Cork Exploration Inc. announces financial, reserve and operational results for the year ended December 31, 2006



    CALGARY, March 12 /CNW/ - Cork Exploration Inc. (the "Corporation" or
"Cork") (TSX: CRK) is pleased to announce its financial, reserve and
operational results for the year ended December 31, 2006.

    
    2006 HIGHLIGHTS

                                                                   For the
                                                                    period
                                                                 February 14,
                                                  Year ended       2005 to
                                                  December 31,   December 31,
                                                     2006            2005
    -------------------------------------------------------------------------
    Daily production (boe/d)                              881             25
    Total revenues                                $15,601,796       $627,751
    Net earnings (loss)                            $1,689,987      ($553,893)
    Net earnings (loss) per share - basic               $0.04         ($0.02)
    Net earnings (loss) per share - diluted             $0.04         ($0.02)
    Funds from operations                          $9,069,299       $745,106
    Funds from operations per share -
     basic(1)                                           $0.23          $0.02
    Funds from operations per share -
     diluted(1)                                         $0.20          $0.02
    Total assets                                 $140,094,501    $43,265,379
    Working capital (net debt)(1)                ($38,747,390)   $16,938,081
    Capital additions                            $112,636,361    $16,366,964
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Non-GAAP measures


    Key highlights for the year include:

    -   Production: Exit production for 2006 averaged 2,636 boed in the last
        21 days of December with an aggregate exit productive capacity of
        4,400 boed, including approximately 500 boed of production that was
        constrained because of infrastructure bottlenecks and approximately
        1,300 boed of behind-pipe production.

    -   Drilling: 42 gross (24.7 net) wells were drilled in 2006 with
        drilling of an additional two gross (0.7 net) wells still in progress
        at December 31, 2006. The Corporation's total production success rate
        was 88%. Total capital cost of the 2006 drilling program was
        $112.6 million. Of the 44 gross wells drilled or drilling, 33 gross
        wells or 75% were drilled on a promoted basis to earn land. Capital
        expenditures include $1.9 million related to capital inventory
        purchases to be used in the 2007 capital program and $1.5 million
        related to two wells drilling over year end and site preparation
        costs for 2007 drills. As a result, the Corporation spent
        $109.1 million in 2006 to achieve its December 31, 2006 productive
        capacity of approximately 4,400 boe/d.

    -   Reserves: Ending reserves of 9,562 mboe proved plus probable at
        December 31, 2006 increased by 296% compared to 2,412 mboe proved
        plus probable at December 31, 2005.

    -   Capital efficiency: Cork achieved a competitive capital efficiency in
        2006 - particularly in light of the substantial number of promoted
        wells. Finding and development costs were $22.94 per boe (proved) and
        $17.17 per boe (proved plus probable), including future development
        capital. In 2007, the Corporation expects to focus on the drilling of
        straight-up development and exploration wells with a corresponding
        anticipated positive impact on the Corporation's 2007 finding and
        development costs.

    -   Land: Cork's land base at December 31, 2006 totaled 151 gross
        sections of developed, undeveloped and undeveloped right-to-earn land
        with an average working interest of 58.9%. This includes 40,737 acres
        of net undeveloped land including right-to-earn lands and
        represents a 142% increase over the land holdings at December 31,
        2005 of 16,810 acres of net undeveloped land.
    

    REVIEW OF OPERATIONS

    During fiscal 2006, Cork drilled 42 gross (24.7 net) wells with an
additional 2 gross (0.7 net) wells drilling over December 31, 2006. From the
Corporation's inception in February 2005 to December 31, 2006, Cork drilled or
had initiated drilling on 52 gross (29.6 net) wells. At December 31, 2006, the
Corporation had 32 gross (19.9 net) wells on production with 12 gross
(5.7 net) wells awaiting completion and tie-in.
    The following table summarizes Cork's drilling results for the periods
indicated.

    
                                                                 Period from
                                                                 February 14,
                                              Year Ended             2005 to
                                       December 31, 2006   December 31, 2005
    -------------------------------------------------------------------------
                                         Gross       Net     Gross       Net
    -------------------------------------------------------------------------
    Crude oil                                2       1.6         -         -
    Natural gas                             23      14.5         7       3.7
    Awaiting compeletion                    12       5.7         -         -
    Dry                                      5       2.9         1       0.5
    Drilling                                 2       0.7         -         -
    -------------------------------------------------------------------------
    Total                                   44      25.4         8       4.2
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    As a result of the drilling success, the Corporation's 2006 exit
production was 2,636 boe/d based upon average production from December 11 to
December 31, 2006, an increase of 779% over Cork's December 31, 2005 exit
production of 300 boe/d. Cork estimates that at December 31, 2006, its exit
production and constrained production totaled approximately 3,100 boe/d. Cork
estimated that at December 31, 2006, it had additional behind-pipe production
capacity of approximately 1,300 boe/d. In aggregate, the Corporation's
production capacity at December 31, 2006 was estimated to be approximately
4,400 boe/d. Production during the fourth quarter of 2006 was subject to
infrastructure capacity constraints. The Corporation is currently implementing
a plan to commit 2007 capital expenditures to remove such infrastructure
capacity constraints. At March 12, 2007, the Corporation's infrastructure
de-bottlenecking program was on schedule to be completed before March 31,
2007, at which point the Corporation will provide an additional operational
update.
    The following table summarizes Cork's average daily production in each
core area based on 2006 exit production using an average production from
December 11 to December 31, 2006:

    
                                                                       Total
    Core Area                                                         (boe/d)
    -------------------------------------------------------------------------
    Brazeau                                                              176
    Carrot Creek                                                       1,639
    Edson                                                                 16
    Pembina                                                              525
    West Pembina                                                         280
    -------------------------------------------------------------------------
    Total                                                              2,636
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    The Corporation's average production during 2006 is as follows:

                                                         Crude Oil
                                             Natural Gas     & NGL     Total
    Core Area                                     (mcf/d)  (bbls/d)   (boe/d)
    -------------------------------------------------------------------------
    Brazeau                                          579        25       122
    Carrot Creek                                   1,539        64       320
    Edson                                             64         2        13
    Pembina                                        1,542        73       330
    West Pembina                                     400        29        96
    -------------------------------------------------------------------------
    Total                                          4,125       193       881
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    During fiscal 2006, 33 gross wells or 75% of the 44 gross wells drilled
or drilling by Cork were on a promoted basis under related farm-in agreements.
Under the terms of these agreements, Cork was required to pay 100% of the
capital costs to drill and evaluate the wells to earn an average 62% working
interest in the related lands.
    The Corporation's total capital expenditures for fiscal 2006 were
$112.6 million. The increased capital expenditures reflected the continued
acceleration of the Corporation's drilling program, the high percentage of
promoted wells and higher than expected service costs. Of the $112.6 million
spent in 2006, $1.9 million related to capital inventory purchases to be used
in the 2007 capital program and $1.5 million related to two wells drilling
over year end and site preparation costs for 2007 drills. As a result, the
Corporation spent $109.1 million in 2006 to achieve its December 31, 2006
productive capacity of approximately 4,400 boe/d and anticipates spending
approximately $6.0 million in the first quarter of 2007 to remove
infrastructure capacity constraints and to bring online most of the
December 31, 2006 behind pipe production by March 31, 2007.

    LAND HOLDINGS

    The following table sets out Cork's land holdings as at December 31,
2006:

    
                          Total Developed,
                           Undeveloped &
                           Right to Earn      Undeveloped      Right to Earn
    -------------------------------------------------------------------------
                          Gross      Net    Gross      Net    Gross      Net
    -------------------------------------------------------------------------
    Brazeau              17,281    7,369    8,001    3,303      320      107
    Carrot Creek         14,240    9,664    2,560    1,664    5,280    3,168
    Cochrane             27,831   20,607   25,911   19,455        -        -
    Edson                 9,600    2,507    7,040    1,867        -        -
    Garrington            2,560    1,056    2,240      928        -        -
    Pembina               8,000    5,142    4,160    2,731    1,600      960
    West Pembina         17,120   10,522   11,360    6,554        -        -
    -------------------------------------------------------------------------
    Total                96,632   56,867   61,272   36,502    7,200    4,235
    -------------------------------------------------------------------------
    

    At December 31, 2006, Cork controlled 151 gross sections of developed,
undeveloped and undeveloped right-to-earn lands with an average working
interest of 59%. Cork's net undeveloped land position was approximately
40,737 net acres, including right-to-earn lands. Excluding any new farm-in
agreements, the majority of the Corporation's 2007 drilling program will be
dedicated to straight-up development and exploratory wells on currently earned
lands. In 2007, however, Cork will continue to pursue new crown and freehold
land purchases and potential farm-in agreements in its core areas.

    RESERVE INFORMATION

    Disclosure of Reserves Data

    The reserves data set forth below (the "Reserve Data") is based upon an
evaluation by GLJ Petroleum Consultants ("GLJ") with an effective date of
December 31, 2006 and dated February 28, 2007. The Reserves Data summarizes
the Corporation's crude oil, natural gas liquids and natural gas reserves and
the net present values of future net revenue for these reserves using constant
prices and costs and forecast prices and costs. The GLJ Report has been
prepared in accordance with the standards contained in the COGE Handbook and
the reserve definitions contained in NI 51-101. Cork engaged GLJ to provide an
evaluation of its proved and proved plus probable reserves and no attempt was
made to evaluate possible reserves. The estimates of reserves are subject to
judgements of future events for which actual results may vary materially.
Disclosure of the Corporation's oil and natural gas reserves will be contained
in the Annual Information Form to be filed at www.sedar.com.

    Cautionary Statements

    Boe's may be misleading, particularly if used in isolation. A Boe
conversion ratio of 1 Boe for 6 Mcf is based on an energy equivalency
conversion method primarily applicable at the burner tip and does not
represent a value equivalency at the wellhead.
    Gross reserves are Corporation's gross reserves, which are the
Corporation's working interest (operating or non-operating) share before
deduction of royalties and without including any royalty interest of the
Corporation. Net Reserves are the Corporation's working interest (operating or
non-operating) share after deduction of royalty obligations plus the
Corporation's royalty interests in reserves.
    All evaluations and reviews of future net cash flow are stated prior to
any provisions 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 estimates
of future net revenues presented in the tables below represent the fair market
value of the reserves. There is no assurance that the constant prices and
costs assumptions and forecast prices and costs assumptions will be attained
and variances could be material. The recovery and reserve estimates of our
crude oil, natural gas liquids and natural gas reserves provided herein are
estimates only and there is no guarantee that the estimated reserves will be
recovered. Actual crude oil, natural gas and natural gas liquid reserves may
be greater than or less than the estimates provided herein. For more
information as to the risks involved, see "Risk Factors" in the Corporation's
long form prospectus dated June 21, 2006. Columns may not add due to rounding.

