Dilutive Effect of
Financings and Acquisitions
 Canadian
Superior may make future acquisitions or enter into financing or other
transactions involving the issuance of securities of Canadian Superior which may
be dilutive.
  Corporate
Matters
  To
date, the Corporation has not declared any dividends payable on its outstanding
common shares. The Board of Directors of the Corporation will consider the
Corporation's dividend policy from time to time to assess whether the
declaration of dividends payable on its outstanding common shares is
appropriate. Certain of the directors and officers of the Corporation are also
directors and officers of other oil and gas companies involved in natural
resource exploration and development, and conflicts of interest may arise
between their duties as officers and directors of the Corporation and as
officers and directors of such other companies. Such conflicts must be disclosed
in accordance with, and are subject to such other procedures and remedies as
apply under the Business
Corporations Act (Alberta).
   DIVIDENDS
  To
date, the Corporation has not declared any dividends payable on its outstanding
Common Shares. The Board of Directors of the Corporation will consider the
Corporation's dividend policy from time to time to assess whether the
declaration of dividends payable on its outstanding common shares is
appropriate.
  The
holders of the First Preferred Shares, Series A, which are the only Preferred
Shares issued and outstanding as of the date of the AIF, are entitled to
receive, as and when declared by the Board of Directors of the Corporation, the
payment of cumulative preferential cash dividends in an amount per share equal
to $100 (One Hundred Dollars) multiplied by the applicable dividend rate, which
will be 1.25% until December 30, 2010 and shall, for and restricted to the 150
day period after December 30, 2010, increase by 1/30 of 1% per day, resulting in
a maximum applicable dividend rate of 6.25%.
  Since
March 31, 2006, dividends have been paid in this manner on the last day of
March, June, September and December of each year.  Dividends will
continue to be paid in this manner on the last day of March, June, September and
December of each year as long as all or any of the First Preferred Shares,
Series A remain issued and outstanding.
  The Corporation may elect to
satisfy its dividend payment obligation entirely or in part by delivering Common
Shares to the holders First Preferred Shares, Series A.  When the
Corporation so elects, the number of Common Shares issuable shall be equal to
115% of the applicable dividend rate multiplied by $100 (One Hundred Dollars)
divided by the current market price of the Common Shares
   DESCRIPTION
OF CAPITAL STRUCTURE
  The
Corporation's authorized share capital consists of an unlimited number of Common
Shares and an unlimited number of Preferred Shares.
  Common
Shares
  The
holders of Common Shares are entitled to notice of and to vote at all meetings
of shareholders (except meetings at which only holders of a specified class or
series of shares are entitled to vote) and are entitled to one vote per share.
The holders of Common Shares are entitled to receive such dividends as the Board
of Directors may declare and, upon liquidation, to receive such assets of
Canadian Superior as are distributable to holders of Common Shares.
   43
  Preferred
Shares
 The
Preferred Shares may be issued in one or more series with each series to consist
of such number of shares as may, before the issue of the series, be fixed by the
directors of the Corporation. The directors are authorized, before the issue of
the series, to determine the designation, rights, restrictions, conditions and
limitations attaching to the Preferred Shares of each series. The Preferred
Shares of each series rank equally with respect to the payment of dividends and
the distribution of assets in the event of liquidation, dissolution or
winding-up and in priority to the Common Shares and any other shares of the
Corporation ranking junior to the Preferred Shares. In addition, if any amount
of a fixed cumulative dividend or an amount payable on return of capital in
respect of shares of a series of Preferred Shares is not paid in full, the
shares of the series are entitled to participate rateably with the shares of any
other series of the same class in respect of such amounts.
  Shareholder Rights
Plan
  The
Corporation has adopted a shareholder rights plan in accordance with the Rights
Plan Agreement. Pursuant to the terms of the Rights Plan Agreement, the Rights
Plan shall have a term of 10 years, expiring January 22, 2011, provided that the
Rights Plan is re-approved by the Shareholders of the Corporation at every third
annual meeting of Shareholders. The Rights Plan was last re-approved at the
annual and special meeting of Shareholders held on April 27, 2007.
  The
primary objective of the Rights Plan is to (i) provide Shareholders adequate
time to properly assess the merits of a take-over bid for the common shares of
the Corporation without undue pressure, (b) allow competing bids to emerge and
(iii) give the board of directors of the Corporation time to consider
alternatives to enable Shareholders to maximize the value of their common
shares. The Rights Plan is designed to encourage a potential acquirer to proceed
either by way of a take-over bid specifically permitted by the Rights Plan (a
"Permitted Bid") or with the approval of the board of directors.
