Kereco Energy Ltd. announces 2006 results



    CALGARY, March 8 /CNW/ - Kereco Energy Ltd. ("Kereco") or the ("Company")
is pleased to announce results for the Company's fourth quarter and year end
ended December 31, 2006, including the closing of the acquisition of Chamaelo
Exploration Ltd. ("Chamaelo") on October 19, 2006.

    
    FINANCIAL AND OPERATING HIGHLIGHTS
    -------------------------------------------------------------------------
    FINANCIAL               Three months                       Year
    ($000s, unless     ended December 31          ended December 31
     otherwise                                %                          %
     indicated)            2006     2005   Change     2006     2005   Change
    -------------------------------------------------------------------------
    Petroleum and
     natural gas sales   39,753   36,971        8  131,674   90,728       45
    Funds flow from
     operations          20,592   20,984       (2)  72,226   50,357       43
      Per share -
       basic ($)           0.40     0.62      (35)    1.87     1.78        5
      Per share -
       diluted ($)         0.39     0.59      (34)    1.81     1.72        5
    Net earnings (loss)    (234)   9,381     (102)  20,005   16,488       21
      Per share -
       basic ($)          (0.01)    0.28     (104)    0.52     0.58      (10)
      Per share -
       diluted ($)        (0.01)    0.26     (104)    0.50     0.56      (11)
    Capital expenditures
      Exploration and
       development       22,930   20,978        9  102,095   88,207       16
      Net acquisitions
       and dispositions 291,783   (1,308)  22,400  299,258  140,826      113
    -------------------------------------------------------------------------
      Total             314,713   19,670    1,600  401,353  229,033       75
    -------------------------------------------------------------------------
    Bank debt           188,673   71,737      163  188,673   71,737      163
    Working capital
     deficiency (1)       7,228    7,683       (6)   7,228    7,683       (6)
    -------------------------------------------------------------------------
    Total net debt(2)   195,901   79,420      147  195,901   79,420      147
    -------------------------------------------------------------------------
    Shareholders'
     equity             481,248  210,584      129  481,248  210,584      129

    Common shares
     outstanding (000s)
      Basic              55,336   33,716       64   55,336   33,716       64
      Diluted            62,808   38,125       65   62,808   38,125       65
    Weighted average
     common shares
     outstanding (000s)
      Basic              51,189   33,716       52   38,611   28,335       36
      Diluted            52,504   35,419       48   39,984   29,349       36
    -------------------------------------------------------------------------
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    OPERATING HIGHLIGHTS(3)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Average daily
     production(4)
      Natural gas
       (mcf/day)         22,406   16,687       34   16,896   12,616       34
      Crude oil and NGLs
       (bbls/day)         4,376    2,858       53    3,408    2,031       68
      Barrels of oil
       equivalent
       (boe/day)          8,111    5,640       44    6,224    4,133       51
    Average selling
     prices(5)
      Natural gas ($/mcf)  7.08    11.73      (40)    7.14     9.41      (24)
      Crude oil and NGLs
       ($/bbl)            59.47    70.56      (16)   67.23    68.31       (2)
      Barrels of oil
       equivalent
       ($/boe)            51.64    70.48      (27)   56.19    62.29      (10)
    Wells drilled (No.)
      Gross                 8.0     10.0      (20)    30.0     34.0      (12)
      Net                   4.7      6.6      (29)    19.9     22.9      (13)
      Success (%)            75       90      (17)      83       88       (6)
    Undeveloped land
     (000s of acres)
      Gross                 336      143      135      336      143      135
      Net                   225       89      153      225       89      153
    Average working
     interest (%)            67       62        8       67       62        8
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Excluding financial derivative contracts.
    (2) Bank debt plus working capital deficiency, excluding financial
        derivative contracts.
    (3) References in this report to boe refer to barrel of oil equivalent
        whereby natural gas volumes have been converted at a rate of
        six thousand cubic feet of natural gas to one barrel of oil.  See
        "Management's Discussion and Analysis" on page four.
    (4) Daily production numbers are calculated using 348 days for the first
        nine months of 2005 as oil and gas operations for Kereco commenced on
        January 18, 2005.
    (5) Average selling prices are net of transportation costs and excluding
        financial derivatives.


    MESSAGE TO SHAREHOLDERS

    Kereco Energy Ltd. ("KCO") is pleased to provide our results for the
fourth quarter and year ended December 31, 2006. Kereco is also pleased to
announce the recent addition of Nathan MacBey to our management team in the
position of Vice President, Negotiations.

   2006 was a challenging year for Kereco as it was for most E & P companies
operating in Canada. Falling natural gas and crude oil prices, service costs
being dramatically higher than 2005 levels - coupled with delays due to labour
and equipment availability, regulatory backlogs, and inexperienced field crews
limited our ability to control our destiny. Kereco entered the year with high
expectations after experiencing some significant and promising drilling
success in late 2005. As well, the commodity price complex looked strong and
sustainable as we moved into 2006. By the middle of the first quarter however
our tone towards near-term natural gas pricing changed from being optimistic
to cautious. With the lack of cold winter weather in both the producing and
consuming regions our concerns grew that there would be record high storage
levels reached in 2006 which would lead to soft natural gas prices during the
summer months and into the fall of the year. Commodity prices ended up falling
from a high of $78.00 US WTI to $59.00 US WTI and natural gas from in excess
of $9.00 CDN/GJ at the beginning of the year to a low of approximately $4.40
CDN/GJ in September. Kereco attempted to do its best to protect against
falling natural gas prices by hedging a good portion of our natural gas
production, reducing our overall capital program, and shifting a higher
percentage of capital towards light oil and away from natural gas. Moving
capital away from our natural gas prone Blair Creek asset precipitated higher
than contemplated declines as the wells drilled in 2005 failed to stabilize at
anticipated rates. In addition to shifting our capital towards our light oil
projects at Sturgeon Lake, where we continued to exceed our expectations for
value creation, we focused our efforts on expanding our growth potential and
diversifying our asset mix. In August we announced the corporate acquisition
of Chamaelo Exploration Ltd. ("Chamaelo") which brought a mix of 50% light oil
and 50% natural gas - maintaining Kereco's even product split. The assets
acquired provide Kereco with property diversification, increased strength to
the Kereco production base, an increase to the size of our central Alberta
growth inventory, and an ability to generate significantly lower F & D costs;
all of which we contemplate being realized as we move through 2007. We also
continued to mature our long-term value plays.  The Sturgeon Lake tertiary
recovery evaluation is on timeline with results to date continuing to show
promise of a viable scheme.  The Blair Creek shale play is marginally behind
our quantification timeline, however we are in the midst of maturing both a
geological and execution model for testing in Q3 of 2007. Overall, our
operating netback remained strong at $34.90/boe for 2006 due to our premium
product mix and downside natural gas price protection and we anticipate this
to continue to improve as commodity prices strengthen through 2007.