    
    Summary of Oil and Gas Reserves

    Based on Forecast Prices and Costs(1)


                                2006                    2005
                     --------------------------------------------------------
                                       Oil
                       Oil &          Equiv.   Oil &            Oil
    As at             Liquids   Gas   (mboe)  Liquids   Gas    Equiv. Percent
     December 31,     (mbbls)  (mmcf)   (3)   (mbbls)  (mmcf)  (mboe) change
    -------------------------------------------------------------------------
    Proved(1)
      Developed
       Producing         569  10,884   2,383     155   2,208     523    356%
      Developed
       Non-Producing     484   8,546   1,908     103   2,237     476    301%
      Undeveloped        432   9,250   1,974      57     915     209    844%
    -------------------------------------------------------------------------
    Total Proved       1,485  28,680   6,265     315   5,360   1,208    419%
    -------------------------------------------------------------------------
    Probable(2)
      Producing          212   4,058     888      71   1,005     238    273%
      Nonproducing       540  11,210   2,409     211   4,530     966    149%
    -------------------------------------------------------------------------
    Total Probable       752  15,268   3,297     282   5,535   1,204    174%
    -------------------------------------------------------------------------
    Proved plus
     Probable(2)       2,237  43,948   9,562     597  10,895   2,412    296%
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) As evaluated by GLJ Petroleum Consultants in its report with an
        effective date of December 31, 2006 (actual remaining quantities
        recovered will be greater than or less than the estimated Proved
        reserves).
    (2) Probable reserves as defined by NI 51-101 are those additional
        reserves that are less certain to be recovered than Proved reserves.
        It is equally likely that the actual remaining quantities recovered
        will be greater or less than the sum of the estimated Proved +
        Probable reserves.
    (3) Using a gas to oil equivalent of 6:1


    Net Present Value of Reserves - Forecast Prices and Costs(1)

                                                Discounted at
    -------------------------------------------------------------------------
                                  NPV 0%   NPV 5%  NPV 10%  NPV 12%  NPV 15%
    As at December 31, 2006      ($000's) ($000's) ($000's) ($000's) ($000's)
    -------------------------------------------------------------------------
    Proved
      Developed Producing         75,040   60,371   51,335   48,596   45,115
      Developed Non-Producing     62,628   48,868   40,460   37,923   34,711
      Undeveloped                 52,582   38,919   30,457   27,910   24,700
    -------------------------------------------------------------------------
    Total Proved                 190,250  148,158  122,252  114,429  104,526
    Total Probable               116,262   66,374   44,454   38,934   32,595
    -------------------------------------------------------------------------
    Proved plus Probable         306,512  214,532  166,706  153,363  137,121
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Field prices have been determined using the following forecasts of
        reference crude oil and natural gas prices. For crude oil,
        adjustments are made for the historical quality and transportation
        differentials applicable to each specific property. For natural gas,
        adjustments are made for the heating value. An allowance for
        inflation was deducted in arriving at the Corporation's share of
        future net revenues.


    GLJ Petroleum Consultants Ltd. Price Forecast

                Exchange            WTI            Light Oil          Gas
                  Rate           Crude Oil            Edm.         AECO Spot
    -------------------------------------------------------------------------
                $US/$CDN          $US/bbl          $Cdn/bbl       $Cdn/mmbtu
    -------------------------------------------------------------------------
    2007          0.87             62.00             70.25              7.20
    2008          0.87             60.00             68.00              7.45
    2009          0.87             58.00             65.75              7.75
    2010          0.87             57.00             64.50              7.80
    2011          0.87             57.00             64.50              7.85
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Based on Constant Prices and Costs(1)


                                2006                    2005
                     --------------------------------------------------------
                                       Oil
                       Oil &          Equiv.   Oil &            Oil
    As at             Liquids   Gas   (mboe)  Liquids   Gas    Equiv. Percent
     December 31,     (mbbls)  (mmcf)   (3)   (mbbls)  (mmcf)  (mboe) change
    -------------------------------------------------------------------------
    Proved(1)
      Developed
       Producing         567  10,812   2,368     155   2,208     523    353%
      Developed
       Non-Producing     483   8,520   1,903     103   2,245     477    299%
      Undeveloped        434   9,290   1,982      57     915     209    848%
    -------------------------------------------------------------------------
    Total Proved       1,484  28,622   6,253     315   5,368   1,209    417%
    -------------------------------------------------------------------------
    Probable(2)
      Producing          211   4,025     882      71   1,005     238    271%
      Nonproducing       541  11,206   2,409     211   4,522     964    150%
    -------------------------------------------------------------------------
    Total Probable       752  15,231   3,291     282   5,527   1,202    174%
    -------------------------------------------------------------------------
    Proved plus
     Probable(2)       2,236  43,853   9,544     597  10,895   2,411    296%
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) As evaluated by GLJ Petroleum Consultants in its report with an
        effective date of December 31, 2006 (actual remaining quantities
        recovered will be greater than or less than the estimated Proved
        reserves).
    (2) Probable reserves as defined by NI 51-101 are those additional
        reserves that are less certain to be recovered than Proved reserves.
        It is equally likely that the actual remaining quantities recovered
        will be greater or less than the sum of the estimated Proved +
        Probable reserves.
    (3) Using a gas to oil equivalent of 6:1


    Net Present Value of Reserves - Constant Prices and Costs

                                                  Discounted at
    -------------------------------------------------------------------------
                                  NPV 0%   NPV 5%  NPV 10%  NPV 12%  NPV 15%
    As at December 31, 2006      ($000's) ($000's) ($000's) ($000's) ($000's)
    -------------------------------------------------------------------------
    Proved
      Developed Producing         59,888   49,719   43,075   41,002   38,329
      Developed Non-Producing     49,317   39,553   33,228   31,269   28,759
      Undeveloped                 38,717   29,077   22,815   20,887   18,428
    -------------------------------------------------------------------------
    Total Proved                 147,922  118,349   99,118   93,158   85,516
    Total Probable                76,862   47,325   32,861   29,022   24,502
    -------------------------------------------------------------------------
    Proved plus Probable         224,784  165,674  131,979  122,180  110,018
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Constant Price Assumptions(1)

    Natural Gas  Crude Oil     Natural Gas Liquids
    -------------------------------------------------------------------------
                  Light,      Pentanes      Butanes
                 Sweet at       Plus         Field      Inflation   Exchange
    Plant Gate   Edmonton    Field Gate      Gate         Rate        Rate
    ($Cdn/Mcf)  ($Cdn/bbl)   ($Cdn/bbl)   ($Cdn/bbl)      %/Yr.    ($US/$Cdn)
    -------------------------------------------------------------------------
       7.00        70.25        71.75        56.25          2         0.87

    (1) The constant price assumptions assume the continuance of current
        laws, regulations and operating costs in effect on the date of the
        GLJ Report. Product prices were not escalated beyond December 31,
        2006. In addition, operating and capital costs have not been
        increased on an inflationary basis.


    Reconciliation of Reserves

                                 Oil (mbbls)               NGL (mbbls)
    -------------------------------------------------------------------------
                         Proved  Probable    P+P    Proved  Probable    P+P
    -------------------------------------------------------------------------
    December 31, 2005         -       29       29      315      253      568
    Technical Revisions       -      (29)     (29)    (108)     (81)    (189)
    Discoveries              26       13       39      165       76      241
    Drilling Extensions      47       23       70      110    1,469    1,579
    Production               (1)       -       (1)     (69)       -      (69)
    -------------------------------------------------------------------------
    December 31, 2006        72       36      108      413    1,718    2,131
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


                                Gas (mmcf)           Oil Equivalent (mboe)
    -------------------------------------------------------------------------
                         Proved  Probable    P+P    Proved  Probable    P+P
    -------------------------------------------------------------------------
    December 31, 2005     5,360    5,535   10,895    1,208    1,204    2,412
    Technical Revisions  (1,020)  (1,532)  (2,552)    (277)    (366)    (643)
    Discoveries           3,274    1,755    5,029      736      382    1,118
    Drilling Extensions  22,572    9,509   32,081    4,919    2,077    6,996
    Production           (1,506)       -   (1,506)    (321)       -     (321)
    -------------------------------------------------------------------------
    December 31, 2006    28,680   15,267   43,947    6,265    3,297    9,562
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Reserve Life Index (RLI)

    The Corporation's RLI, on a proved and probable basis and using December
2006 volumes, is 7.4 years for crude oil and liquids and 7.8 for natural gas,
resulting in a combined RLI of 7.7 years.

    Finding and Development Costs

                                                         2006           2005
    -------------------------------------------------------------------------
    Exploration and Development Costs             109,068,544(1)  16,367,000
    Future Capital
      Proven                                       17,832,000      3,559,000
      Probable                                     26,579,000      7,404,000
    Finding and Development costs per BOE(2)
      Proved                                           $22.94         $16.39
      Proved plus Probable                             $17.17          $9.82
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Excludes $3.6 million of capital inventory and costs related to wells
        drilling over year end included in future capital
    (2) Including future development costs
    


    SUMMARY MANAGEMENT DISCUSSION & ANALYSIS

    March 8, 2007

    The following management's discussion and analysis ("MD&A") of the
financial results for Cork Exploration Inc. ("Cork" or the "Corporation")
should be read in conjunction with the accompanying audited financial
statements and related notes for the year ended December 31, 2006 and the
period from incorporation on February 14, 2005 to December 31, 2005. The
financial data contained herein has been prepared in accordance with Canadian
generally accepted accounting principles ("GAAP"). The reporting and
measurement currency is the Canadian dollar.

    Forward-Looking Statements

    Certain statements that appear in the Review of Operations, Reserve
Information, MD&A and elsewhere in this document may constitute
"forward-looking information" or "forward-looking statements" which involve
known and unknown risks, uncertainties and other factors which may cause the
actual results, performance or achievements of the Corporation, or industry
results, to be materially different from any future results, performance or
achievements expressed or implied by such forward-looking information. When
used in the Review of Operations, Reserve Information, MD&A and elsewhere in
this document, such information uses words such as "may", "will", "should",
"estimated", "expected", "believe", "planned", "future", "anticipated",
"potential", "continued" or the negative of these terms or other comparable
terminology. This information reflects the Corporation's current expectations
regarding future events and operating performance and speaks only as of the
date of the Review of Operations, Reserve Information and MD&A. All statements
other than statements of historical fact may be forward-looking statements.
Forward-looking information involves significant risks and uncertainties,
should not be read as a guarantee of future performance or results, and will
not necessarily be an accurate indication of whether or not such results will
be achieved. A number of factors could cause actual results to differ
materially from the results discussed in the forward-looking information,
including, but not limited to, the factors discussed below. Although the
forward-looking information contained in the Review of Operations, Reserve
Information, and MD&A is based upon what management of the Corporation
believes are reasonable assumptions, the Corporation cannot assure investors
that actual results will be consistent with this forward-looking information.
This forward-looking information is provided as of the date of the Review of
Operations, Reserve Information and MD&A, and, subject to applicable
securities laws, the Corporation assumes no obligation to update or revise
such information to reflect new events or circumstances.
    The Corporation's actual results could differ materially from those
anticipated in the forward-looking information as a result of several factors,
including, but not limited to, the following: general economic conditions in
Canada, the United States and internationally; volatility in market prices for
oil, natural gas and natural gas liquids; competition; liabilities and risks,
including environmental liabilities and risks, inherent in oil and natural gas
operations; sourcing, pricing and availability of materials, equipment,
suppliers, drilling services, facilities, and skilled management, technical
and field personnel; ability to integrate technological advances and match
advances of Cork's competitors; availability of capital; stock market
volatility and market valuations; failure to obtain industry partner and third
party consent and approvals (i.e. farm-in operations, joint ventures, etc);
uncertainties in weather and temperature affecting fluctuations in foreign
exchange rate and interest rates, duration of oil and gas operations, drilling
and activities that can be completed; unanticipated operating events or
regulatory restrictions which can reduce production or cause production to be
shut in or delayed; changes in legislation and the regulatory environment,
including uncertainties with respect to implementing the Kyoto Protocol; and
the other factors considered under "Risk Factors" in the Corporation's final
long form prospectus which is available on the Corporation's SEDAR profile at
www.sedar.com.

    Comparability of Prior Period Results

    The Corporation was incorporated on February 14, 2005 and commenced
operations on April 1, 2005. As such, the period from February 14 to
December 31, 2005 has been provided for comparison purposes.

    Non-GAAP Measures

    This MD&A contains the terms "funds from operations" and "netbacks" which
are not defined under GAAP. The Corporation uses these measures to help
evaluate its performance. Management considers netbacks an important measure
as it demonstrates Cork's profitability relative to current commodity prices.
Management uses funds from operations to analyze operating performance and
leverage and considers funds from operations to be a key measure as it
demonstrates the Corporation's ability to generate the cash necessary to fund
future capital investments and to repay debt. Funds from operations should not
be considered an alternative to, or more meaningful than, cash flow from
operating activities as determined in accordance with GAAP as an indicator of
the Corporation's performance. Therefore, references to funds from operations
or funds from operations per share (basic and diluted) may not be comparable
with the calculation of similar measures for other entities. The
reconciliation between funds from operations and cash flow from operations can
be found in the statements of cash flow in the audited financial statements.
Funds from operations per share is calculated using the basic and diluted
weighted average number of shares for the period.