  Under
the Rights Plan, one right (a "Right") is attached to each Common Share in the
capital of the Corporation. The Rights will separate from the Common Shares and
become exercisable eight trading days (the "Separation Time") after a person
acquires, or commences a take-over bid to acquire, 20% or more of the voting
shares or other securities convertible into voting shares of the Corporation,
unless the Separation Time is deferred. The acquisition by any person (an
"Acquiring Person") of 20% or more of the Common Shares, other than in a
permitted manner, is called a "Flip-in Event". Any Rights held by an Acquiring
Person will become void upon the occurrence of a Flip-In Event.
  After
the Separation Time, each Right will permit the holder (other than an Acquiring
Person) to purchase from the Corporation, on payment of $15, Common Shares with
a market value of $30. The result will be a dilution of the holdings of the
Acquiring Person. The Corporation anticipates that no Acquiring Person will be
willing to risk such dilution and so will instead either make a take-over bid
that is permitted by the Rights Plan, negotiate with the Board of Directors for
a waiver of the Rights Plan, or apply to regulatory authorities for an order
rendering the Rights Plan ineffective.
  A
person will not become an Acquiring Person, and will not trigger the separation
and ability to exercise the Rights, by becoming the beneficial owner of 20% or
more of the Common Shares pursuant to a Permitted Bid or in other circumstances
provided for under the Rights Plan. Investment advisors (for fully managed
accounts), trust companies (acting in their capacities as trustees and
administrators) and statutory bodies acquiring 20% of the Common Shares are
exempted from triggering a Flip-In Event, provided that they are not making, and
are not part of a group making, a take-over bid.
  The
issue of the Rights is not initially dilutive. However, upon a Flip-In Event
occurring and the Rights separating from the Common Shares, reported earnings
per share on a fully diluted or non-diluted basis may be affected. Holders of
Rights who do not (or, in the case of an Acquiring Person, cannot) exercise
their Rights upon the occurrence of a Flip-In Event will suffer substantial
dilution.
   44
  This
summary is qualified in its entirety by reference to the Rights Plan Agreement.
Shareholders may obtain a copy of the Rights Plan Agreement on written request
to the Corporate Secretary of the Corporation.
  
  MARKET
FOR SECURITIES
  Trading Price and
Volume
  The
Common Shares of Canadian Superior are listed and posted for trading on the
Toronto Stock Exchange and the American Stock Exchange under the symbol "SNG".
The following table sets forth the reported high, low and close sale prices and
volume of trading of the Common Shares as reported by the Toronto Stock Exchange
for the periods indicated.
  High
                    ($)
                  Low
                    ($)
                  Close
                    ($)
                  Volume2008
                  January
                  4.05
                  2.88
                  3.49
                  4,715,900February
                  3.74
                  3.18
                  3.22
                  3,446,700March
                  3.36
                  3.02
                  3.15
                  1,241,200April
                  3.45
                  2.96
                  3.07
                  2,700,100May
                  4.32
                  3.05
                  4.10
                  4,971,300June
                  4.99
                  4.03
                  4.70
                  4,721,700July
                  4.86
                  3.70
                  3.95
                  2,441,700August
                  5.01
                  3.86
                  4.07
                  7,141,100September
                  4.26
                  2.38
                  2.64
                  3,838,000October
                  2.81
                  1.27
                  1.87
                  4,086,200November
                  2.30
                  1.27
                  1.72
                  1,473,800December
                  1.73
                  1.00
                  1.20
                  1,938,8002009
                  January
                  1.46
                  1.15
                  1.18
                  1,019,400February
                  1.25
                  0.35
                  0.46
                  6,257,200March
                  0.66
                  0.23
                  0.59
                  11,673,500
 
 
  DIRECTORS
AND OFFICERS
  Names, Occupations and
Security Holders
  The
following sets forth the names and municipalities of residence of the directors
and officers of the Corporation, their offices or positions with the
Corporation, their principal occupations during the past five years and the
period or periods during which each director has served as a director. The term
of the directors' office expires at the next annual general meeting of the
Corporation. Officers of the Corporation are appointed by the directors until
they resign or until their successors are appointed.