    The following is a summary of our fourth quarter and full year 2006:

     1.   Reserves
       -  Kereco added 13.487 mmboe of proved and probable reserves, bringing
          the company total to 32.514 mmboe which is up 53% from year end
          2005.
       -  Reserve life index on a P + PA basis moves to 11.0 years based on
          fourth quarter average production.
       -  Finding and development costs for the year on a P + PA basis were
          $32.66/boe excluding future development costs, $37.96/boe including
          future development costs.  Excluding revisions (primarily at Blair
          Creek) and our acquisition of Chamaelo, finding and developments
          were $20.36/boe on a P + PA basis excluding future development
          costs, $25.22/boe with the inclusion of future development costs.

     2.   Production

       -  Fourth quarter average production was 8,111 boe/day, a 49% increase
          over the previous quarter and a 44% increase over the fourth
          quarter of 2005.
       -  2006 average daily production was 6,224 boe/day (16.9 mmcf/day of
          natural gas and 3,408 boe/day of oil and liquids), a 51% increase
          over 2005.

     3.   Undeveloped land
       -  Kereco grew its net undeveloped land by 153% to 225,000 acres from
          89,000 acres in 2005, principally in the central Alberta area where
          we added 57,000 net acres of undeveloped land.

     4.   Net Asset Value ("NAV")
       -  Kereco ended the year with a NAV of $8.32/share (basic) using a net
          present value at 8%, before tax, analysis.

     5.   Tax Pools
       -  At year end Kereco maintains a very significant tax pool base at
          $478.3 million which we believe provides us with the ability to
          defer any current tax obligations through to 2010.

     6.   Drilling Inventory
       -  Kereco currently has in excess of 270 drilling prospects in
          inventory of which 178 demonstrate potential for sound economic
          returns in the current price and cost environment.  This drilling
          inventory provides in excess of three years of drilling potential
          for our company at currently budgeted spending levels.

     7.   Capital

       -  During the fourth quarter, the Company spent $12.3 million and
          $99.0 million for the full year on exploration and development,
          excluding the $341.5 million acquisition of Chamaelo.

     8.    Wells Drilled

        -  In the fourth quarter of 2006, Kereco drilled 8 wells with 75%
           success resulting in 4 gas wells, 2 oil wells and 2 dry and
           abandoned.  For the full year, Kereco drilled a total of 30 wells
           with an 83% success rate including 16 gas wells, 9 oil wells and 5
           abandonments.

     9.    Funds Flow

        -  Funds flow from operations for the fourth quarter was $20.6
           million $0.40 per basic share), a 35% decrease from the fourth
           quarter of 2005. For the year, funds flow was $72.2 million
           ($1.87 per basic share), a 5% increase over 2005 cash flow per
           basic share.


    Reserves
    --------

    The following tables outline the Company's reserves as at December 31,
2006 as independently evaluated by GLJ Petroleum Consultants Ltd. ("GLJ") in
accordance with National Instrument 51-101 Standards of Disclosure of Oil and
Gas Activities ("NI 51-101"). For the complete NI 51-101 disclosures please
refer to the Company's Annual Information Form which will be filed on SEDAR on
or before March 31, 2007.

    Summary of Oil and Gas Reserves (Company Interest - Forecast Price
    Case)(1)

                                                                    2006 Boe
                          Natural gas    Crude oil         NGLs   equivalent
                                (mmcf)      (mmbls)      (mbbls)       (mboe)
    -------------------------------------------------------------------------
    Proved producing           39,412        8,547        1,291       16,406
    Proved non-producing        7,455        1,046          226        2,515
    -------------------------------------------------------------------------
    Total proved developed     46,867        9,593        1,517       18,921
    Proved undeveloped         10,053        2,243          286        4,205
    -------------------------------------------------------------------------
    Total proved               56,920       11,836        1,803       23,126
    Probable additional        24,571        4,557          735        9,388
    -------------------------------------------------------------------------
    Total proved plus
     probable                  81,491       16,394        2,538       32,514
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    Net Present Value of Reserves

                      Undis-  Discounted  Discounted  Discounted  Discounted
    ($000s)          counted       At 8%      at 10%      at 12%      at 15%
    -------------------------------------------------------------------------
    Total Proved     690,957     460,651     427,051     398,492     362,793
    Probable         291,268     140,641     123,415     109,534      93,101
    -------------------------------------------------------------------------
    Total Proved
     Plus Probable   982,225     601,292     550,465     508,026     455,894
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Corporate Reserve Reconciliation (mboe)

                          Dec 31, 2005     Revisions(1)       Additions
                               Opening
    -------------------------------------------------------------------------
    Total Proved                15,970            (970)           3,183
    -------------------------------------------------------------------------
    Total Proved
     Plus Probable              21,299          (1,336)           4,741
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Corporate Reserve Reconciliation (mboe)

                          Property      Corporate
                      Acquisitions   Acquisitions    Production      Close
    -------------------------------------------------------------------------
    Total Proved               552          6,663       (2,272)     23,126
    -------------------------------------------------------------------------
    Total Proved
     Plus Probable             641          9,441       (2,272)     32,514
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------




     Finding and development costs ("F & D") by Major Capital Type


                                                     Change in
                                          2006(4)       Future
    ($000s, except as                    Capital   Development         Total
     otherwise noted)               Expenditures       Capital       Capital
    -------------------------------------------------------------------------
    Proved Reserves
      Exploration and development        102,094        15,244       117,338
      Corporate acquisitions(4)          330,923        29,898       360,821
      Property acquisitions                7,475             -         7,475
    -------------------------------------------------------------------------
      Total                              440,492        45,142       485,634
    -------------------------------------------------------------------------
    Proved Plus Probable Reserves
      Exploration and development        102,094        26,145       128,239
      Corporate acquisitions(4)          330,923        45,335       376,258
      Property acquisitions                7,475             -         7,475
    -------------------------------------------------------------------------
      Total                              440,492        71,480       511,972
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