    Boe Presentation

    Certain disclosure may be presented on a per barrel of oil equivalent
(boe) basis. Boe's may be misleading, particularly if used in isolation. A boe
conversion ratio of 6 thousand cubic feet (mcf) to 1 barrel (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.

    
    RESULTS OF OPERATIONS

    Petroleum and Natural Gas Production

                                                                     For the
                                                                      period
                                                                 February 14,
                                                    Year ended       2005 to
                                                  December 31,   December 31,
    Daily Production                                     2006           2005
    -------------------------------------------------------------------------
    Natural gas (mcf/d)                                 4,125            118
    Oil & NGLs (bbls/d)                                   193              5
    -------------------------------------------------------------------------
    Total (boe/d)                                         881             25
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Production for the year ended December 31, 2006 averaged 881 boe/d.
Production increased substantially compared to the 25 boe/d recorded in the
prior period due to the success of the 2005/2006 capital investment program
which commenced in the third quarter of 2005. Gas production comprised
approximately 78% of total production with oil and natural gas liquids (NGLs)
representing the remaining 22% to oil and natural gas liquids. Substantially
all of the oil and NGL production is comprised of natural gas liquids.
    The following is a summary of Cork's daily production for the quarterly
periods indicated:

    
                                         2006                       2005
                         ----------------------------------------------------
    Daily Production        Q4       Q3       Q2       Q1       Q4       Q3
    -------------------------------------------------------------------------
    Natural gas (mcf/d)   7,580    3,709    3,418    1,737      412        -
    Oil & NGLs (bbls/d)     426      112      160       73       16        1
    -------------------------------------------------------------------------
    Total (boe/d)         1,689      730      729      364       85        1
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Marketing

    Cork's revenues from the sale of gas, natural gas liquids and oil are
exposed to price fluctuations of the related commodity. The Corporation
monitors the impact of commodity price exposure and may, from time to time,
implement hedging strategies to mitigate such price risk. The objective of
these hedging strategies is to reduce the Corporation's risk exposure to
changes in cash flow resulting from uncertainty or changes in commodity
prices. The Corporation may utilize derivative instruments from time to time
such as swaps, puts or collars to implement these hedging strategies.
    On July 28, 2006, Cork entered into a derivative instrument to hedge
against price fluctuations on a portion of its future natural gas production.
Following is a summary of all derivative contracts in place as at December 31,
2006:

    
      Natural Gas      Volume     Pricing Point   Strike Price      Term
    -------------------------------------------------------------------------
    Costless collar   3000 gj/d       AECO         Cdn $7.00 -   Sept 1/06 -
                                                   $10.60        Mar 31/07
    -------------------------------------------------------------------------
    

    The impact of the derivative instrument was a realized gain of $421,967
and an unrealized gain of $181,849 for the year ended December 31, 2006. There
were no comparative amounts in the prior period.
    On January 23, 2007, the Corporation entered into a hedge against price
movements on a portion of its future natural gas production. The Corporation
has hedged 4,500 gj/d of natural gas production for the period of April 1 to
October 31, 2007 via a swap on AECO natural gas price for $7.25/gj.

    Revenue

    The Corporation realized the following revenues and related commodity
prices during the year:

    
                                                                   For the
                                                                    period
                                                                 February 14,
                                                  Year ended       2005 to
                                                  December 31,   December 31,
                                                     2006            2005
    -------------------------------------------------------------------------
    Revenues By Product ($)
    Natural gas sales                              10,880,883        512,440
    Crude oil and NGLs                              4,298,946        115,311
    -------------------------------------------------------------------------
    Total petroleum and natural gas sales          15,179,829        627,751
    Realized gains on financial derivative
     instruments                                      421,967              -
    -------------------------------------------------------------------------
    Total petroleum and natural gas sales
     and hedge revenue                             15,601,796        627,751
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Average Realized Prices
    Natural gas ($/mcf)                                 $7.51         $13.53
    Crude oil and NGLs ($/bbl)                         $60.92         $66.46
    -------------------------------------------------------------------------
    Total per boe ($/boe)                              $48.52         $78.03
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Revenues for the year ended December 31, 2006, including realized gains
from financial derivative instruments, increased to $15,601,796 from $627,751
in the prior period as a result of significant production increases. During
the period from February 14 to December 31, 2005, Cork was involved in
exploration and drilling activities with production commencing in December
2005.
    The average sales price for natural gas is at a premium of 15% to 20% to
the AECO-C spot price due to the high energy content of the Corporation's
natural gas production. Except to the extent that the Corporation has hedged
exposure to gas price volatility using financial derivative instruments as
stated in the Marketing section above, all of the Corporation's production is
sold on the spot market. Therefore both the historical prices received and the
expected future prices fluctuate with prevailing market prices of crude oil
and natural gas. The significant decline in realized natural gas price in 2006
reflects softening of the natural gas market in the last half of 2006 due to
market concerns over higher natural gas storage levels and the prospect of a
warmer than normal winter. The average realized prices for crude oil and NGLs
decreased in the current year due to the proportion of crude oil and NGL
production. During 2005, crude oil and NGL production consisted of a higher
proportion of higher priced crude oil. During 2006, this proportion change and
consisted mainly of natural gas liquids.

    
    Royalties

                                                                   For the
                                                                    period
                                                                 February 14,
                                                  Year ended       2005 to
                                                  December 31,   December 31,
                                                     2006            2005
    -------------------------------------------------------------------------
    Royalties ($)
      Crown (net of ARTC)                           3,062,128        116,510
      Freehold and overriding                          70,305          2,302
    -------------------------------------------------------------------------
    Total royalties                                 3,132,433        118,812
    -------------------------------------------------------------------------
    Total royalties ($/boe)                             $9.74         $14.77
    Average royalty rate (%)                            20.1%          18.9%
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Royalty expense consists of Crown royalties paid to the Alberta
Government and overriding royalties paid to royalty owners. For the year ended
December 31, 2006, royalties net of Alberta Royalty Tax Credits (ARTC) were
$3,132,433 compared to $118,812 for the prior period. The increase in royalty
expense is due to an increase in petroleum and natural gas production and
associated revenues. The royalty rate for the year ended December 31, 2006 was
20.1% compared to 18.9% for the period from February 14 to December 31, 2005.
The slightly lower royalty rate in the prior period is due to the royalty
holiday program. There were only two producing wells as at December 31, 2005,
of which one was granted a royalty holiday.
    In September 2006, the Alberta Government announced the cessation of the
ARTC program effective January 1, 2007. The impact of this change to Cork is
expected to result in an increase in royalty expenses of $500,000 in 2007.

    
    Operating Expenses

                                                                   For the
                                                                    period
                                                                 February 14,
                                                  Year ended       2005 to
                                                  December 31,   December 31,
                                                     2006            2005
    -------------------------------------------------------------------------
    Operating expenses ($)                          1,992,953         39,031
    Operating expenses per boe                          $6.20          $4.85
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Net operating expenses were $1,992,953 for the year ended December 31,
2006 compared to $39,031 in 2005. Total operating costs increased due to
increased production. Operating expenses per boe were $6.20 per boe for the
year ended December 31, 2006 compared to $4.85 per boe for the period from
February 14, 2005 to December 31, 2005. The increase in operating costs per
boe is due primarily to start-up costs for wells being brought on production
and higher costs associated with processing contracts for the facilities where
a significant amount of the Corporation's production is received. Operating
expenses for 2007 are expected to decrease as a result of a larger ongoing
production base to lessen the impact of one-time costs for new wells and the
infrastructure de-bottlenecking program allowing Cork to send more gas to a
lower fee facility.

    
    Transportation Charges

                                                                   For the
                                                                    period
                                                                 February 14,
                                                  Year ended       2005 to
                                                  December 31,   December 31,
                                                     2006            2005
    -------------------------------------------------------------------------
    Transportation expenses ($)                       382,582         11,519
    Transportation expense per boe                      $1.19          $1.43
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Transportation charges relate primarily to the cost of transporting
natural gas on natural gas pipelines and to a lesser degree for clean oil
trucking charges. An increase in production volumes caused an increase in
transportation costs to $382,582 for the year ended December 31, 2006 from
$11,519 for the period from February 14, 2005 to December 31, 2005. As
transportation charges vary by operating area, transportation charges per boe
decreased in the current year primarily due to the changes in proportion of
production from the different areas as more wells came on production.

    Netbacks

    The following is a summary of the operating netbacks for the period:

    
                                                                   For the
                                                                    period
                                                                 February 14,
                                                  Year ended       2005 to
                                                  December 31,   December 31,
    $/boe                                            2006            2005
    -------------------------------------------------------------------------
    Revenues                                            48.52          78.03
    Royalties                                           (9.74)        (14.77)
    Operating expenses                                  (6.20)         (4.85)
    Transportation expenses                             (1.19)         (1.43)
    -------------------------------------------------------------------------
    Operating netback ($/boe)                           31.39          56.98
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    The operating netback decreased to $31.39 per boe for the year ended
December 31, 2006 from $56.98 per boe in 2005. The decrease in operating
netback is due primarily to the reduction in average sales price. This is
consistent with the decrease in benchmark AECO natural gas prices in 2006
compared to 2005.

    
    General and Administrative Expenses

                                                                   For the
                                                                    period
                                                                 February 14,
                                                  Year ended       2005 to
                                                  December 31,   December 31,
    $                                                2006            2005
    -------------------------------------------------------------------------
    General and administrative expenses (gross)     3,341,262      1,014,044
    Capitalized general and administrative
     expenses                                      (1,375,424)      (597,251)
    Overhead recoveries                              (746,746)      (186,877)
    -------------------------------------------------------------------------
    General and administrative expenses (net)       1,219,092        229,916
    -------------------------------------------------------------------------
    General and administrative expenses per boe         $3.79         $28.58
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    General and administrative expenses ("G&A") net of recoveries and
capitalization for the year ended December 31, 2006 were $1,219,092 compared
to $229,916 for the period from February 14 to December 31, 2005. This
increase reflects a full year of expenses along with increased activity in the
Corporation in 2006, resulting in more staff and associated costs. As well,
the Corporation incurred one-time costs associated with taking the Corporation
public in 2006, including costs to implement corporate governance measures and
develop infrastructure for a public corporation. The higher gross G&A was
partially offset by higher recoveries driven by higher capital spending during
2006 versus the prior period.
    G&A per boe decreased to $3.79 per boe for the year ended December 31,
2006 from $28.58 per boe for the period from February 14 to December 31, 2005.
This decrease reflects the significant increase in production levels since
2005 partially offset by higher G&A costs. At start-up, exploration companies
are burdened with start-up costs and no production resulting in higher G&A per
boe until production increases. G&A expense per boe is expected to decrease in
the future as a result of anticipated increased production.

    
    Stock-Based Compensation

                                                                   For the
                                                                    period
                                                                 February 14,
                                                  Year ended       2005 to
                                                  December 31,   December 31,
    $                                                2006            2005
    -------------------------------------------------------------------------
    Stock-based compensation expense                  533,254        925,622
    Capitalized stock-based compensation            1,535,259      1,779,378
    -------------------------------------------------------------------------
    Total stock-based compensation                  2,068,513      2,705,000
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    During the year ended December 31, 2006, the Corporation expensed
$533,254 and capitalized $1,535,259 (including tax effect of $961,245) related
to the outstanding stock options. During the period from February 14 to
December 31, 2005, the Corporation expensed $925,622 and capitalized
$1,779,378. The decrease in stock-based compensation in 2006 is due to the
performance warrants which were issued and vested during 2005. No performance
warrants were issued in 2006.