  Name
      and Municipality of Residence
                  Office
      or Position
                  Director
      Since(6)
                  Present
      and Principal Occupation During the Last Five YearsLeigh
      Bilton
                    Calgary,
      Alberta, Canada
                  Non-Executive
      Vice Chairman
                  Not
      Applicable
                  Manager
      of all Canadian Superior Western Canadian operations from 2001 to February
      2009.
  45
  Name
      and Municipality of Residence
                  Office
      or Position
                  Director
      Since(6)
                  Present
      and Principal Occupation During the Last Five YearsCharles
      Dallas (1),(4),(6)
                    Innisfail,
      Alberta, Canada
                  Director
                  2000
                  Rancher
      and independent businessman.Thomas
      J. Harp(2),(5),
      (6)
                    Calgary,
      Alberta, Canada
                  Director
                  2000
                  Interim
      Chairman of the Corporation from April 24, 2009 to the current
      date.  President of Harp Resources Ltd., a private resources
      company.Gregory
      S. Noval
                    Turner
      Valley, Alberta, Canada
                  Executive
      Chairman of the Board
                  1996
                  Executive
      Chairman of the Corporation from June 26, 2007 to April 24,
      2009.  Prior thereto, he was Chairman and Chief Executive
      Officer of Canadian Superior.Michael
      E. Coolen
                    Halifax,
      Nova Scotia, Canada
                  President,
      Chief Executive Officer, Chief Operating Officer and a
      Director
                  2006
                  President
      and Chief Operating Officer of the Corporation from April 10, 2006 to
      April 24, 2009, and CEO from December, 2008 to April 24,
      2009.  Vice President, East Coast Operations of the Corporation
      from March 12, 2004 to April 10, 2006. Prior thereto, was a Director of
      East Coast Operations of the Corporation.Alexander
      Squires(1),(3),
      (6)
                    Toronto,
      Ontario, Canada
                  Director
                  2004
                  Managing
      Partner and Director of Brant Securities Ltd., an independent full service
      securities firm.Robb
      D. Thompson
                    Calgary,
      Alberta, Canada
                  Chief
      Financial Officer
                  Not
      applicable
                  Chief
      Financial Officer of the Corporation from February 5, 2008 to present.
      Prior thereto, Mr. Thompson was CFO of Berkana Energy Inc. from January
      15, 2007 and CEO of Dynetek Industries Ltd. from September
      2000.Kaare
      Idland(2),(5),
      (6)
                    Red
      Deer, Alberta, Canada
                  Director
                  2005
                  Independent
      businessman. Formerly President and Chief Executive Officer of Kidd
      Construction Ltd., an independent oil and gas construction service
      companies.Richard
      Watkins(1),(2),(3),
      (6)
                    Houston,
      Texas, US
                  Director
                  2006
                  Managing
      Director, Energy Advisors LLC, an energy consulting
  firm.Leif
      Snethun
                    Calgary,
      Alberta, Canada
                  Chief
      Operating Officer
                  Not
      applicable
                  Appointed
      Chief Operating Officer of the Corporation on April 29,
      2009.  Prior thereto was the Vice President of Western Canada
      for the Corporation from February 5, 2008 to April 29,
      2009.  Prior thereto founder, President and CEO of Seeker
      Petroleum.
 
 Notes:
  (1)           Member
of the Corporation's Audit Committee.
 (2)           Member
of the Corporation's Compensation Committee.
 (3)           Member
of the Corporation's Disclosure Committee
 (4)           Member
of the Corporation's Special Projects Committee.
 (5)           Member
of the Corporation's Reserves Committee.
 (6)           Member
of the Committee of Independent Directors
 (7)           All
of the Director's terms are for one year and expire at the Corporation's next
annual meeting of shareholders.
  As at
December 31, 2008, the number and percentage of Common Shares beneficially
owned, or controlled or directed, directly or indirectly, by all directors and
executive officers of the Corporation, as a group, was 2,019,958 Common Shares,
being 1.2% of the outstanding Common Shares of the Corporation.
   46
  Cease Trade Orders,
Bankruptcies, Penalties or Sanctions
  No
director or executive officer of the Corporation is, as at the date hereof, or
was within 10 years before the date of hereof, a director, chief executive
officer or chief financial officer of any issuer that:
  (a)
              was
      subject to an order that was issued while the director or executive
      officer was acting in the capacity as director, chief executive officer or
      chief financial officer, or
  (b)
              was
      subject to an order that was issued after the director or executive
      officer ceased to be a director, chief executive officer or chief
      financial officer and which resulted from an event that occurred while
      that person was acting in the capacity as director, chief executive
      officer or chief financial officer.