                                                 Traditional(2)  NI 51-101(3)
                                                         F & D         F & D
                                         Reserve     No Future   With Future
    ($000s, except as                  Additions       Capital       Capital
     otherwise noted)                      (mboe)       ($/boe)       ($/boe)
    -------------------------------------------------------------------------
    Proved Reserves
      Exploration and development          2,213         46.13         53.02
      Corporate acquisitions(4)            6,663         49.67         55.26
      Property acquisitions                  552         13.54         13.54
    -------------------------------------------------------------------------
      Total                                9,429         46.72         51.50
    -------------------------------------------------------------------------
    Proved Plus Probable Reserves
      Exploration and development          3,403         30.00         37.68
      Corporate acquisitions(4)            9,441         35.05         39.85
      Property acquisitions                  641         11.66         11.66
    -------------------------------------------------------------------------
      Total                               13,487         32.66         37.96
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Finding and development costs ("F & D") excluding Corporate Acquisition
    and Revisions


                                                     Change in
                                          2006(4)       Future
    ($000s, except as                    Capital   Development         Total
     otherwise noted)               Expenditures       Capital       Capital
    -------------------------------------------------------------------------
    Proved Reserves                      109,569        15,244       124,813

    Proved Plus Probable Reserves        109,569        26,145       135,714
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


                                                 Traditional(2)  NI 51-101(3)
                                                         F & D         F & D
                                         Reserve     No Future   With Future
    ($000s, except as                  Additions       Capital       Capital
     otherwise noted)                      (mboe)       ($/boe)       ($/boe)
    -------------------------------------------------------------------------
    Proved Reserves                        3,736         29.33         33.41

    Proved Plus Probable Reserves        5,381.6         20.36         25.22
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    (1) Since inception, the Company's reserves have been evaluated by the
        independent engineering firm of GLJ Petroleum Consultants ("GLJ").
    (2) Calculated excluding changes in future development capital.
    (3) Calculated as outlined in NI 51-101, including the change in future
        development capital.
    (4) Comprised of $341.5 million for the acquisition of Chamaelo, net of
        $10.6 million of former Chamaelo properties disposed prior to year
        end.


    OUTLOOK

    Moving into 2007, we are very excited about our prospects for value
adding growth, primarily in natural gas.  We are continuing to gain confidence
in the commodity price complex for the back half of this year and into 2008.
Our expectation is that natural gas will be above $9.00/GJ as we exit the year
and oil will be at, or above, $65.00 US WTI.  We are also experiencing
softening service costs and services that are more readily available which we
anticipate will have a substantial impact on capital efficiencies and will
improve cycle times.  We also believe acquisition metrics to be reducing as a
result of the lack of available equity and tightening debt financing
capabilities.

    Kereco has experienced some very good drilling results in its $30 million
first quarter capital program, we believe adding between 1.5 to 2.0 mmboe of
reserves.  Although the Chamaelo acquisition has met or exceeded our
expectations for delivering efficient growth from a production standpoint, we
have been plagued by production hydrate problems with our Pembina property,
negatively impacting our current production by approximately 1,500 boe/day.
Assuming we are successful at getting the hydrate problems resolved in the
near term at Pembina, we will achieve our 10,500 boe/day first quarter exit
production rate guidance.  We currently have an additional capability from our
first quarter drilling program of between 1,800 and 2,300 boe/day which is
awaiting tie-in or regulatory approval at this time.

    For the year we are projecting our production to increase over 65% from
2006 levels to an average daily rate of 10,300  10,800 boe/day with an exit
rate of 12,000 boe/day (55% natural gas, 45% light oil & liquids).  Our $130
million capital budget for 2007 includes the drilling of 55 to 65 wells and
will be subject to increase if the environment continues to warrant capital
expansion.  Our capital for the year is allocated approximately 65% towards
natural gas and 35% towards light oil with 15 to 20% directed to high impact
exploration.  We estimate that our capital program as budgeted will generate
cash flow between $125 - $130 million ($2.15 - $2.25 per basic share), an
increase of 17% over 2006 levels.

    We remain somewhat cautious in the near term to ensure our financial
strength and flexibility and at the same time continue to be optimistic about
a significantly improving 2007, and we look forward to reporting back to you
on our progress as the year unfolds.  Thank you for your continued interest
and support of Kereco.

     On behalf of the Board of Directors,
     Grant B. Fagerheim President and Chief Executive Officer
     March 8, 2007




    MANAGEMENT'S DISCUSSION AND ANALYSIS

    The following management's discussion and analysis ("MD&A") should be
read in conjunction with the audited consolidated financial statements and
MD&A for the years ended December 31, 2006 and 2005 contained in the 2006
consolidated financial statements of Kereco and is based on information to
March 7, 2006. The reader should be aware that historical results are not
necessarily indicative of future performance. Additional information relating
to Kereco Energy Ltd. ("Kereco")or the ("Company") can be found at
www.sedar.com.
    Funds flow from operations, which is determined before changes in non-
cash working capital, is used by us as a key measure of performance. Funds
flow from operations does not have a standardized meaning prescribed by
Canadian Generally Accepted Accounting Principles ("GAAP") and therefore may
not be comparable with the calculation of similar measures for other
companies. Funds flow from operations as presented is not intended to
represent operating profits for the period nor should it be viewed as an
alternative to cash provided by operating activities, net earnings or other
measures of financial performance calculated in accordance with GAAP. Funds
flow from operations per share is calculated using the same share bases which
are used in the determination of earnings per share.
    The financial data contained herein has been prepared in accordance with
GAAP, and unless otherwise indicated, all comments in this report are in
thousands of Canadian dollars. In conformity with Canadian Securities
Administrators National Instrument 51-101, natural gas volumes have been
converted to equivalent barrels of oil ("boe") using a conversion ratio of six
thousand cubic feet ("mcf") to one boe. This ratio is based on an energy
equivalency conversion method primarily applicable at the burner tip and does
not represent a value equivalency at the wellhead. Readers are cautioned that
boes may be misleading, particularly if used in isolation.