    
    Depletion, Depreciation and Accretion

                                                                   For the
                                                                    period
                                                                 February 14,
                                                  Year ended       2005 to
                                                  December 31,   December 31,
    $                                                2006            2005
    -------------------------------------------------------------------------
    Depletion                                       5,937,487         99,457
    Depreciation                                       20,940          8,147
    Accretion                                          48,283            135
    -------------------------------------------------------------------------
    Total depletion, depreciation and accretion     6,006,710        107,739
    -------------------------------------------------------------------------
    DD&A per boe                                       $18.68         $13.39
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Depletion, depreciation and accretion ("DD&A") increased to $6,006,710
for the year ended December 31, 2006 compared to $107,739 for the period from
February 14 to December 31, 2005. The increase in the total expense
corresponds to a significant increase in production as there was minimal
production in 2005. On a boe basis, DD&A expense for 2006 was $18.68 per boe
compared to $13.39 per boe in 2005. The increase reflects higher finding costs
due to the significant number of promoted wells in 2006, higher-than-expected
drilling and completion costs and an industry-wide increase in service costs.

    Impairment test

    The company performed a full cost impairment test at December 31, 2006 to
assess the recoverability of its petroleum and natural gas interests. As at
December 31, 2006, there was no impairment of the petroleum and natural gas
assets.

    Income Taxes

    The provision for future income taxes for the year ended December 31,
2006 was an expense of $1,021,197 for an overall tax rate of 37.7%. For the
period from February 14 to December 31, 2005, the Corporation recorded an
income tax expense of $265,638. The Corporation does not expect to incur cash
income taxes in 2007 based on available tax pools, current commodity prices
and planned capital expenditures for 2007.
    On November 8, 2006, the Corporation issued, on a private placement,
bought deal basis, 3,334,000 flow-through common shares at an issue price of
$4.50 per flow-through common share for aggregate gross proceeds of
$15,003,000. The Corporation is committed to spend the $15,003,000 on
exploration expenditures and renounce the tax deductions related to such
expenditures to the holders of the flow-through shares. As of December 31,
2006, an estimated $6.8 million of qualifying expenditures had been spent. The
remaining $8.2 million will be spent throughout 2007 under the Canada Revenue
Agency's defined "lookback" rules.
    On February 20, 2007, the Corporation issued, on a private placement,
bought deal basis, an aggregate of 3,335,000 flow-through common shares at
$4.80 per flow-through common share for aggregate gross proceeds of
$16,008,000. Proceeds from the issuance of the flow-through common shares will
be used to fund the Corporation's 2007 exploration and development program.
Canadian exploration expenses in the amount of the gross proceeds from the
offering will be renounced to subscribers of the flow-through common shares
effective on or before December 31, 2007. Under the look-back rule, the
Corporation is required to incur all related expenditures by December 31,
2008.
    The Corporation has approximately $122.4 million in tax pools to shelter
taxable income in future years. Of this amount, $6.8 million of CEE costs were
incurred after November 8, 2006 and will be renounced to flow-through share
holders. The tax pools are comprised of the following:

    
                                                                   For the
                                                                    period
                                                                 February 14,
                                                  Year ended       2005 to
                                                  December 31,   December 31,
    $                                                2006            2005
    -------------------------------------------------------------------------
    Canadian Exploration Expense                   51,713,920      6,257,000
    Canadian Development Expense                   42,251,094        828,000
    Canadian Oil and Gas Property Expense           5,872,385      4,640,000
    Undepreciated Capital Cost                     18,730,552      1,618,000
    Share issue costs                               3,868,916      1,552,000
    Non-capital loss carry forward                          -      1,045,000
    Alberta attributed royalty income deduction             -        161,000
    -------------------------------------------------------------------------
    Total pools, losses and share issue costs     122,436,867     16,101,000
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Net Earnings and Funds From Operations

    Net earnings were $1,689,987 for the year ended December 31, 2006
compared to a net loss of $553,893 during the period from February 14 to
December 31, 2005. Net earnings increased over the prior period reflecting a
full year of operations in 2006 along with an increase in production. In
addition, Cork realized gains on financial derivative instruments in 2006 with
no comparative amount in 2005. On a per boe basis, net earnings increased to
$5.25 in 2006 from a loss of $68.85 in the prior period.
    Funds from operations increased to $9,069,299 for the year ended
December 31, 2006 compared to $745,106 during the period from February 14 to
December 31, 2005. The increase in funds from operations is due primarily to
the increase in production volumes resulting from the capital program
commencing in the third quarter of 2005. On a per boe basis funds from
operations decreased to $28.20 in the current year from $92.62 in the prior
period. The prior period amounts do not serve as an adequate basis for
comparison as the operations of the company were in the start-up phase with
minimal production. The Corporations' capital program commenced in the third
quarter of 2005 and required significant cash flows therefore reducing the
amount of cash available for investment in the current year.

    
                                                                   For the
                                                                    period
                                                                 February 14,
                                                  Year ended       2005 to
                                                  December 31,   December 31,
    ($/boe)                                          2006            2005
    -------------------------------------------------------------------------
    Petroleum and natural gas revenues                  48.52          78.03
    Royalties                                           (9.74)        (14.77)
    Interest income                                      0.93          64.22
    -------------------------------------------------------------------------
                                                        39.71         127.48
    Operating expenses                                  (6.20)         (4.85)
    Transportation expenses                             (1.19)         (1.43)
    -------------------------------------------------------------------------
                                                        (7.39)         (6.28)
    General and administrative expenses                 (3.79)        (28.58)
    Interest and financing expenses                     (0.33)             -
    Asset retirement expenditures                           -              -
    Current taxes                                           -              -
    -------------------------------------------------------------------------
    Funds from operations                               28.20          92.62

    Unrealized hedging income                            0.57              -
    Stock based compensation expense                    (1.66)       (115.06)
    Depletion, depreciation and accretion expenses     (18.68)        (13.39)
    -------------------------------------------------------------------------
    Earnings before taxes                                8.43         (35.83)
    Future income tax expense                           (3.18)        (33.02)
    -------------------------------------------------------------------------
    Net earnings                                         5.25         (68.85)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    Capital Expenditures

                                                                   For the
                                                                    period
                                                                 February 14,
                                                  Year ended       2005 to
                                                  December 31,   December 31,
    $                                                2006            2005
    -------------------------------------------------------------------------
    Drilling and completions                       87,717,544      9,048,543
    Equipment and facilities                       20,014,591      1,818,997
    Land and maintenance                            2,076,076      4,507,059
    Capitalized G&A                                 1,375,424        597,251
    Seismic                                         1,452,726        395,114
    -------------------------------------------------------------------------
    Total net capital investment                  112,636,361     16,366,964
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    During 2006, the Corporation invested approximately $87,717,544 in
drilling and completions (2005 - $9,048,543), $20,014,591 on equipment and
facilities (2005 - $1,818,997), $2,076,076 on land acquisitions (2005 -
$4,507,059), $1,375,424 on capitalized G&A (2005 - $597,251) and $1,452,726 on
seismic assets (2005 - $395,114). Total capital investment for 2006 was
$112,636,361 compared to $16,366,964 in 2005. The increased capital investment
reflects increased exploration activities by the Corporation and the expanded
capital program in 2006 with the drilling of 44 gross (25.4 net) wells.
    Of the $112,636,361 spent in 2006, $1.9 million related to capital
inventory purchases to be used in the 2007 capital program and $1.5 million
related to two wells drilling over year end and site preparation costs for
2007 drills. As a result, the Corporation spent $109.1 million in 2006 to
achieve its December 31, 2006 productive capacity of approximately 4,400 boe/d
and anticipate spending approximately $6.0 million in the first quarter of
2007 to remove infrastructure capacity constraints and to bring on the
majority of the December 31, 2006 behind pipe production by March 31, 2007.