  For the
purposes of subsection (a) above, “order” means a cease trade order, an order
similar to a cease trade order, or an order that denied the relevant issuer
access to any exemption under securities legislation, that was in effect for a
period of more than 30 consecutive days.
  Other
than the CCAA proceeding described above, no director or executive officer of
the Corporation, or a shareholder holding a sufficient number of securities of
the Corporation to affect materially the control of the
Corporation:
  (c)
              is,
      as at the date of hereof, or has been within the 10 years before the date
      hereof, a director or executive officer of any issuer that, while that
      person was acting in that capacity, or within a year of that person
      ceasing to act in that capacity, became bankrupt, made a proposal under
      any legislation relating to bankruptcy or insolvency or was subject to or
      instituted any proceedings, arrangement or compromise with creditors or
      had a receiver, receiver manager or trustee appointed to hold its assets;
      or
  (d)
              has,
      within the 10 years before the date hereof, become bankrupt, made a
      proposal under any legislation relating to bankruptcy or insolvency, or
      become subject to or instituted any proceedings, arrangement or compromise
      with creditors, or had a receiver, receiver manager or trustee appointed
      to hold the assets of the director, executive officer or
      shareholder.
  No
director or executive officer of the Corporation, or a shareholder holding a
sufficient number of securities of the Corporation to affect materially the
control of the Corporation, has been subject to
  (e)
              any
      penalties or sanctions imposed by a court relating to securities
      legislation or by a securities regulatory authority or has entered into a
      settlement agreement with a securities regulatory authority;
      or
  (f)
              any
      other penalties or sanctions imposed by a court or regulatory body that
      would likely be considered important to a reasonable investor in making an
      investment decision.
  Conflicts of
Interest
  Certain
of the directors and officers of the Corporation are directors and/or officers
of other private and public companies. Some of these private and public
companies may, from time to time, be involved in business transactions or
banking relationships which may create situations in which conflicts might
arise. Any such conflicts shall be resolved in accordance with the procedures
and requirements of the relevant provisions of the Business Corporations Act
(Alberta), including the duty of such directors and officers to act honestly and
in good faith with a view to the best interests of the Corporation.
   47
 LEGAL
PROCEEDINGS
 For the
year ended December 31, 2008 the Corporation is involved in various claims and
litigation arising in the ordinary course of its business. In the opinion of
Canadian Superior, the various claims and litigation arising therefrom are not
expected to have a material adverse effect on the Corporation's financial
position. The Corporation also maintains insurance to address any unforeseen
claims.
  In the
period subsequent to the December 31, 2008 year end the Corporation became
involved in two related and material legal proceedings, specifically the CCAA
orders which have been granted to the Corporation and the interim receivership
order affecting the Corporation's interest in Block 5(c).  The details
of these material legal proceedings are set out in the foregoing
sections.
   INTERESTS
OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS
  Within
the last three completed financial years or the current financial year of the
Corporation, other than as disclosed herein, none of the directors or executive
officers of the Corporation or any person that beneficially owns, or controls or
directs, directly or indirectly, more than 10% of the Common Shares of the
Corporation, and no associate or affiliate of any such persons, has or has had
any material interest, direct or indirect, in any transaction that has
materially affected or is reasonably expected to materially affect the
Corporation or any of its affiliates.
  During
the year ended December 31, 2008, Canadian Superior paid $ 2.3 million (2007 -
$1.9 million) for equipment rentals to a related party company controlled by Mr.
Gregory Noval, an officer and director of Canadian Superior.  Also,
during 2008, the Corporation invoiced $ 1.1 million (2007 - $0.7 million to this
company for payroll services).
  At
December 31, 2008, Canadian Superior was carrying a receivable in the amount of
US$29.1 million (2007 - US$19.7 million) from a company related to Mr. Gregory
Noval, an officer and director of Canadian Superior.  These
receivables pertain to transactions for Canadian Superior's Trinidad "Intrepid"
Block 5(c) project in Trinidad.  These transactions were incurred
under normal industry terms and conditions.