    FORWARD LOOKING STATEMENTS

    Certain information set forth in this disclosure, including management's
assessment of the future plans and operations of Kereco, contains forward-
looking statements. By their nature, forward-looking statements are subject to
numerous risks and uncertainties, some of which are beyond our control,
including the impact of general economic conditions, industry conditions,
changes in laws and regulations including the adoption of new environmental
laws and regulations and changes in how they are interpreted and enforced,
volatility of commodity prices, currency fluctuations, interest rate
volatility, imprecision of reserve estimates, environmental risks, competition
from other industry participants, the lack of availability of qualified
personnel or management, stock market volatility and ability to access
sufficient capital from internal and external sources, market valuations with
respect to announced transactions and the final valuations thereof and
obtaining required approvals of regulatory authorities. Readers are cautioned
that the assumptions used in the preparation of such information, although
considered reasonable at the time of preparation, may prove to be imprecise
and, as such, undue reliance should not be placed on forward looking
statements. The actual results, performance or achievement of Kereco could
differ materially from those expressed in, or implied by, these forward-
looking statements and, accordingly, no assurance can be given that any of the
events anticipated by the forward looking statements will transpire or occur,
or if any of them do so, what benefits that Kereco will derive therefrom.
Except as required by law, Kereco disclaims any intention or obligation to
update or revise any forward-looking statements, whether as a result of new
information, future events or otherwise.

    BASIS OF PRESENTATION

    Kereco is a Calgary-based intermediate light oil and natural gas
exploration, development and production company whose key business activities
are focused in central and north western Alberta and north eastern British
Columbia. Kereco began operations as an oil and gas exploration and production
company on January 18, 2005 with the conveyance of oil and gas properties from
Ketch Resources Ltd. ("Ketch"). Our strategy is to create value primarily
through the generation and drilling of exploration and development prospects
as well as through the exploitation and production of existing reserves,
otherwise referred to as organic growth. In addition, we seek strategic
acquisitions which add to our production, reserves and growth potential. We
target areas and prospects that we believe can result in meaningful reserve
and production additions on a per share basis.

    RESULTS OF OPERATIONS

    Production in 2006 averaged 6,224 boe/day (16,896 mcf/day of natural gas
and 3,408 bbls/day of crude oil and NGLs) up 34 percent from the 4,133 boe/day
(12,616 mcf/day of natural gas and 2,031 bbls/day of crude oil and NGLs)
averaged in 2005.
    Capital expenditures in 2006, including net property dispositions of
$3.1 million, were $98.9 million. Kereco also completed the corporate
acquisition of Chamaelo Exploration Ltd. ("Chamaelo") on October 19, 2006
which added $302.4 million to property, plant and equipment. During the year
ended December 31, 2006, our net $98.9 million capital program, resulted in
the drilling of 30 wells, 16 of which were cased as natural gas wells and nine
were cased as oil wells (83 percent success). Of the 25 successful wells
drilled in 2006, four were completed as gas wells and one as an oil well in
our Peace River Arch area, seven as gas wells in our Blair Creek area, six as
oil wells in our Sturgeon Lake area, three as gas wells in our emerging Noel
and Poplar areas and two gas and two oil wells in our new Central Alberta area
acquired with Chamaelo.

    2006 Selected Quarterly Information
                                                           2006
    -------------------------------------------------------------------------
    ($000s, except per share amounts)          Q4       Q3       Q2       Q1
    -------------------------------------------------------------------------
    Revenues (net of royalties)            31,461   24,152   22,984   24,048
    -------------------------------------------------------------------------
    Funds flow from operations             20,592   17,422   16,690   17,552
      Per share - basic ($)                  0.40     0.49     0.49     0.52
      Per share - diluted ($)                0.39     0.48     0.48     0.80
    -------------------------------------------------------------------------
    Net earnings (loss)                      (234)   7,006    7,765    5,468
      Per share - basic ($)                 (0.01)    0.20     0.23     0.16
      Per share - diluted ($)               (0.01)    0.19     0.22     0.16
    -------------------------------------------------------------------------
    Total assets                          767,411  391,933  364,342  347,063
    -------------------------------------------------------------------------
    Bank debt                             188,673   84,695   74,284   79,565
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


                                                           2005
    -------------------------------------------------------------------------
    ($000s, except per share amounts)          Q4       Q3       Q2       Q1
    -------------------------------------------------------------------------
    Revenues (net of royalties)            28,312   23,471   14,963    2,681
    -------------------------------------------------------------------------
    Funds flow from operations             20,984   17,523   10,161    1,689
      Per share - basic ($)                  0.62     0.52     0.34     0.11
      Per share - diluted ($)                0.59     0.49     0.32     0.10
    -------------------------------------------------------------------------
    Net earnings (loss)                     9,381    4,645    2,651     (189)
      Per share - basic ($)                  0.28     0.14     0.09    (0.01)
      Per share - diluted ($)                0.26     0.13     0.08    (0.01)
    -------------------------------------------------------------------------
    Total assets                          328,267  312,030  269,321   50,374
    -------------------------------------------------------------------------
    Bank debt                              71,737   66,628   46,749    3,060
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    Increases in revenues, funds flow from operations and net earnings
throughout 2005 was a result of increased production due to increased drilling
activities and also due to increasingly stronger commodity prices. The
pronounced increase in the second quarter of 2005 was largely a reflection of
the Chariot Energy Inc. ("Chariot") acquisition which closed on April 19, 2005
and whose results were included from that point forward. The pronounced
increase in the fourth quarter of 2006 was largely a result of the Chamaelo
acquisition which closed on October 19, 2006 and whose results were included
from that point forward. Relatively flat production volumes and commodity
prices in the first, second and third quarters of 2006 resulted in relatively
flat revenues and funds flow from operations over that period.

    Selected Annual Information
                                             Year ended December 31
    -------------------------------------------------------------------------
    ($000s, except per share amounts)                 2006     2005     2004
    -------------------------------------------------------------------------
    Revenues (net of royalties)                    102,645   69,427        -
    -------------------------------------------------------------------------
    Funds flow from operations                      72,226   50,357        -
      Per share - basic ($)                           1.87     1.78        -
      Per share - diluted ($)                         1.81     1.72        -
    -------------------------------------------------------------------------
    Net earnings (loss)                             20,005   16,488        -
      Per share - basic ($)                           0.52     0.58        -
      Per share - diluted ($)                         0.50     0.56        -
    -------------------------------------------------------------------------
    Total assets                                   767,411  328,267        -
    -------------------------------------------------------------------------
    Bank debt                                      188,673   71,737        -
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    FUNDS FLOW FROM OPERATIONS

    Funds flow from operations increased 43 percent in 2006 to $72.2 million,
or $1.81 per share on a diluted basis from $50.4 million, or $1.72 per share
on a diluted basis for 2006, largely as a result of increased production
volumes offset somewhat by lower commodity prices. Funds flow from operations
is calculated as follows:

                                                      Year ended December 31
    -------------------------------------------------------------------------
    ($000s)                                                    2006     2005
    -------------------------------------------------------------------------
    Cash provided by operating activities                    67,977   41,525
    Change in non-cash working capital                        4,294    8,832
    ------------------------------------------------------------------------
    Funds flow from operations                               72,226   50,357
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    NET OPERATING INCOME

                                                      Year ended December 31
    -------------------------------------------------------------------------
    ($000s, except per share amounts)                          2006     2005
    -------------------------------------------------------------------------
    Petroleum and Natural gas sales                         131,674   90,728
    Transportation                                           (4,012)  (1,131)
    Realized financial derivative gains/(losses)              1,854     (479)
    -------------------------------------------------------------------------
    Total net sales                                         129,516   89,118
    Royalty expenses                                        (29,029) (21,301)
    Operating expenses                                      (21,193) (13,476)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Net operating income                                     79,294   54,341
    -------------------------------------------------------------------------
      Per share  - basic ($)                                   2.05     1.92
                 - diluted ($)                                 1.98     1.85
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    OPERATING NETBACKS

                                                      Year ended December 31
    -------------------------------------------------------------------------
                                                               2006     2005
    -------------------------------------------------------------------------
    Boe netback ($/boe)
      Sales price                                             57.96    63.08
      Transportation                                          (1.77)   (0.79)
      Realized gains (loss) on financial derivatives           0.82    (0.33)
    -------------------------------------------------------------------------
      Sales price, net of transportation and realized
       gain (loss) on financial derivatives                   57.01    61.96
      Royalty expenses  - ($/boe)                            (12.78)  (14.81)
                        - (%)                                  22.7     23.8
      Operating expenses                                      (9.33)   (9.37)
    -------------------------------------------------------------------------
      Netback                                                 34.90    37.78
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
      Natural gas netback ($/mcf)
      Sales price                                              7.37     9.53
      Transportation                                          (0.23)   (0.12)
      Realized gains (loss) on financial derivatives           0.31    (0.04)
    -------------------------------------------------------------------------
      Sales price, net of transportation and realized
       gain (loss) on financial derivatives
                                                               7.45     9.37
      Royalty expenses  - ($/mcf)                             (1.57)   (2.29)
                        - (%)                                  22.0     24.3
      Operating expenses                                      (1.55)   (1.55)
    -------------------------------------------------------------------------
      Netback                                                  4.33     5.53
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Crude oil and NGL netback ($/bbl)
      Sales price                                             69.31    69.15
      Transportation                                          (2.07)   (0.84)
      Realized loss) on financial derivatives                 (0.05)   (0.40)
    -------------------------------------------------------------------------
      Sales price, net of transportation realized
       gain (loss) on financial derivatives                   67.19    67.91
      Royalty expenses  - ($/bbl)                            (15.54)  (15.93)
                        - (%)                                  23.1     23.3
      Operating expenses                                      (9.35)   (9.42)
    -------------------------------------------------------------------------
      Netback                                                 42.30    42.56
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    PETROLEUM AND NATURAL GAS SALES

    Production in 2006 averaged 6,224 boe/day and net realized prices of
$56.19/boe resulted in revenues of $131.6 million, a 51 percent increase in
production and a 10 percent decrease in realized prices compared to the year
ended 2005 which had production of 4,133 boe/day and realized prices of
$62.29/boe. Production increases for the year ended 2006 over 2005 are largely
attributable to the recognition of a a full year of production from the
Chariot acquisition which closed on April 19, 2005 as well as the recognition
of production from the Chamaelo acquisition which closed on October 19, 2006.
Average price realizations in 2006, net of transportation costs, were
$56.19/boe ($7.14/mcf for natural gas, $67.23/bbl for crude oil & NGLs and
realized financial derivative gains of $0.82/boe). Financial derivative
contracts in place (see note 10 to the consolidated financial statements for
further details) resulted in realized gains of $1.9 million ($0.82/boe) for
2006. Comparatively, average price realizations for the year ended 2005, net
of transportation costs, were $62.29/boe ($9.41/mcf for natural gas,
$68.31/bbl for crude oil & NGLs and a financial derivative loss of $0.33/boe).
The decrease in net realized prices tracked changes in the underlying
commodity prices over these periods. Gas prices averaged, for AECO daily index
($Cdn/mcf) $6.53/mcf in 2006, 25 percent lower than $8.74/mcf in 2005, and the
average monthly index AECO natural gas price was $6.98/mcf for 2006, 18
percent lower than $8.49/boe in 2005. WTI crude oil strengthened to average
U.S.$66.25/bbl in 2006, 17 percent higher than U.S. $56.623/bbl averaged in
2005. On a boe basis, the decreases in realized gas commodity prices for 2006
were partially offset by the financial derivative contracts we entered into
which resulted in gains of $1.9 million or $0.82/boe.
    All of our production is sold within Canada, and revenues are received in
Canadian dollars. There was an increase in the value of the Canadian dollar
versus the U.S. dollar in 2006 compared to 2005 and other historical levels,
which negatively impacted our price realizations. The average Canada/U.S.
exchange rate for 2006 was 1.13 for 2006 and was an average of 1.22 for 2005.

    Realized Financial Derivatives

    We entered into several financial and physical commodity contracts to
assist in minimizing exposure to commodity prices. In accordance with our
corporate policies, a maximum of 70 percent of our forecasted production can
be capped by management under financial or physical contracts for a period not
extending further than 12 months hence without obtaining additional approval
of our board of directors. Physical contracts are settled as a part of actual
monthly product sales directly from marketers that purchase our production.
Financial contracts are settled through direct exchange of funds with the
applicable financial institutions holding the positions.
    The following financial derivative contracts were in place resulting in
$1.9 million of realized derivative gains for 2006:

    Period                      Volume                Type   Pricing terms(1)
    -------------------------------------------------------------------------
    Natural Gas

    Apr 1 - Oct 31, 2006   2000 GJ/day    Financial Collar    $9.00 - $13.00
                                                              (AECO CDN $/GJ)
    Jul 1 - Sep 30, 2006   4000 GJ/day    Financial Collar    $6.25 - $8.83
                                                              (AECO CDN $/GJ)
    Sep 1 - Sep 30, 2006   2000 GJ/day    Financial Collar    $5.50 - $8.30
                                                              (AECO CDN $/GJ)
    Nov 1 - Dec 31, 2006   4500 GJ/day    Financial Collar    $7.78 - $13.42
                                                              (AECO CDN $/GJ)
    Crude Oil

    Jan 1 - Dec 31, 2006   1250 bbls/day  Financial Collar   $52.29 - $73.38
                                                                (WTI US$/BBL)
    Apr 1 - Dec 31, 2006   500 bbls/day   Financial Collar   $55.00 - $77.00
                                                                (WTI US$/BBL)
    Jun 1 - Dec 31, 2006   500 bbls/day   Financial Collar   $62.00 - $86.75
                                                                (WTI US$/BBL)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Collar price indicates minimum floor and maximum ceiling.