    LIQUIDITY AND CAPITAL RE

SOURCES Share Capital For the period February 14, Year ended 2005 to December 31, December 31, 2006 2005 ------------------------------------------------------------------------- Common shares Weighted average outstanding common shares Basic 39,830,670 25,901,870 Diluted 44,459,585 25,901,870 Outstanding securities at December 31, Common shares 47,589,011 34,500,001 Common share options 3,133,333 450,000 Common share warrants 5,984,990 6,900,000 ------------------------------------------------------------------------- Diluted common shares outstanding 56,707,334 41,850,001 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Outstanding securities at March 8, 2007 Common shares 51,015,677 Common share options 3,846,667 Common share warrants 5,909,990 ------------------------------------------------------------------------- Diluted common shares outstanding 60,772,334 ------------------------------------------------------------------------- ------------------------------------------------------------------------- As at December 31, 2006, Cork had 47,589,011 shares outstanding, (March 8, 2007 - 51,015,677 shares outstanding). The authorized capital of the Corporation consists of an unlimited number of common shares and an unlimited number of preferred shares. On February 14, 2005 the Corporation issued one common share for total proceeds of $1.00 upon incorporation. On May 5, 2005, pursuant to the private placement, the Corporation issued 34,500,000 common shares, including, 1,455,000 flow-through shares, at an issue price of $1.00 per common share for gross proceeds of $34,500,000. Concurrent with the private placement, the Corporation issued performance warrants to management, directors and employees to purchase up to 6,900,000 common shares. Each performance warrant entitles the holder to acquire one common share at a price of $1.00 until May 5, 2010 subject to certain vesting provisions. As of December 31, 2005, all performance warrants became fully vested. On June 28, 2006, the Corporation issued 8,750,000 common shares at a price of $4.00 per share for gross proceeds of $35,000,000. On November 8, 2006, the Corporation issued, on a private placement, bought deal basis, 3,334,000 flow-through common shares at an issue price of $4.50 per flow-through common share for aggregate gross proceeds of $15,003,000. Proceeds from the issuance of the flow-through common shares were used to fund the Corporation's 2006 and 2007 exploration and development program. Canadian exploration expenses in the amount of the gross proceeds from the offering were renounced to subscribers of the flow-through common shares effective December 31, 2006 using the look-back rule. Under the look- back rule, the Corporation is required to incur all related expenditures by December 31, 2007. On February 20, 2007, the Corporation issued, on a private placement, bought deal basis, an aggregate of 3,335,000 flow-through common shares at $4.80 per flow-through common share for aggregate gross proceeds of $16,008,000. Proceeds from the issuance of the flow-through common shares will be used to fund the Corporation's 2007 exploration and development program. Canadian exploration expenses in the amount of the gross proceeds from the offering will be renounced to subscribers of the flow-through common shares effective on or before December 31, 2007. Under the look-back rule, the Corporation is required to incur all related expenditures by December 31, 2008. The Corporation created an incentive stock option plan dated effective April 26, 2005 which provided that the Board of Directors may from time to time, at its discretion, grant to directors, officers, employees and certain consultants to the Corporation, non-transferable options to purchase common shares. The maximum number of Common Shares that may be reserved for issuance pursuant to all other equity based compensation arrangements of the Corporation is 10% of the issued and outstanding Common Shares of the Corporation. As at December 31, 2006, there were 3,133,333 stock options outstanding and therefore, based on the issued Common Shares of the Corporation as at December 31, 2006, 1,140,001 Common Shares remained available for grant to eligible Optionees. On March 8, 2007, the Board of Directors approved the granting of an additional 730,000 options to directors, employees and insiders of the Corporation. Bank Facility At December 31, 2006, the Corporation had a $30 million demand revolving operating credit facility agreement with a Canadian chartered bank. The credit facility is subject to periodic review and was collateralized by a $60 million demand floating charge debenture over all of the assets of the Corporation. As at December 31, 2006, $16.9 million had been drawn under the credit facility. On January 29, 2007, the Corporation increased its facility to $33.0 million. On February 16, 2007, the Corporation entered into a commitment letter to replace its $33 million credit facility with a $45 million credit facility from another Canadian chartered bank. The credit facility provides that advances may be made by way of direct advances or bankers acceptances. Direct advances bear interest at the bank's prime lending rate and banker's acceptances bear interest at the applicable banker's acceptance rate plus 100 basis points. Under the terms of the credit facility, funded debt to cash flow, calculated on a rolling four quarter basis is to be maintained at all times at 3.5:1 or lower. As at the quarter ending June 30, 2007 and thereafter, the ratio is to be maintained at all times at 3.0:1 or lower. The cash flow to interest expense, calculated on a rolling four quarter basis, is not to be less than 2.5:1. The credit facility is collateralized by a $100 million demand floating charge debenture over all of the assets of the Corporation. Net Working Capital Deficiency The Corporation's working capital deficit increased to $38,747,390 as at December 31, 2006 compared to working capital of $16,938,081 at December 31, 2005. The change in working capital during 2006 is due to expenditures on the 2006 capital program. The working capital deficiency is comprised of accounts payable and accrued liabilities of $35,124,923 and accounts receivable, prepaid expenses and financial derivative instruments of $13,325,849. Accounts receivable consist mainly of monthly revenue which is typically collected on the 25th day of the month following the month of production as well as joint venture receivables from partners with whom the Corporation conducts joint operations. Accounts payable and accrued liabilities consist of payments owing for capital, operating and general and administrative activities. These invoices are processed within the Corporation's normal payment period. The capital intensive nature of the Corporation's activities may create situations of a working capital deficiency. The Corporation actively manages its capital spending program by monitoring forecasted production and commodity prices and resulting funds from operations. In the event that circumstances affect funds from operations in a detrimental way, the Corporation is capable of reducing capital activity levels or securing alternative financing sources. Investment Program Funding For the period February 14, Year ended 2005 to December 31, December 31, $ 2006 2005 ------------------------------------------------------------------------- Cash and cash equivalents, beginning of period 17,938,193 - Add: ---- Funds from operations 9,069,299 745,106 Change in non cash working capital 20,980,811 1,000,112 Proceeds from issue of share capital (net of share issue costs) 46,621,899 32,559,939 Proceeds from exercise of stock options and warrants 1,077,843 - Less: ----- Cash and cash equivalents (bank debt), end of period (16,948,316) 17,938,193 ------------------------------------------------------------------------- Capital expenditures during the period 112,636,361 16,366,964 ------------------------------------------------------------------------- ------------------------------------------------------------------------- The Corporation's 2006 capital program was funded by the funds from operations, the credit facility and two equity offerings during the year. On June 28, 2006, the Corporation issued 8,750,000 common shares in the initial public offering at a price of $4.00 per common share resulting in gross proceeds of $35,000,000 ($32,533,304 net of issuance costs). On November 8, 2006, the Corporation issued, on a private placement, bought deal basis, 3,334,000 flow-through common shares at a price of $4.50 per flow-through common share for gross proceeds of $15,003,000 ($14,088,596 net of share issuance costs). The 2007 capital program is anticipated to be $63 million and will be funded through a combination of cash flow from operations, proceeds from flow- through share issuance and bank debt. Cork currently targets a 2007 average debt to operational cash flow ratio not to exceed 1:1. Cork is committed to maintaining a strong balance sheet to minimize exposure to volatile product prices and to maximize its ability to participate in opportunities that arise both internally and from industry partners. As at December 31, 2006, the Corporation had total debt of $16,948,316 (2005 - $nil) and a working capital deficit of $38,747,390 compared to working capital of $16,938,081 at December 31, 2005. The ratio of total net debt as at December 31, 2006 to fourth quarter 2006 annualized funds from operations was 2.9:1. Giving effect to the funds from the flow-through share issue on February 20, 2007, this ratio is 2.0:1. The net debt will return to the target range as more production comes on line in March 2007 when capacity constraints are removed. RELATED PARTY TRANSACTIONS The Corporation had the following related party transactions: a) A company controlled by one of the directors of the Corporation provides engineering consulting services to the Corporation. The amounts incurred for consulting services for 2006 were $51,622 (2005 - $23,355). b) The Corporation used the services of a law firm of which one of its partners became a Director of the Corporation in October, 2005. During 2006, the Corporation incurred $245,371 (2005 - $106,742) for services provided by the firm related to the Corporation's initial public offering and prospectus and general corporate matters. All related party transactions are in the normal course of operations and have been measured at the agreed to exchange amounts, which are the amounts of consideration established and agreed to by the related parties and which are similar to those negotiated with third parties. CONTRACTUAL OBLIGATIONS AND COMMITMENTS The Corporation leases office space under an agreement which expires in June, 2010. The minimum lease and operating payments required under the lease are $199,903 for each of 2007, 2008 and 2009 and $99,952 for 2010. OFF-BALANCE SHEET ARRANGEMENTS The Corporation does not have any special purpose entities nor is it a party to any arrangements that would be excluded from the balance sheet. OUTLOOK In 2007, excluding any new farm-in agreements, Cork expects to transition from the exploration and land earning phase of the Corporation to the drilling of straight-up development and exploratory wells on currently earned lands. Cork's initial focus in 2007 will be to complete the infrastructure de- bottlenecking program and to tie-in the estimated 1,300 boe/d behind pipe production by the end of the first quarter of 2007, while directing its drilling efforts in the first quarter of 2007 to areas not affected by these infrastructure capacity constraints. Upon removal of the infrastructure bottleneck, Cork intends to resume drilling activity in the affected areas. The Corporation expects a normal decrease in drilling activity in the second quarter of 2007 due to spring break-up and anticipates a return to normal drilling levels in the third and fourth quarters of 2007. During the second quarter of 2007, the Corporation intends to utilize cash-flow from operations to pay down existing bank debt. Cork has budgeted to drill 37 gross (22.3 net wells) in 2007 on a capital budget of $63 million. The Corporation expects to exit 2007 with production between approximately 5,000 boe/d and 5,500 boe/d, depending upon, among other factors, the timing of third party tie-ins, weather and other related risks. Average production for 2007 is expected to be between approximately 4,000 boe/d and 4,400 boe/d, reflecting the impact of first quarter infrastructure capacity constraints and the aforementioned tie- in, weather and other related risks. QUARTERLY FINANCIAL SUMMARY The Corporation was incorporated on February 14, 2005 and commenced operations on April 1, 2005. Production did not commence until the third quarter of 2005, and as such only the last seven quarters have been provided for comparison purposes. Certain prior quarter amounts have been reclassified to conform to current quarter presentation. ---------------------------------------------------- 2006 ---------------------------------------------------- Q4 Q3 Q2 Q1 ---------------------------------------------------- Operations Production Natural gas (mcf/d) 7,580 3,709 3,418 1,737 Oil & NGL (bbls/d) 426 112 160 73 Total production (boe/d) 1,689 730 729 364 Average realized price Natural gas ($/mcf) $7.81 $7.16 $6.70 $8.50 NGL ($/bbl) $55.09 $64.13 $72.38 $65.35 Total per boe ($/boe) $48.94 $46.20 $47.25 $53.88 Netback Royalties ($/boe) ($9.63) ($7.04) ($11.71) ($11.76) Operating expenses ($/boe) ($6.68) ($5.94) ($5.68) ($5.46) Transportation expenses ($/boe) ($1.30) ($1.20) ($0.71) ($1.62) Operating netback ($/boe) $31.33 $32.02 $29.15 $35.05 Depletion, depreciation & accretion ($/boe) ($22.45) ($14.50) ($16.49) ($13.77) General & administrative expenses ($/boe) ($2.48) ($3.50) (6.46) ($5.19) ------------------------------------------------------------------------- Financial ($) Petroleum and natural gas revenue 7,605,027 3,103,658 3,135,596 1,757,515 Royalties (1,496,714) (473,159) (777,021) (385,539) Operating expenses (1,038,236) (398,957) (376,850) (178,910) Transportation expenses (201,808) (80,594) (47,394) (52,786) Depletion, depreciation & accretion (3,489,106) (974,140) (1,094,383) (449,081) General and administrative expenses (385,541) (234,923) (428,630) (169,998) Net earnings (loss) 118,510 1,267,070 16,413 287,994 Per share basic - $0.03 - $0.01 Per share diluted - $0.03 - $0.01 Funds from (used in) operations 4,454,516 2,073,756 1,474,602 1,066,425 Per share basic $0.10 $0.05 $0.04 $0.03 Per share diluted $0.09 $0.04 $0.04 $0.03 ------------------------------------------------------------------------- Assets ($) Total assets 140,094,501 96,665,274 90,615,173 58,362,268 Capital additions 43,657,310 30,030,009 14,794,155 24,154,887 Working capital (net debt) (38,747,390) (13,657,738) 13,543,303 (6,150,381) ------------------------------------------------------------------------- --------------------------------------- 2005 --------------------------------------- Q4 Q3 Q2 --------------------------------------- Operations. Production Natural gas (mcf/d) 412 - - Oil & NGL (bbls/d) 16 1 1 Total production (boe/d) 85 1 1 Average realized price Natural gas ($/mcf) $13.53 - - NGL ($/bbl) $67.06 $55.00 $55.00 Total per boe ($/boe) $78.41 $55.00 $55.00 Netback Royalties ($/boe) ($14.90) ($9.84) - Operating expenses ($/boe) ($4.78) ($5.75) - Transportation expenses ($/boe) ($1.46) ($0.90) - Operating netback ($/boe) $57.26 $40.39 - Depletion, depreciation & accretion ($/boe) ($13.70) - - General & administrative expenses ($/boe) $0.48 ($757.16) - ------------------------------------------------------------ Financial Petroleum and natural gas revenue 616,510 6,750 4,491 Royalties (117,122) (1,014) (676) Operating expenses (37,611) (860) (560) Transportation expenses (11,519) - - Depletion, depreciation & accretion (107,739) - - General and administrative expenses 3,766 (92,926) (140,756) Net earnings (loss) (239,344) (33,690) (280,859) Per share basic ($0.01) - ($0.01) Per share diluted ($0.01) - ($0.01) Funds from (used in) operations 667,874 134,741 (57,509) Per share basic $0.03 - - Per share diluted $0.03 - - ------------------------------------------------------------ Assets Total assets 43,265,379 36,599,111 33,658,993 Capital additions 12,709,467 3,358,212 299,285 Working capital (net debt) 16,938,081 28,988,324 32,212,017 ------------------------------------------------------------ Production Production during the fourth quarter of 2006 increased 131% to 1,689 boe/d compared with 730 boe/d in the prior quarter. The production increase is due primarily to successful drilling in the third and fourth quarter of 2006 with 12 wells starting production in the fourth quarter of 2006. Of these wells, four wells were in the West Pembina area, one well in Pembina, four wells in Carrot Creek and three wells in Brazeau. Production increased from the 85 boe/d recorded in the fourth quarter of 2005 due to the success of the 2006 capital program. Production during the fourth quarter was subject to infrastructure capacity constraints. The Corporation is currently implementing a plan to commit 2007 capital expenditures to remove such infrastructure capacity constraints in the first quarter of 2007. Petroleum and Natural Gas Sales Petroleum and natural gas revenues increased 145% to $7,605,027 in the fourth quarter of 2006 compared to $3,103,658 in the third quarter of 2006 as a result of increased production volumes. Realized natural gas prices increased 9% to $7.81 per mcf in the fourth quarter compared to $7.16 per mcf in the third quarter. The price increase along with the production growth resulted in substantial revenue growth. Revenues increased significantly from the $616,510 recorded in the fourth quarter of 2005 due to significant increases in production. Royalties Royalties, net of ARTC, for the fourth quarter of 2006 increased to $1,496,714 compared to the prior quarter of $473,159. As a percentage of sales, the royalty rate increased to 19.7% in the fourth quarter of 2006 from 15.2% in the third quarter of 2006. The increase in the royalty rate is due to a lower proportion of wells granted royalty holidays. Compared to the fourth quarter of 2005, royalties increased from $117,122. Operating Expenses Operating expenses for the fourth quarter of 2006 increased to $1,038,235 compared to the prior quarter of $398,957. On a boe basis, operating expenses in the fourth quarter were $6.68 compared to $5.94 recorded in the third quarter, an increase of 13%. Operating expenses during the fourth quarter of 2005 were $37,611 and $4.78 per boe. Transportation expenses for the fourth quarter of 2006 increased to $201,808 compared to the prior quarter of $80,594. On a boe basis, transportation expenses in the fourth quarter were $1.30 compared to $1.20 recorded in the third quarter, an increase of 8%. Transportation expenses during the fourth quarter of 2005 were $11,519 and $1.46 per boe. The increase in operating costs and transportation costs per boe is due primarily to higher costs associated with transportation and processing contracts for the facilities where a significant amount of the Corporation's production is received. Operating expenses for 2007 are expected to decrease as a result of the Corporation's plans to debottleneck the facility constraints and send more gas to a lower fee facility. General and Administrative Expenses For the fourth quarter of 2006, G&A expenses were $385,541 ($2.48 per boe) compared to $234,923 ($3.50 per boe) recorded in the prior quarter. Fourth quarter G&A expense was comprised of $961,272 in direct G&A expenses less $285,952 in recoveries and $289,779 in capitalized G&A. The prior quarter, G&A was comprised of $822,929 in G&A expenses less $188,682 in recoveries and $399,324 in capitalized G&A. The decrease in G&A expenses in the fourth quarter of 2006 over the prior quarter is due to an increase in production in the current quarter. The Corporation recorded G&A recovery of $3,766 (recovery of $0.48 per boe) in the fourth quarter of 2005. The increase in G&A expenses over the fourth quarter of 2005 is a result of increases in activity. Depletion, Depreciation and Accretion For the fourth quarter of 2006, DD&A expenses increased 258% to $3,489,106 from the $974,140 recorded in the third quarter primarily due to increased production in the fourth quarter of 2006. On a boe basis, DD&A expenses increased 55% in the current quarter, increasing to $22.45 in the fourth quarter from $14.50 in the third quarter. For the fourth quarter of 2005, the DD&A expense per boe was $13.70. The increase in DD&A over the fourth quarter of 2005 reflects the increase reflects higher finding costs due to the significant number of promoted wells in 2006, higher-than-expected drilling and completion costs and an industry-wide increase in service costs. Net Earnings Net earnings for the fourth quarter of 2006 decreased 91% to $118,510 ($nil per basic and diluted share) from $1,267,070 ($0.03 per basic and diluted share) recorded in the prior quarter. Net earnings in the fourth quarter of 2006 increased over the net loss of $239,344 (a loss of $0.01 per basic and diluted share) recorded in the fourth quarter of 2005. Funds From Operations The Corporation recorded $4,454,516 ($0.10 per basic share, $0.09 per diluted share) in funds from operations in the fourth quarter, a 115% increase over the $2,073,756 ($0.05 per basic share, $0.04 per diluted share) recorded in the prior quarter. The increase in net earning and funds from operations over the third quarter of 2006 is due to higher production and natural gas prices. Funds from operations in the fourth quarter of 2006 increased from the $667,874 ($0.03 per basic and diluted share) recorded in the fourth quarter of 2005 reflecting the significant production increases in the fourth quarter of 2006 compared to the same quarter of 2005. Total Assets Total assets increased 45% to $140,094,501 at the end of the fourth quarter of 2006 compared to $96,665,274 in the prior quarter. The increase is attributable to an increase in drilling and capital spending in the fourth quarter of 2006. The increase in total assets from $43,265,379 at December 31, 2005 is due primarily to the extensive capital program in 2006. The capital expenditures in the fourth quarter of 2006 included $911,571 for land acquisitions and maintenance, $36,428,540 of drilling and completions, $419,630 in geological and geophysical activities and $5,611,617 in facilities and $285,952 for capitalized general and administrative costs. Included in total assets at the end of the fourth quarter of 2006, $1.9 million related to capital inventory purchases to be used in the 2007 capital program and $1.5 million related to two wells drilling over year end and site preparation costs for 2007 drills. Working Capital Deficiency Bank debt and working capital deficiency has increased throughout 2006 as a result of using leverage to fund a portion of the corporation's drilling and acquisition program. The increase in bank debt and working capital deficiency to $38,747,390 in the fourth quarter from $13,657,738 in the third quarter reflects the partial funding of the Corporation's fourth quarter capital expenditures with the remaining funding derived from the Corporation's November 8, 2006 flow through share issuance of $15,003,000. CORK EXPLORATION INC. Balance Sheets As at As at December 31, December 31, $ 2006 2005 ------------------------------------------------------------------------- ASSETS (Notes 3 & 13) Current assets Cash and cash equivalents - 17,938,193 Accounts receivable 12,606,003 6,741,148 Prepaid expenses and deposits 537,997 59,278 Financial derivative instruments (Note 10) 181,849 - ------------------------------------------------------------------------- 13,325,849 24,738,619 ------------------------------------------------------------------------- Property, plant and equipment (Note 4) 126,768,652 18,140,149 Future income tax asset (Note 8) - 386,611 ------------------------------------------------------------------------- 126,768,652 18,526,760 ------------------------------------------------------------------------- 140,094,501 43,265,379 ------------------------------------------------------------------------- ------------------------------------------------------------------------- LIABILITIES Current liabilities Bank debt (Note 3) 16,948,316 - Accounts payable and accrued liabilities 35,124,923 7,800,538 ------------------------------------------------------------------------- 52,073,239 7,800,538 ------------------------------------------------------------------------- Asset retirement obligations (Note 5) 565,141 101,546 Future income tax liability (Note 8) 1,029,421 - ------------------------------------------------------------------------- 1,594,562 101,546 ------------------------------------------------------------------------- SHAREHOLDERS' EQUITY Share capital (Note 6) 82,136,731 33,212,188 Contributed surplus (Note 7) 3,153,875 2,705,000 Retained earnings (deficit) 1,136,094 (553,893) ------------------------------------------------------------------------- 86,426,700 35,363,295 ------------------------------------------------------------------------- Commitments (Note 6 & 12) ------------------------------------------------------------------------- 140,094,501 43,265,379 ------------------------------------------------------------------------- ------------------------------------------------------------------------- See accompanying notes to the financial statements CORK EXPLORATION INC. Statements of Earnings (Loss) and Retained Earnings (Deficit) For the period February 14, Year ended 2005 to December 31, December 31, $ 2006 2005 ------------------------------------------------------------------------- REVENUES Petroleum and natural gas sales 15,179,829 627,751 Realized gain on financial derivative instruments (Note 10) 421,967 - Royalties (net of Alberta Royalty Tax Credit) (3,132,433) (118,812) Interest 300,182 516,633 Unrealized gain on financial derivative instruments (Note 10) 181,849 - ------------------------------------------------------------------------- 12,951,394 1,025,572 ------------------------------------------------------------------------- EXPENSES Operating 1,992,953 39,031 Transportation 382,582 11,519 General and administrative (Note 11) 1,219,092 229,916 Stock-based compensation (Note 7) 533,254 925,622 Interest 105,619 - Depletion, depreciation and accretion 6,006,710 107,739 ------------------------------------------------------------------------- 10,240,210 1,313,827 ------------------------------------------------------------------------- Earnings (loss) before income taxes 2,711,184 (288,255) INCOME TAXES Future income taxes (Note 8) 1,021,197 265,638 ------------------------------------------------------------------------- Net earnings (loss) for the period 1,689,987 (553,893) Deficit, beginning of period (553,893) - ------------------------------------------------------------------------- Retained earnings (deficit), end of period 1,136,094 (553,893) ------------------------------------------------------------------------- ------------------------------------------------------------------------- Net earnings (loss) per share (Note 6) Basic $0.04 ($0.02) Diluted $0.04 ($0.02) ------------------------------------------------------------------------- See accompanying notes to the financial statements CORK EXPLORATION INC. Statements of Cash Flows For the period February 14, Year ended 2005 to December 31, December 31, $ 2006 2005 ------------------------------------------------------------------------- Cash provided by (used in) OPERATING Net earnings (loss) for period 1,689,987 (553,893) Add (deduct) non-cash items: Depletion, depreciation and accretion 6,006,710 107,739 Stock-based compensation (Note 7) 533,254 925,622 Unrealized gain on financial derivative instruments (Note 10) (181,849) - Future income taxes 1,021,197 265,638 ------------------------------------------------------------------------- 9,069,299 745,106 Change in non cash working capital (Note 9) (2,657,705) (520,479) ------------------------------------------------------------------------- 6,411,594 224,627 ------------------------------------------------------------------------- ------------------------------------------------------------------------- FINANCING Proceeds from bank debt 16,948,316 - Proceeds from issuance of shares (net of share issue costs) 47,699,742 32,559,939 ------------------------------------------------------------------------- 64,648,058 32,559,939 ------------------------------------------------------------------------- ------------------------------------------------------------------------- INVESTING Capital expenditures (112,636,361) (16,366,964) Change in non cash working capital (Note 9) 23,638,516 1,520,591 ------------------------------------------------------------------------- (88,997,845) (14,846,373) ------------------------------------------------------------------------- ------------------------------------------------------------------------- Increase (decrease) in cash and cash equivalents (17,938,193) 17,938,193 Cash and cash equivalents, beginning of period 17,938,193 - ------------------------------------------------------------------------- Cash and cash equivalents, end of period - 17,938,193 ------------------------------------------------------------------------- ------------------------------------------------------------------------- See accompanying notes to the financial statements CORK EXPLORATION INC. NOTES TO FINANCIAL STATEMENTS Year Ended December 31, 2006 and For the Period February 14, 2005 to December 31, 2005 1. NATURE OF BUSINESS Cork Exploration Inc. ("Cork" or the "Corporation") was incorporated under the laws of the Province of Alberta on February 14, 2005 under the name of 1152311 Alberta Ltd. On March 15, 2005, the Corporation changed its name to Cork Exploration Inc. The Corporation commenced trading on the Toronto Stock Exchange on June 28, 2006 under the symbol CRK. Cork is engaged in the exploration, development and production of petroleum and natural gas in the Western Canada Sedimentary basin. 