  In
November 2004, the Corporation entered into participation agreements in respect
of the Corporation's offshore Nova Scotia and offshore Trinidad and Tobago
prospects with a company controlled by Mr. Noval at the time. Pursuant to the
participation agreements, the Corporation has the right to participate on a
promoted basis for 16 2/3% of Canadian Superior's costs of the offshore Nova
Scotia wells (this was subsequently increased to 33 1/3%) and the company
controlled by Mr. Noval has the right to participate on a promoted basis for 33
1/3% of Canadian Superior's costs of certain earning wells in Trinidad and
Tobago.
  The
transactions described in this section were in the normal course of operations
and agreed to by the related company and the Corporation based on extensive
negotiations and Board approval and approval by the Corporation.
   TRANSFER
AGENT AND REGISTRAR
  Valiant
Trust Company at 310, 606 - 4th Street SW Calgary, Alberta, T2P 1T1, is the
transfer agent and registrar for the Common Shares.  This is also the
location of the register.
   48
 MATERIAL
CONTRACTS
 There
are no "material contracts", as defined under applicable securities regulations,
that were entered into either within the last financial year, or before the
before the last financial year that are still in effect.
  A
"material contract" in this context does not include otherwise material
contracts that are entered into in the ordinary course of business unless that
material contract is:
  (a)
              a contract to which directors,
      officers, or promoters are parties otherthan a contract of
      employment;
 (b)
              a continuing contract to sell the
      majority of the reporting issuer’s products or services or to purchase the
      majority of the reporting issuer’s requirements of goods, services, or
      raw
      materials;
 (c)
              a franchise or licence or other
      agreement to use a patent, formula, tradesecret, process or trade
      name;
 (d)
              a financing or credit agreement
      with terms that have a direct correlation withanticipated cash
      distributions;
 (e)
              an external management or
      external
      administration agreement; or
 (f)
              a contract on which the reporting
      issuer’s business is
      substantially dependent.
 
  INTERESTS
OF EXPERTS
  There
is no person or company whose profession or business gives authority to a
statement made by such person or company and who is named as having prepared or
certified a statement, report or valuation described or included in a filing, or
referred to in a filing, made under National Instrument 51-102 by the
Corporation during, or related to, the Corporation's most recently completed
financial year other than GLJ, the Corporation's independent engineering
evaluator and Meyers Norris Penny LLP, the Corporation's auditors.
  Neither
GLJ nor any of directors, officers or employees had any registered or beneficial
interests, direct or indirect, in any securities or other property of the
Corporation or of the Corporation's associates or affiliates either at the time
they prepared the statement, report or valuation prepared by it nor at any time
thereafter, nor are any securities or other property of the Corporation to be
received by them. Meyers Norris Penny LLP, the Corporation's auditors, are
independent in accordance with the auditor's rules of professional conduct in a
jurisdiction of Canada.
  None of
the aforementioned persons or companies, nor any director, officer or employee
of any of the aforementioned persons or companies, is or is expected to be
elected, appointed or employed as a director, officer or employee of the
Corporation or of any associate or affiliate of the Corporation.
   AUDIT
COMMITTEE
  The
Audit Committee of the Corporation consists of Messrs. Alexander Squires,
Richard Watkins and Charles Dallas, each of whom is considered "independent" and
"financially literate" within the meaning of National Instrument 52-110 - Audit
Committees.
  Mandate of the Audit
Committee
  The
Audit Committee is appointed by the Board of Directors of the Corporation to
assist the Board of Directors in fulfilling its oversight responsibilities,
including with respect to:
  1.
              the
      integrity of the Corporation's financial
  statements;
   49
  2.
              the
      integrity of the financial reporting
process;
  3.
              the
      system of internal control and management of financial
    risks;
  4.
              the
      external auditors' qualifications and independence;
  and
  5.
              the
      external audit process and the Corporation's processes for monitoring
      compliance with laws and
regulations.
  The
Charter of the Audit Committee of the Board of Directors of Canadian Superior is
attached hereto as Appendix "C".
  Relevant Education and
Experience of Audit Committee Members
  The
following is a brief summary of the education or experience of each member of
the Audit Committee that is relevant to the performance of his responsibilities
as a member of the Audit Committee, including any education or experience that
has provided the member with an understanding of the accounting principles used
by the Corporation.
  Name
      of
                  Audit
      Committee Member
                Relevant
      Education and ExperienceAlexander
      Squires, CFA
                Since
      1997, Mr. Squires has been a Manager Partner and Director of Brant
      Securities Ltd., an independent full service securities
    firm.Richard
      Watkins
                Mr.