    The realized gains from financial derivatives in place throughout 2006
were mainly due to our natural gas collar structures in place as AECO natural
gas prices decreased throughout 2006.

    Transportation Costs

    ($000s, except as indicated)                      Year ended December 31
    -------------------------------------------------------------------------
                                                               2006     2005
    -------------------------------------------------------------------------
    Transportation costs                                      4,012    1,131
      - $/boe                                                  1.77     0.79
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Increases in transportation costs in 2006 are related to the increase in
sales volumes compared to 2005. Transportation costs have remained level
throughout the year and are expected to remain fairly static on a per boe
basis throughout 2007. The increase in 2006 is also the result of recording
transportation expenses associated with prior period product sales as
previously recorded in the second quarter of 2006.

    ROYALTIES

                                                      Year ended December 31
    -------------------------------------------------------------------------
    ($000s, except as indicated)                               2006     2005
    -------------------------------------------------------------------------
    Royalties                                                29,029   21,301
      - $/boe                                                 12.78    14.81
      - rate %                                                 22.7     23.8
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Our royalty burdens are predominantly Crown, along with some overriding,
freehold and net profits interest royalties ("other royalties"). For the year
ended 2006, average royalty rates remained relatively static at 22.7 percent
(Crown royalties of 20.6 percent and other royalties of 2.1 percent) compared
to 23.8 percent (Crown royalties of 22.0 percent and other royalties of
1.8 percent) for the year ended 2005. ARTC of $0.5 million has been recognized
for the year to date on production from new wells drilled by Kereco. Kereco's
overall corporate royalty rate is expected to be maintained or decrease
slightly into 2007 as a result of a reduced corporate royalty rate expected
through continued drilling incentives, and increased reductions due expected
capital cost allowance, operating expense and custom processing deductions.

    CASH COSTS

    Cash costs (operating, general and administrative and interest) increased
to $12.60/boe in 2006 from $11.87/boe in 2005 largely as a result of higher
interest expense. Cash costs are expected to decrease with increased
production volumes and as cost control initiatives are implemented in 2007, in
addition to the incorporation of the relatively lower cost Chamaelo assets
into our portfolio.

    Operating Costs

                                                      Year ended December 31
    -------------------------------------------------------------------------
    ($000s, except as indicated)                               2006     2005
    -------------------------------------------------------------------------
    Operating costs                                          21,193   13,476
      - $/boe                                                  9.33     9.37
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Operating costs remained relatively static on a per boe basis in 2006
compared to 2005 as increases in costs tracked production increases. Year to
date 2006 costs were $9.33/boe ($1.55/mcf for natural gas and $9.35/bbl for
crude oil and NGLs) compared to 2005 costs of $9.37/boe ($1.55/mcf for natural
gas and $9.42/bbl for crude oil and NGLs). Operating costs are largely
influenced by power costs for our Sturgeon Lake facility, repair and
maintenance at Sturgeon Lake and the ability to attract third party volumes
for processing through our Sturgeon Lake Plant. Despite the significance of
these factors we managed to keep operating costs relatively consistent on a
year over year basis. The Chamaelo properties which were recently acquired are
also relatively lower cost properties to operate averaging approximately $7.00
to $8.00 per boe historically. This assisted in reducing our overall 2006
corporate rate and will also assist in maintaining our expected operating cost
rate for all of 2007. We also continue to have approximately 70 percent of the
electrical power load required for Sturgeon Lake fixed at a rate of $65.50 per
KWh throughout 2007 and 2008.

    General and Administrative Expenses

                                                      Year ended December 31
    -------------------------------------------------------------------------
    ($000s, except as indicated:                               2006     2005
    -------------------------------------------------------------------------
    Gross                                                     4,664    3,087
    Capitalized overhead                                       (611)    (201)
    Recoveries                                               (1,973)  (1,004)
    -------------------------------------------------------------------------
    Net                                                       2,080    1,882
    -------------------------------------------------------------------------
      - $/boe                                                  0.92     1.31
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    General and administrative costs decreased 30 percent on a boe basis to
$0.92/boe for the year ended 2006 from $1.31/boe for the year ended 2005
largely as a result of higher recoveries related to increased drilling
activity, a reduction in incentive compensation between the two periods as
well as increases in the overall production base in the year in outpacing
similar increases in general and administrative expenses. Gross general and
administrative expenses increased in 2006, largely related to the staff that
were added in conjunction with the Chamaelo acquisition. Total general and
administrative expenses are expected to be maintained or increase slightly in
2007. With the exception of minor changes when required, we believe that we
are currently adequately staffed to execute our currently planned 2007
activities.

    Interest Expense

                                                      Year ended December 31
    -------------------------------------------------------------------------
    ($000s, except as indicated)                               2006     2005
    -------------------------------------------------------------------------
    Interest expense                                          5,329    1,709
      - $/boe                                                  2.35     1.19
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Interest expense increased to $5.3 million in the 2006 compared to
$1.7 million in 2005. This increase was a result of the increase in the
company's size and asset base as a result of the Chamaelo acquisition and
increased capital activity over the past year, and the corresponding increase
in the size of, and utilization of, our credit facilities. The average draw on
our bank line during 2006 was $97.3 million (at an average interest rate of
5.48 percent) compared to a draw on the bank line in 2005 of $44.0 million (at
an average interest rate of 4.10 percent). The average interest rate rose as a
result of increases in prime lending rates, which directly impact our
completely floating rate obligations, over the two respective periods.
Interest expense is expected to increase in 2007 as a result of the expected
utilization of our bank line. The capital expenditure program for the
remainder of 2007 is expected to be funded from cash flow and our available
credit lines.

    NET EARNINGS

    Net earnings for 2006 were $20.0 million ($0.50 per diluted share)
compared to $16.5 million ($0.56 per share on a diluted basis) in 2005.