2. SIGNIFICANT ACCOUNTING POLICIES Basis of Presentation The financial statements have been prepared in accordance with Canadian generally accepted accounting principles. These principles require management to use estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods presented. Actual results may differ from these estimates and assumptions. Significant accounting policies are summarized below. Joint Venture Operations A significant portion of the Corporation's exploration, development and production activities are conducted jointly with others. These financial statements reflect only the Corporation's proportionate interest in such activities. Measurement Uncertainty The amounts recorded for depletion and depreciation of petroleum and natural gas property, plant and equipment and the provision for asset retirement obligations are based on estimates. The cost recovery ceiling test is based on estimates of proved reserves, production rates, petroleum and natural gas prices, future costs and other relevant assumptions. The determination of stock compensation involves estimates of volatility of the Corporation's common shares and expected life. By their nature, these estimates are subject to measurement uncertainty and the impact of changes in those estimates on the financial statements of future periods could be material. Cash and Cash Equivalents Cash and cash equivalents consist of cash in the bank, less outstanding cheques and short-term deposits with a maturity of less than three months. Property, Plant & Equipment Capitalized costs The Corporation follows the full cost method of accounting for petroleum and gas operations whereby all costs related to the acquisition, exploration and development of petroleum and natural gas reserves are capitalized. Such costs include land and lease acquisition costs, geological and geophysical costs, carrying charges of non-producing properties, costs of drilling both productive and non-productive wells, the cost of petroleum and natural gas production equipment and corporate expenses directly related to exploration and development activities. Proceeds from the disposition of petroleum and natural gas properties are accounted for as a reduction of capitalized costs except for dispositions that would change the rate of depletion and depreciation by 20% or more, in which case a gain or loss would be recorded. Ceiling test Petroleum and natural gas assets are evaluated at each balance sheet date to determine if the costs are recoverable and do not exceed the fair value of the properties. Impairment is recognized if the carrying amount of the property, plant and equipment exceeds the sum of the undiscounted cash flows expected to result from the Corporation's proved reserves plus the cost of undeveloped land, net of any impairment. If the carrying value is impaired, the amount of impairment is measured by comparing the carrying amounts of the property, plant and equipment to an amount equal to the estimated net present value of future cash flows from proved plus probable reserves plus the cost of undeveloped land, net of any impairment. The calculation of the estimated net present value of future cash flows incorporates risks and uncertainties in the expected future cash flows that are discounted using a risk-free rate. Any excess carrying value above the net present value of the future cash flows would be recorded as a permanent impairment and charged to earnings. Depletion and depreciation Capitalized costs, together with estimated future capital costs associated with proved reserves, are depleted and depreciated using the unit-of-production method based on estimated gross proved reserves of petroleum and natural gas as determined by independent engineers. For purposes of this calculation, reserves and production are converted to equivalent units of oil based on relative energy content of six thousand cubic feet of gas to one barrel of oil. Costs of significant unproved properties, net of impairments, are excluded from the depletion and depreciation calculation. Costs of significant unproved properties excluded from the depletion and depreciation calculation are assessed annually for impairment. Office furniture, equipment and leaseholds are recorded at cost and depreciated over their useful life on a declining balance basis using a rate of 20%. Asset Retirement Obligations The Corporation recognizes the fair value of any asset retirement obligations as a liability in the period in which it incurs a legal obligation associated with the retirement of tangible long-lived assets that result from the acquisition, construction, development, and normal use of the assets. On recognition of the liability there is a corresponding increase in the carrying amount of the related assets known as the asset retirement cost, which is depleted on a unit-of-production basis over the life of the reserves. The liability is adjusted each reporting period to reflect the passage of time, with the accretion charged to earnings, and for the revisions to the estimated future cash flows. Actual costs incurred upon settlement of the obligations are charged against the liability. Derivative Instruments Derivative financial instruments are utilized to reduce commodity price risk associated with the Corporation's production of oil and natural gas. The Corporation does not enter into financial instruments for trading or speculative purposes. The Corporation follows a policy of using risk management instruments such as fixed price swaps, forward sales, puts and costless collars. The objective is to partially offset or mitigate the wide price swings commonly encountered in oil and natural gas commodities and in so doing protect a minimum level of cash flow in periods of low commodity prices. For financial risk management contracts entered into during 2006, the Corporation does consider these contracts to be effective on an economic basis but has decided not to designate these contracts as hedges for accounting purposes and, accordingly, for outstanding contracts, an unrealized gain or loss is recorded based on the fair value (mark-to-market) of the contracts at the period end. These instruments have been recorded as a financial derivative asset in the balance sheet. In the case of forward sales, the instrument can sometimes be satisfied by physical delivery. In the case of physical delivery, the payment is part of the normal revenue stream. Revenue Recognition Revenues from the sale of petroleum, natural gas and natural gas liquids are recorded when title passes to an external third party. Revenues are recorded gross of transportation charges incurred by the Corporation. Income Taxes The Corporation follows the liability method of accounting for income taxes. Under this method, future income tax is based on the differences between assets and liabilities reported for financial reporting purposes and those reported for income tax purposes. Future income taxes are measured using substantively enacted tax rates and laws that will be in effect when the differences are expected to reverse. The effect on future tax assets and liabilities of a change in tax rates is recognized in net earnings in the period in which the changes are substantively enacted. Future income tax assets are limited to the amount that is more likely than not to be realized. Flow-through Shares The Corporation from time to time finances a portion of its exploration and development activities through the issuance of flow-through common shares. Under the terms of the flow-through share agreements, the tax attributes of the related expenditures are renounced to the subscribers. Share capital is reduced and the future income tax liability is increased by the tax effect of the renounced tax deductions at the time of renouncement, which is when the related documentation is filed with the appropriate government agency and there is reasonable certainty that the expenditures will be incurred. Stock-Based Compensation The Corporation accounts for its stock-based compensation plans using the fair value method. Fair value is determined at the grant date using the Black-Scholes option-pricing model and is recognized over the vesting period of the options and performance warrants granted as stock compensation expense and contributed surplus. Upon the exercise of the stock options, consideration paid together with the amount previously recorded in contributed surplus is recorded as an increase to share capital. The Corporation has not incorporated an estimated forfeiture rate for stock options that will not vest, and will instead account for actual forfeitures as they occur. Per Share Information Basic earnings per share is calculated using the weighted average number of shares outstanding during the period. Diluted earnings per share is calculated using the treasury stock method to determine the dilutive effect of stock options and warrants. The treasury method assumes that proceeds from the exercise of in-the-money stock options and warrants are used to re-purchase common shares at the average market price during the period. 3. BANK DEBT At December 31, 2006, the Corporation had a $30 million demand revolving operating credit facility agreement with a Canadian chartered bank. The credit facility provides that advances may be made by way of direct advances or bankers' acceptances. Direct advances bear interest at the bank's prime lending rate and bankers' acceptances bear interest at the applicable bankers' acceptance rates plus a 120 basis points per annum stamping fee. The effective interest rate on the bank debt during 2006 was 5.2%. The credit facility is subject to periodic review and was collateralized by a $60 million demand floating charge debenture over all of the assets of the Corporation. As at December 31, 2006, $16.9 million had been drawn under the bank facility. On January 29, 2007, the Corporation increased its facility to $33.0 million under the same terms. On February 16, 2007, the Corporation entered into a commitment letter to replace its $33 million credit facility with a $45 million credit facility from another Canadian chartered bank (see Note 13). 4. PROPERTY, PLANT AND EQUIPMENT December 31, December 31, $ 2006 2005 ------------------------------------------------------------------------- Petroleum and natural gas property and equipment 132,688,979 18,186,650 Furniture and equipment 145,704 61,103 ------------------------------------------------------------------------- 132,834,683 18,247,753 Accumulated depletion and depreciation (6,066,031) (107,604) ------------------------------------------------------------------------- Net book value 126,768,652 18,140,149 ------------------------------------------------------------------------- ------------------------------------------------------------------------- The Corporation capitalizes certain general and administrative expenditures and stock-based compensation directly related to exploration and development activities. During the year ended December 31, 2006, the Corporation capitalized $1,375,424 and $1,535,259 (including tax effect of $961,245), respectively, of such costs (2005 - $597,251 and $1,779,378 respectively). The calculation of 2006 depletion and depreciation included an estimated $17,832,000 (2005 - $3,559,000) for future development capital associated with proved undeveloped reserves and excluded $4,986,009 (2005 - $4,765,171) for the estimated value of unproved properties. Depletion and depreciation expense for the year ended December 31, 2006 was $5,958,427 (2005 - $107,604). The Corporation performed a ceiling test calculation at December 31, 2006 to assess the recoverability of its petroleum and natural gas interests. As at December 31, 2006 there was no impairment required. The prices used in the ceiling test evaluation of the Corporation's petroleum and natural gas assets are summarized in the following chart: Crude Oil Natural Gas Natural Gas Liquids ------------------------------------------------------------------------- Edmonton Spec Edmonton Edmonton Edmonton Par AECO Ethane Propane Butane Pentanes (Cdn$/bbl) (Cdn$/Mcf) (Cdn$/bbl) (Cdn$/bbl) (Cdn$/bbl) (Cdn$/bbl) ------------------------------------------------------------------------- 2007 70.25 7.20 24.25 45.00 56.25 71.75 2008 68.00 7.45 25.25 43.50 50.25 69.25 2009 65.75 7.75 26.25 42.00 48.75 67.00 2010 64.50 7.80 26.50 41.25 47.75 65.75 2011 64.50 7.85 26.50 41.25 47.75 65.75 2012 65.00 8.15 27.75 41.50 48.00 66.25 2013 66.25 8.30 28.25 42.50 49.00 67.50 2014 67.75 8.50 29.00 43.25 50.25 69.00 2015 69.00 8.70 29.50 44.25 51.00 70.50 2016 70.50 8.90 30.00 45.00 52.25 72.00 2017 71.25 9.10 30.75 46.00 53.00 73.25 Thereafter 2.0% 2.0% 2.0% 2.0% 2.0% 2.0% ------------------------------------------------------------------------- ------------------------------------------------------------------------- Percentage change of 2.0% represents the change in future process each year after 2017 to the end of the reserve life. 5. ASSET RETIREMENT OBLIGATIONS The total future asset retirement obligations are estimated by management based on the Corporation's net ownership in all wells and facilities, the estimated costs to abandon and reclaim the wells and facilities and the estimated timing of the costs to be incurred in future periods. The total undiscounted amount of the estimated cash flows required to settle the asset retirement obligation is approximately $1,083,290 which will be incurred over the next 49 years with the majority of costs to be incurred between 2019 and 2037. A credit adjusted risk-free rate ranging from 7.2% to 8.0% and an inflation rate of 2% was used to calculate the fair value of the asset retirement obligations. The following reconciles the Corporation's asset retirement obligation: For the period February 14, Year ended 2005 to December 31, December 31, $ 2006 2005 ------------------------------------------------------------------------- Balance, beginning of period 101,546 - Liabilities incurred 415,312 101,411 Accretion expense 48,283 135 ------------------------------------------------------------------------- Balance, end of period 565,141 101,546 ------------------------------------------------------------------------- ------------------------------------------------------------------------- 6. SHARE CAPITAL Authorized: Unlimited number of voting common shares Unlimited number of preferred shares, issuable in series Issued: The Corporation had the following shares outstanding at December 31, 2006: For the period Year ended February 14, 2005 to December 31, 2006 December 31, 2005 ------------------------------------------------------------------------- Number Amount ($) Number Amount ($) ------------------------------------------------------------------------- Common shares Balance, beginning of period 34,500,001 33,212,188 - - Issued on incorporation - - 1 1 Issued pursuant to private placement(i) - - 34,500,000 34,500,000 Tax effect of flow- through renouncement(i) - (489,171) - - Reclassification of flow-through share benefit due to renunciation of tax pools(i) - 291,000 - - Issued for cash(ii) 12,084,000 50,003,000 - - Share issue costs(i)(ii) - (3,381,100) - (1,940,062) Tax effect of share issue costs(i)(ii) - 1,055,579 - 652,249 Issued on exercise of options 90,000 162,833 - - Issued on exercise of warrants 915,010 915,010 - - Reclassification from contributed surplus upon exercise of options & warrants - 367,392 - - ------------------------------------------------------------------------- Balance, end of period 47,589,011 82,136,731 34,500,001 33,212,188 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Share capital amounts related to the exercise of stock options and warrants include stock based compensation amounts. Issue of Common Shares: i) On May 5, 2005, pursuant to a private placement, 33,045,000 common shares and 1,455,000 flow-through common shares were sold at an issue price of $1.00 per share for gross proceeds of $34,500,000. All of the flow-through common shares were issued to management and directors of the Corporation. Total costs related to the placement were $1,287,813 (net of tax effect of $652,249) for net total proceeds of $32,559,938. The Corporation's total commitment for flow-through expenditures of $1,455,000 was met effective December 31, 2005. A future tax liability of $489,171 on the flow through share issue was recognized upon filing of the renunciation in February 2006. ii) On June 28, 2006, the Corporation issued 8,750,000 common shares at a price of $4.00 per share for gross proceeds of $35,000,000. Total share issue costs related to the issuance were $1,696,594 (net of tax effect of $770,102) for net total proceeds of $33,533,304. On November 8, 2006, the Corporation issued, on a private placement, bought deal basis, 3,334,000 flow-through common shares at an issue price of $4.50 per flow-through common share for aggregate gross proceeds of $15,003,000. Total costs related to the placement were $628,927 (net of tax effect of $285,477) for total proceeds of $14,088,596. The related income tax impact will be recorded when the tax expenditures are renounced to shareholders in 2007. The Corporation is committed to spend the $15,003,000 on exploration expenditures and renouncing the tax deductions related to such expenditures to the holders of the flow-through shares prior to December 31, 2007. As of December 31, 2006, approximately $6.8 million of qualifying