      Watkins has held a variety of accounting and corporate governance
      positions spanning a period of over 20 years in the oil and gas
      industry.Charles
      Dallas
                Mr.
      Dallas has over 40 years of oil and gas experience in various supervisory
      positions, including being a controller. He has also during much of that
      time managed his own independent ranch and farm businesses, including the
      financial management of these
enterprises.
 
 Audit Committee
Oversight
  At no
time since the commencement of the Corporation's most recently completed
financial year has a recommendation of the Audit Committee to nominate or
compensate an external auditor not been adopted by the Board of Directors of the
Corporation.
  External Auditor
Fees
  For the
year ended December 31, 2008 and 2007, Meyers Norris Penny LLP and its
affiliates were paid approximately $394,247 and $311,365, respectively, as
detailed below:
  Audit
Fees
  Audit
fees consist of fees for the audit of the Corporation's annual financial
statements or services that are normally provided in connection with statutory
and regulatory filings or engagements. The aggregate audit fees billed by the
Corporation's external auditor in each of the last two financial years were
$216,725 in 2008 and $201,798 in 2007.
  Audit-Related
Fees
  Audit-related
fees include fees relating to the review of the Corporation's quarterly
financial statements. The aggregate audit-related fees billed by the
Corporation's external auditor in each of the last two financial years were
$65,850 in 2008 and $52,115 in 2007
   50
  Tax Fees
 Tax
fees include fees relating to tax compliance, tax planning, tax advice and
various taxation matters. The aggregate tax fees billed by the Corporation's
external in each of the last two financial years were $15,330 in 2008 and $7,420
in 2007.
  All Other
Fees
  All
other fees consists of fees for services provided by Meyers Norris Penny LLP
other than audit, audit-related and tax services, including prospectus and other
offering related work. The aggregate fees billed by the Corporation's external
auditor in each of the last two financial years other than audit fees,
audit-related fees and tax fees, were $96,342 in 2008 and $50,032 in
2007.
   ADDITIONAL
INFORMATION
  Additional
information relating to the Corporation may be found on the internet on the
System for Electronic Document Analysis and Retrieval (SEDAR) which can be
accessed at www.sedar.com. Additional information, including directors' and
officers' remuneration and indebtedness, principal holders of the Corporation's
securities and securities authorized for issuance under equity compensation
plans, if applicable, is contained in the Corporation's Management Information
Circular for its most recent annual meeting of shareholders that involved the
election of directors. Additional financial information is provided in the
Corporation's financial statements and management's discussion and analysis for
its most recently completed financial year. Additional copies of this Annual
Information Form and the documents set forth in this section are available upon
request by contacting the Corporation at 3200, 500 – 4th Avenue SW T2P 2V6 or by
phone at (403) 294-1411 or fax at (403) 216-2374.
   51
  APPENDIX
"A"
  FORM
51-101F2
 REPORT
ON RESERVES DATA
 BY
 INDEPENDENT
QUALIFIED RESERVES
 EVALUATOR
OR AUDITOR
    To the Board of
Directors of Canadian Superior Energy Inc. (the "Company");
  1.
                We have
      prepared an evaluation of the Company’s reserves data as at December 31,
      2008. The reserves data are estimates of proved reserves and probable
      reserves and related future net revenue as at December 31, 2008, estimated
      using forecast prices and costs.
  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 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, 2008, and identifies the respective portions
      thereof that we have audited, evaluated and reviewed and reported on to
      the Company's board of directors:
  Independent
      Qualified Reserves Evaluator
                Description
      and Preparation Date of Evaluation Report
                Location
      of Reserves (Country or Foreign Geographic Area)
                Net
      Present Value of Future Net Revenue
                  (before
      income taxes, 10% discount rate - $M)Audited
                Evaluated
                Reviewed
                TotalGLJ Petroleum
      Consultants
                Corporate
      Summary
                  March 25,
      2009
                Canada
                -
                219,752
                -
                219,752
  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.
  6.
                We have no
      responsibility to update our reports referred to in paragraph 4 for events
      and circumstances occurring after their respective preparation
      dates.
  7.
                Because the
      reserves data are based on judgments regarding future events, actual
      results will vary and the variations may be material. However, any
      variations should be
   52
   consistent
      with the fact that reserves are categorized according to the probability
      of their recovery.