    Depletion, Depreciation and Accretion ("DD&A")

                                                      Year ended December 31
    -------------------------------------------------------------------------
    ($000s, except as indicated)                               2006     2005
    -------------------------------------------------------------------------
    Depletion and depreciation                               42,294   19,425
    Accretion                                                   661      362
    -------------------------------------------------------------------------
    Total DD&A                                               42,955   19,787
    -------------------------------------------------------------------------
      - $/boe                                                 18.91    13.76
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Depletion, depreciation and accretion ("DD&A") amounted to $42.9 million,
or $18.91/boe in 2006 compared to $19.8 million or $13.76/boe for 2005. The
DD&A rate throughout 2005 was largely influenced by the carrying value of the
property, plant and equipment conveyed from Ketch on January 18, 2005, the
fair value of property, plant and equipment acquired from Chariot on April 19,
2005 and the capital expenditures added to the depletable asset pool since
inception, relative to the proven reserves added. The DD&A rate increased in
2006 significantly in the fourth quarter of 2006 as a result of the fair value
of the property, plant and equipment acquired with Chamaelo on October 19,
2006 as well as the capital expenditures added to the depletable pool
throughout the year. These cumulative additions to the depletable pools
relative to year end reserves result in the increased DD&A rate per boe. The
DD&A rate for first quarter 2007 will be approximately $25.00 per boe (based
upon the fourth quarter DD&A rate), prior to incorporating any 2007
activities.

    Stock-Based Compensation Expense

                                                      Year ended December 31
    -------------------------------------------------------------------------
    ($000s, except as indicated)                               2006     2005
    -------------------------------------------------------------------------
    Stock based compensation expense                          4,011    2,664
    -------------------------------------------------------------------------
      - $/boe                                                  1.77     1.85
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Stock-based compensation expense increased 51 percent to $4.0 million in
2006 from $2.7 million in 2005. This increase reflects additional option
grants issued throughout 2006, including those associated with employees added
with the Chamaelo acquisition, as well as the effect of a full year of
compensation expense recognized with respect to all 2005 option grants. Stock-
based Compensation Expense may change in 2007 as Management and the Board of
Director's have approved an arrangement which will involve the cancellation of
stock options previously issued to non-insider employees and the regranting
them at a later date to the same non-insider employees of the Company. See
note 12. to the consolidated financial statements for more details.

    Unrealized (Gains) Losses on Financial Derivatives

                                                      Year ended December 31
    -------------------------------------------------------------------------
    ($000s)                                                    2006     2005
    -------------------------------------------------------------------------
    Unrealized (gain) loss                                   (5,198)      72
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Unrealized gains on financial derivative contracts at year end 2006
amounted to $5.2 million compared to unrealized losses of $0.1 million at year
end 2005. As all of our derivative contracts are based upon the commodity
benchmarks of (WTI) for oil and (AECO) natural gas, these gains are a result
of the reductions in commodity prices at the end of 2006. Accounting standards
require that the change in the fair value ("mark to market") of these
positions at each quarter end be included in earnings for the period. See note
10 in the notes to the consolidated financial statements for additional
details.

    Taxes

                                                         Year ended December
    -------------------------------------------------------------------------
    ($000s, except as indicated)                               2006     2005
    -------------------------------------------------------------------------
    Future income taxes                                      10,336   11,305
    Current income taxes                                       (224)     434
    -------------------------------------------------------------------------
    Total taxes                                              10,112   11,739
    -------------------------------------------------------------------------
    Effective tax rate (%)                                       34       42
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Total tax expense for 2006 of $10.1 million ($10.3 million of future
taxes and a recovery of $0.2 million of large corporations tax) compared to
2005 which was $11.7 million ($11.3 million of future income taxes and $0.4 of
large corporations tax). This results in an effective tax rate of 34 percent
for 2006 compared to a rate of 42 percent for 2005. This decrease in the
effective tax rate is mainly a result of reduced federal and provincial
corporate tax rates which were substantially enacted in the second quarter of
2006. A recovery of $0.2 million in large corporations tax also resulted from
the elimination of current income tax effective January 1, 2006 as well as an
additional recovery of $0.2 million resulting from the filing of the 2005 year
end tax return.

    Income Tax Pools

    At the end of 2006, we had $465.9 million of tax pools and losses
available for deduction against future taxable income. The CEE pools remaining
of $32.7 million are comprised of $44.3 million in expenditures, net of
$11.6 million in flow-through eligible expenditures incurred to December 31,
2006. Of the $22.0 million flow-through share offering on June 9, 2006,
$11.6 million has been spent to date. The remaining $10.4 million will be
spent throughout 2006 under the Canada Revenue Agency's defined "lookback"
rules. The tax pools available at year end are as follows:

    As at December 31 ($000s)                                           2006
    -------------------------------------------------------------------------
    Canadian oil and gas property expense ("COGPE")                  229,600
    Canadian development expense ("CDE")                              98,500
    Canadian exploration expense ("CEE")                              32,700
    Undepreciated capital costs ("UCC")                               90,600
    Non-capital losses carried forward                                14,500
    -------------------------------------------------------------------------
    Total pools and losses                                           465,900
    Share issue costs                                                 12,440
    -------------------------------------------------------------------------
    Total pools, losses and share issue costs                        478,340
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    LIQUIDITY AND CAPITAL RE