expenditures had been spent. Earnings (loss) per share Net earnings (loss) per common share figures have been calculated using the treasury stock method. The following table reconciles the denominators used for the basic and diluted earning per common share calculations: For the period February 14, Year ended 2005 to December 31, December 31, Weighted average common shares 2006 2005 ------------------------------------------------------------------------- Basic 39,830,670 25,901,870 Effect of warrants 3,772,506 - Effect of stock options 856,409 - ------------------------------------------------------------------------- Diluted 44,459,585 25,901,870 ------------------------------------------------------------------------- ------------------------------------------------------------------------- 7. STOCK-BASED COMPENSATION Stock Options Under the terms of the stock option plan (the "Plan"), directors, employees and service providers may be granted options to purchase common shares. The Plan provides for the granting of up to 10% of the issued and outstanding common shares of the Corporation. No eligible optionee may hold stock options to purchase more than 5% of the outstanding common shares of the Corporation. Options granted under the plan prior to September 2006, have a term of five years to expiry and vest over a two-year period. One third of the options vest when granted, one third vest on the first anniversary of the grant date and one third vest on the second anniversary of the grant date. The options granted under the plan in September 2006 have a term of five years to expiry and vest equally over a three-year period. One third of the options vest on the first anniversary of the grant date, one third vest on the second anniversary and one third vest on the third anniversary. The following table provides a reconciliation of the stock option plan activity through December 31, 2006: December 31, 2006 December 31, 2005 ------------------------------------------------------------------------- Weighted Weighted average average Number of exercise Number of exercise options price ($) options price ($) ------------------------------------------------------------------------- Balance, beginning of period 450,000 1.00 - - Granted 2,930,000 2.07 450,000 1.00 Exercised (90,000) 1.81 - - Cancelled (156,667) 1.82 - - ------------------------------------------------------------------------- Balance, end of period 3,133,333 1.94 450,000 1.00 ------------------------------------------------------------------------- ------------------------------------------------------------------------- The following table summarizes stock options outstanding and exercisable under the plan at December 31, 2006: Options outstanding Options exercisable ------------------------------------------------------------------------- Weighted Weighted Weighted Range of average average average exercise Number of contractual exercise Options exercise price options life price exercisable price ------------------------------------------------------------------------- $1.00 450,000 3.60 $1.00 300,000 $1.00 $1.75 2,238,333 4.22 $1.75 746,111 $1.75 $3.85 35,000 4.64 $3.85 11,667 $3.85 $3.51 150,000 4.74 $3.51 - - $4.00 260,000 4.47 $4.00 86,667 $4.00 ------------------------------------------------------------------------- 3,133,333 4.18 $1.94 1,144,445 $1.75 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Performance Warrants Pursuant to the initial private placement of shares on May 5, 2005, the Corporation issued performance warrants to management, directors and employees to purchase up to 6,900,000 common shares at a price of $1.00 per share until May 5, 2010. As of December 31, 2005 all of the performance warrants became fully vested. The following table provides a reconciliation of the activity through December 31, 2006: December 31, 2006 December 31, 2005 ------------------------------------------------------------------------- Weighted Weighted average average Number of exercise Number of exercise warrants price ($) warrants price ($) ------------------------------------------------------------------------- Balance, beginning of period 6,900,000 1.00 - - Granted - - 6,900,000 1.00 Exercised (915,010) 1.00 - - ------------------------------------------------------------------------- Balance, end of period 5,984,990 1.00 6,900,000 1.00 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Stock-Based Compensation The Corporation accounts for its stock based compensation plan using the fair value method. Under this method, a compensation cost is charged over the vesting period for stock options and performance warrants with a corresponding increase to contributed surplus. The following table reconciles the Corporation's contributed surplus: For the period February 14, Year ended 2005 to December 31, December 31, ($) 2006 2005 ------------------------------------------------------------------------- Balance, beginning of period 2,705,000 - Reclassification of flow through share benefit due to the renunciation of tax pools (291,000) - Stock-based compensation expense 534,931 925,622 Capitalized stock-based compensation 586,853 1,779,378 Exercise of stock options & performance warrants (367,392) - Cancellation of stock options (14,517) - ------------------------------------------------------------------------- Balance, end of period 3,153,875 2,705,000 ------------------------------------------------------------------------- ------------------------------------------------------------------------- The fair value of the options granted during the period was estimated on the date of grant using the Black-Scholes option pricing model with weighted average assumptions and resulting values for grants as follows: For the period February 14, Year ended 2005 to December 31, December 31, Assumptions 2006 2005 ------------------------------------------------------------------------- Risk free interest rate 4.0% 3.5% Expected life (years) 3 3 Expected dividend yield (%) 0% 0% Expected volatility (%) 45.2% 45.0% ------------------------------------------------------------------------- Weighted average fair value of options granted ($) $0.72 $0.34 ------------------------------------------------------------------------- ------------------------------------------------------------------------- 8. FUTURE INCOME TAXES The provision for future income taxes in the statements of earnings reflect an effective tax rate which differs from the expected statutory tax rate. Differences were accounted for as follows: For the period February 14, Year ended 2005 to December 31, December 31, ($) 2006 2005 ------------------------------------------------------------------------- Net earnings before taxes 2,711,184 (288,255) Expected statutory income tax rate 34.50% 37.62% ------------------------------------------------------------------------- Expected income taxes (recovery) 935,358 (108,442) Add (deduct): Non-deductible crown payments 371,566 26,006 Resource allowance (230,284) 27,878 Income tax rate changes (216,151) (31,605) Non-deductible stock compensation and other expenses 190,810 348,219 Other (30,102) 3,582 ------------------------------------------------------------------------- Future income tax expense 1,021,197 265,638 ------------------------------------------------------------------------- ------------------------------------------------------------------------- The future income tax liability at December 31, 2006 and future income tax asset at December 31, 2005 is comprised of the tax effect of temporary differences as follows: For the period February 14, Year ended 2005 to December 31, December 31, ($) 2006 2005 ------------------------------------------------------------------------- Property, plant and equipment (1,457,389) (522,317) Commodity contracts (62,729) - Asset retirement obligations 163,891 34,140 Loss carry-forward - 351,339 Share issue costs 1,207,876 521,799 Attributed Canadian Royalty Income 80,175 - Other (961,245) 1,650 ------------------------------------------------------------------------- Future income tax asset (liability) (1,029,421) 386,611 ------------------------------------------------------------------------- ------------------------------------------------------------------------- As at December 31, 2006, the Corporation had tax deductions of approximately $122,436,867 (2005 - $14,895,000 of tax deductions and $1,045,000 in non-capital losses) that are available to shelter future taxable income. 9. SUPPLEMENTAL CASH FLOW INFORMATION Changes in non-cash working capital For the period February 14, Year ended 2005 to December 31, December 31, ($) 2006 2005 ------------------------------------------------------------------------- Accounts receivable (5,864,855) (6,741,148) Prepaid expenses and deposits (478,719) (59,278) Accounts payable and accrued liabilities 27,324,385 7,800,538 ------------------------------------------------------------------------- Change in non-cash working capital 20,980,811 1,000,112 ------------------------------------------------------------------------- Relating to: Operating activities (2,657,705) (520,479) Investing activities 23,638,516 1,520,591 ------------------------------------------------------------------------- 20,980,811 1,000,112 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Interest and taxes paid For the period February 14, Year ended 2005 to December 31, December 31, ($) 2006 2005 ------------------------------------------------------------------------- Interest paid 105,619 - ------------------------------------------------------------------------- Taxes paid - - ------------------------------------------------------------------------- ------------------------------------------------------------------------- 10. FINANCIAL INSTRUMENTS Fair value of financial instruments: Financial instruments of the Corporation carried on the balance sheet consist mainly of cash and cash equivalents, accounts receivable, deposits, financial derivative instruments, bank debt and accounts payable. The estimated fair value of the financial instruments approximates their carrying value due to their short terms to maturity and the floating interest rate on the Corporation's debt. Credit risk: Substantially all of the Corporation's accounts receivable are due from customers in the oil and gas industry and are subject to normal credit risk. With respect to counterparties to financial instruments, the Corporation mitigates associated credit risk by entering into transactions with major institutions with investment grade credit ratings. Interest rate risk: The Corporation is exposed to interest rate risk to the extent that changes in market interest rates impacts its borrowings under the floating rate credit facility. The Corporation had no interest rate swaps or hedges at December 31, 2006. Risk Management Activities The Corporation has entered into derivative financial instruments for the purpose of protecting a portion of its funds from operations from the volatility of natural gas commodity prices. The Corporation has not designated the derivatives as a hedge for accounting purposes and has therefore recorded the unrealized gains and losses on these contracts in the balance sheet as assets or liabilities with changes in their fair value recorded in net earnings for the period. Realized gains or losses from financial instruments related to commodity prices are recognized in the statement of earnings as the related sales occur. The realized gain for the year ended December 31, 2006 was $421,967. As at December 31, 2006, the Corporation had recognized a financial derivative instrument asset of $181,849. Following is a summary of all derivative contracts in place as at December 31, 2006: Pricing Natural Gas Volume Point Strike Price Term ------------------------------------------------------------------------- Costless collar 3000 gj/d AECO Cdn $7.00-$10.60 Sept 1/06-Mar 31/07 ------------------------------------------------------------------------- 11. RELATED PARTY TRANSACTIONS The Corporation had the following related party transactions: a) A company controlled by one of the Directors of the Corporation provides engineering consulting services to the Corporation. The amounts incurred for consulting services for 2006 were $51,622 (2005 - $23,355). b) The Corporation used the services of a law firm in which one of its partners became a Director of the Corporation in October, 2005. During 2006, the Corporation incurred $245,371 (2005 - $106,742) for services provided by the firm related to general corporate matters. All related party transactions are in the normal course of operations and have been measured at the agreed to exchange amounts, which are the amounts of consideration established and agreed to by the related parties and which are similar to those negotiated with third parties. 12. COMMITMENTS The Corporation leases office space under an agreement which expires in June, 2010. The minimum lease and operating payments required under the lease are $199,903 for each of 2007, 2008 and 2009 and $99,952 for 2010. 13. SUBSEQUENT EVENTS On January 23, 2007, the Corporation entered into a hedge against price movements on a portion of its future natural gas production. The Corporation has hedged 4,500 gj/d of natural gas production for the period of April 1 to October 31, 2007 through a swap on AECO natural gas price for $7.25/gj. On January 29, 2007, the Corporation increased its facility to $33.0 million under the same terms of the existing credit facility. On February 16, 2007, the Corporation entered into a commitment letter to replace its $33 million credit facility with a $45 million credit facility from another Canadian chartered bank. The credit facility provides that advances may be made by way of direct advances or bankers' acceptances. Direct advances bear interest at the bank's prime lending rate and bankers' acceptances bear interest at the applicable bankers' acceptance rate plus 100 basis points. Under the terms of the credit facility,funded debt to cash flow, calculated on a rolling four quarter basis is to be maintained at all times at 3.5:1 or lower. As at the quarter ending June 30, 2007 and thereafter, the ratio is to be maintained at all times at 3.0:1 or lower. The cash flow to interest expense, calculated on a rolling four quarter basis, is not to be less than 2.5:1. The credit facility is collateralized by a $100 million demand floating charge debenture over all of the assets of the Corporation. On February 20, 2007, the Corporation issued, on a private placement, bought deal basis, an aggregate of 3,335,000 flow-through common shares at $4.80 per flow-through common share for aggregate gross proceeds of $16,008,000. Proceeds from the issuance of the flow-through common shares will be used to fund the Corporation's 2007 exploration and development program. Canadian exploration expenses in the amount of the gross proceeds from the offering will be renounced to subscribers of the flow-through common shares effective on or before December 31, 2007. On March 8, 2007, the Board of Directors approved the granting of an additional 730,000 options to directors, employees and insiders of the Corporation. %SEDAR: 00023712E

For further information:

For further information: Cork Exploration Inc., 380, 435 - 4th Avenue
S.W., Calgary, Alberta, T2P 3A8; Philip E. Collins, President and CEO; Or
Geoffrey D. Krause, Vice-President Finance and CFO, Telephone: (403) 531-1695,
Fax: (403) 531-1696; Website: www.corkexploration.com

Organization Profile

CORK EXPLORATION INC.

More on this organization


Custom Packages

Browse our custom packages or build your own to meet your unique communications needs.

Start today.

CNW Membership

Fill out a CNW membership form or contact us at 1 (877) 269-7890

Learn about CNW services

Request more information about CNW products and services or call us at 1 (877) 269-7890