   EXECUTED as to our
report referred to above:
    GLJ Petroleum
Consultants Ltd., Calgary, Alberta, Canada, March 27, 2009
   (Signed)"John
H. Stilling, P. Eng."
 Vice
President
  
   53
  APPENDIX
"B"
  Report
of Management and Directors
 on
Reserves Data and Other Information
  
 This
is the form referred to in item 2 of section 2.1 of National Instrument 51-101
Standards of Disclosure for
Oil and Gas Activities ("NI-51-101").
  1.
              Terms
      to which a meaning is ascribed in NI 51-101 have the same
      meaning in this form.
  2.
              The
      reportreserves
      data referred to in item 2 of section 2.1 of NI 51-101, to be
      executed by one or more qualified reserves evaluators
      or auditors independent of the reporting issuer, must
      in all material respects be as
follows:
  Per NI
51-101F3]Management of Canadian Superior Energy Inc. (the "Corporation") are
responsible for the preparation and disclosure of information with respect to
the Corporation’s oil and gas activities in accordance with securities
regulatory requirements. This information includes reserves data which are
estimates of proved reserves and probable reserves and related future net
revenue as at [last day of the reporting issuer’s most recently completed
financial year], estimated using forecast prices and costs.
  An
independent qualified reserves evaluator has evaluated and reviewed the
Corporation’s reserves data. The report of the independent qualified reserves
evaluator is presented in Appendix "A" to the Annual Information Form of the
Corporation dated March 27, 2009.
  The
Reserves Committee of the board of directors of the Corporation has
  (a)
              reviewed
      the Corporation’s procedures for providing information to the independent
      qualified reserves evaluator;
  (b)
              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
  (c)
              reviewed
      the reserves data with management and the independent qualified reserves
      evaluator.
  The
Reserves Committee of the board of directors has reviewed the Corporation’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 Reserves Committee,
approved
  (a)
              the
      content and filing with securities regulatory authorities of Form 51-101F1
      containing reserves data and other oil and gas
  information;
  (b)
              the
      filing of Form 51-101F2 which is the report of the independent qualified
      reserves evaluator on the reserves data;
and
  (c)
              the
      content and filing of this report.
   54
  Because
      the reserves data are based on judgments regarding future events, actual
      results will vary and the variations may be material. However, any
      variations should be consistent with the fact that reserves are
      categorized according to the probability of their
  recovery.
  DATED   April
29, 2009.
 
 (signed) "Thomas J.
      Harp"
                        
                        (signed) "Kaare
      Idland"THOMAS J. HARP
                          Director & Member of Reserves
      Committee
                        
                        KAARE IDLAND
                          Director & Chairman of
      Reserves
Committee
 
  55
  APPENDIX
"C"
  CHARTER
OF THE AUDIT COMMITTEE OF THE
 BOARD
OF DIRECTORS OF CANADIAN SUPERIOR ENERGY INC.
  
  Purpose/Objectives
  The
Audit Committee is appointed by the Board to assist the Board in fulfilling its
oversight responsibilities, including:
  1.
              the
      integrity of the Corporation's financial
  statements;
  2.
              the
      integrity of the financial reporting
process;
  3.
              the
      system of internal control and management of financial risks the external
      auditors' qualifications and independence;
and
  4.
              the
      external audit process and the Corporation's process for monitoring
      compliance with laws and
regulations.
  In
performing its duties, the Committee will maintain effective working
relationships with the Board, management and the external auditors. To perform
his or her role effectively, each Committee member will obtain an understanding
of the Corporation's business, operations, risks and related legislation,
regulations and industry standards. So that the Audit Committee can discharge
the duties as a whole, all Audit Committee members must be financially literate,
and at least one member must have significant accounting or related financial
management experience.
  Authority
  The
Board authorizes the Committee, within its scope of duties and responsibilities,
to:
  1.
              seek
      any information it requires from any employee of the Corporation (whose
      employees are directed to cooperate with any request made by the
      Committee);
  2.
              seek
      any information it requires directly from external parties including the
      external auditors and independent reservoir engineering firm;
      and
  3.
              obtain
      outside legal or professional advice without seeking Board approval
      (however providing  notice to the Chair of the
      Board).
  Organization
  The
following provisions and regulations shall apply to the composition of the
Committee:
  1.
              the
      Committee shall consist of three members of the Board of the
      Corporation;
  2.
              the
      members of the Committee shall be independent members of the Board as
      defined in section 1.4 of Multilateral Instrument 52-110 Audit Committees,
      as well as Part 1, section 121(A) of the AMEX Company
    manual;
  3.
              the
      Chairman of the Committee shall be determined by the
  Board;
  4.
              two
      members of the Committee shall constitute a quorum
  thereof;
   56
  5.
              no
      business shall be transacted by the Committee except at a meeting of its
      members at which a quorum is present in person or by telephone or by a
      resolution in writing signed by all members of the
    Committee;
  6.
              the
      meetings and proceedings of the Corporation that regulate meetings and
      proceedings of the Board shall apply to the
  Committee;
  7.
              the
      Committee may invite such directors, officers or employees of the
      Corporation, the external auditors and the independent reservoir
      engineering firm as it may see fit, to attend its meetings and take part
      in the discussion and consideration of the affairs of the Committee;
      and
  8.
              meetings
      shall be held not less than four times per year, generally coinciding with
      the release of interim or year-end financial information including
      consecutive sessions with Management and the External
      Auditors.
  Special
meetings may be convened as required upon the request of the Committee. The
external auditors and independent reservoir engineering firm may convene a
meeting if they consider that it is desirable or necessary; and the proceedings
of all meetings will be minuted.
  Duties and
Responsibilities
  The
Board hereby delegates and authorizes the Committee to carry out the following
duties and responsibilities to the extent that these activities are not carried
out by the Board as a whole:
  Corporate
Information and Internal Control
  1.
              review
      and recommend for approval of quarterly and annual financial statements,
      MD&A and annual reports of the
Corporation;
  2.
              review
      of internal control systems maintained by the
  Corporation;
  3.
              review
      of significant accounting and tax compliance issues where there is choice
      among various alternatives or where application of a policy has a
      significant effect on the financial results of the
      Corporation;
  4.
              review
      of significant proposed non-recurring events such as mergers, acquisitions
      or divestitures; and
  5.
              review
      of press releases or other publicly circulated documents containing
      financial information.
  External
Auditors
  1.
              retain
      and/or terminate the external auditors (subject to regulatory and
      shareholder notification) who, in turn, will report directly to the Audit
      Committee;
  2.
              review
      the terms of the external auditors' engagement and the appropriateness and
      reasonableness of the proposed engagement
fees;
  3.
              annually,
      obtain and review a certificate attesting to the external auditors'
      independence, identifying all relationships between the external auditors
      and the Corporation;
  4.
              annually,
      evaluate the external auditors' qualifications, performance and
      independence;
  5.
              annually,
      to assure continuing auditors' independence, consider the rotation of the
      lead audit partner or the external audit
firm;
   57
  6.
              pre-approve
      engagements for non-audit services provided by the external auditors or
      their affiliates together with estimated fees and potential issues of
      independence; and
  7.
              review
      hiring policies for employees or former employees of the external
      auditors.
  Audit
  1.
              review
      the audit plan for the coming year with the external auditors and with
      management;
  2.
              review
      with management and the external auditors any proposed changes in major
      accounting policies, the presentation and impact of significant risks and
      uncertainties, and key estimates and judgments of management that may be
      material to financial reporting;
  3.
              query
      management and the external auditors regarding significant financial
      reporting issues during the fiscal period and the method of
      resolution;
  4.
              review
      any problems experienced by the external auditors in performing the audit,
      including any restrictions imposed by management of significant accounting
      issues in which there was a disagreement with
  management;
  5.
              review
      audited annual financial statements and quarterly financial statements
      with management and the external auditors (including disclosures under
      "Management Discussion and Analysis"),
in
  6.
              conjunction
      with the report of the external auditors and obtain explanation from
      management of all significant variances between comparative reporting
      periods; and
  7.
              review
      the auditors' report to management, containing recommendations of the
      external auditors, and management's response and subsequent remedy of any
      identified weaknesses.
  Other Duties and
Responsibilities
  1.
              The
      responsibilities, practices and duties of the Committee outlined herein
      are not intended to be comprehensive. The Board may, from time to time
      charge the Committee with the responsibility of reviewing items of a
      financial or control, risk management or reserves
  nature.
  2.
              The
      Committee shall periodically report to the Board the results of reviews
      undertaken and any associated
recommendations.
  3.
              The
      Committee shall monitor the receipt, retention and treatment of complaints
      received by the issuer regarding accounting, internal accounting controls,
      or auditing matters.
  4.
              The
      Committee shall monitor the confidential, anonymous submissions by
      employees of concerns regarding questionable accounting or auditing
      matters.