SOURCES Capital Resources Year ended December 31 ------------------------------------------------------------------------- 2006 2005 ------------------------------------------------------------------------- Funds flow from operations 72,226 50,357 Change in non-cash working capital (10,768) 9,569 Increase in bank debt 19,209 31,564 Repayment of bank debt assumed with Ketch plan of arrangement - (5,134) Common shares purchased for employee benefit plan - (351) Chamaelo acquisition transaction costs (2,780) - Proceeds from the exercise of stock options 443 - Proceeds from share issuances 20,626 158,522 ------------------------------------------------------------------------- Total capital resources 98,956 244,527 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Bank Debt At December 31, 2006 the Company had in place a syndicated committed credit facility, in the amount of $198 million, with two major Canadian Chartered Banks and the Canadian branch of a major international bank. Interest on this facility is charged at monthly rates and borrowings can be made in Canadian or U.S. dollars. Borrowings can also be made by way of prime rate advances or Banker's Acceptances which attract interest at increments to prime based on the Company's debt/cash flow ratio, calculated utilizing the two most recent fiscal quarters. The Company has provided a $500 million demand fixed and floating charge debenture as collateral for the facility. As at December 31, 2006, $188.7 million (December 31, 2005 - $71.7 million) had been drawn under the bank facility. The average interest rate on borrowings outstanding for the year was 5.48 percent, totaling $5.3 million in interest expense (December 31, 2005 - 4.10 percent and $1.7 million in interest expense). $162 million of the balance outstanding under the credit facility is not due within 12 months and is therefore presented as long term. $27 million of the balance under the credit facility is potentially repayable within 12 months and is therefore presented as current on the balance sheet. Subsequent to December 31, 2006, the credit facility was reduced from $198 million to $183 million. This reduction was the result of the effect of two minor property dispositions and a flow-through share financing subsequent to year end(see note 12 to the consolidated financial statements). This reduction is not related to the annual review of our credit facility currently being conducted by the syndicate of lenders, expected to be complete by the first week of April 2007. Working Capital Kereco ended the year with a working capital deficiency of $7.2 million which is comprised of accounts payable and accrued liabilities of $51.9 million and accounts receivable and prepaid expenses of $44.7 million. Accounts receivable mainly consist of monthly revenue which is predominately collected on the 25th day of the month following the month of production as well as joint venture receivables from partners with whom we conduct joint operations. Accounts payable and accrued liabilities consist of payments owing for capital, operating and general and administrative activities. Capital intensive periods will tend to create situations of a working capital deficiency. Kereco constantly monitors its working capital position in conjunction with its undrawn bank credit lines. Kereco expects that the credit lines which result from the borrowing base review currently in progress, and the expected cash flow for the year will be adequate to fund the upcoming year's expected capital program and operating commitments and we will continue to monitor all aspects and make changes to our plans if required. Share Capital Year ended December 31 ------------------------------------------------------------------------- 2006 2005 ------------------------------------------------------------------------- Weighted average shares outstanding Basic 38,610,662 28,335,221 Options and warrants 1,373,198 1,013,887 ------------------------------------------------------------------------- Diluted 39,983,860 29,349,108 ------------------------------------------------------------------------- Common shares outstanding Basic 55,336,432 33,715,578 Options and warrants 7,471,492 4,408,982 ------------------------------------------------------------------------- Diluted 62,807,924 38,124,560 ------------------------------------------------------------------------- ------------------------------------------------------------------------- As at March 7, 2007, Kereco had 57,748,032 shares outstanding, reflecting the issuance of 2,250,000 flow-through common shares and 161,600 warrants since December 31, 2006. In the second quarter of 2006, all of the 2,507,692 non-voting shares were converted to voting common shares and 1,500,000 flow- through common shares were issued. For the year to date 40,667 common shares were issued from the exercise of stock options and 153 shares were issued pursuant to the exercise of 153 warrants. 20,080,034 common shares were issued pursuant to the acquisition of Chamaelo Exploration Ltd. on October 19, 2006. CAPITAL EXPENDITURES Capital expenditures in 2006, including net property dispositions of $3.1 million, were $98.9 million. Kereco also completed the corporate acquisition of Chamaelo on October 19, 2006 which resulted in the addition of $302.4 million to property, plant and equipment. Year ended December 31 ------------------------------------------------------------------------- ($000s) 2006 2005 ------------------------------------------------------------------------- Land 2,621 26,165 Geological and geophysical 9,595 3,691 Drilling and completions 61,743 46,457 Facilities and equipment 26,735 11,099 Office and corporate costs 764 594 Capitalized general and administrative costs 637 201 ------------------------------------------------------------------------- Total exploration and development 102,095 88,207 ------------------------------------------------------------------------- Chariot acquisition - 143,278 Chamaelo acquisition 302,397 - Property acquisitions 7,475 1,474 Property dispositions (10,614) (3,926) ------------------------------------------------------------------------- Total capital expenditures 401,353 229,033 ------------------------------------------------------------------------- ------------------------------------------------------------------------- During the year ended December 31, 2006 we executed a $98.9 million capital program, including property acquisitions of $7.5 million and property dispositions of $10.6 million. We drilled 30 (19.8 net) wells which resulted in 16 cased natural gas wells and nine oil wells (83 percent success). Of the 25 successful wells drilled in 2006, four (2.1 net) were completed as gas wells and one (0.2 net) as an oil well in our Peace River Arch area, seven (4.2 net) as gas wells in our Blair Creek area, six (6.0 net) as oil wells in our Sturgeon Lake area, three (2.3 net) as gas wells in our emerging Noel and Poplar areas and two gas (1.1 net) and two (1.5 net) oil wells in our new Central Alberta area acquired with Chamaelo. This amounted to $62.6 million in drilling and completion expenditures for the year to date and $26.1 million in related equipping and facility costs. $2.6 million was also spent on land, which in combination with the acquisition of Chamaelo, resulted in an undeveloped land position, net of expiries, of 225,000 net undeveloped acres at December 31, 2006. $9.4 million was spent on seismic in the year, mainly in our exploration areas of Noel and Blair Creek, British Columbia. Property acquisitions included a producing property in our core Sturgeon area for $7.5 million in the third quarter of 2006 and property dispositions included four non-core properties which had been acquired with Chamaelo and disposed of in the fourth quarter of 2006. CONTRACTUAL OBLIGATIONS On February 16, 2007, the Company issued 2,250,000 flow-through common shares for proceeds of $19.4 million which will require the Company to spend $19.4 million of flow-through share eligible Canadian Exploration Expenditures, as defined in the Canadian Income Tax Act, by December 31, 2008. On June 9, 2006, the Company issued 1,500,000 flow-through common shares for proceeds of $22.0 million which will require the Company to spend $22 million of flow-through share eligible Canadian Exploration Expenditures, as defined in the Canadian income Tax Act, by December 31, 2007. Approximately $11.6 million in qualifying CEE expenditures related to this flow-through share commitment had been spent to December 31, 2006. The Company executed a three year contract with a large drilling contractor for the exclusive use of a specific drilling rig. Due to delays experienced, the contract commenced in December of 2006 and requires Kereco to utilize the rig for a minimum of 225 days per year. Kereco has also fixed the price on approximately 70 percent of its electricity requirements for a period which commenced on February 1, 2006 and which ends on December 31, 2008. Following are the future minimum payments required under these contracts: ($000s) Electricity contract Drilling contract ------------------------------------------------------------------------- 2007 $ 2,008 $ 3,823 2008 $ 2,008 $ 3,823 2009 $ - $ 3,504 ------------------------------------------------------------------------- ------------------------------------------------------------------------- The Company has other commitments and guarantees in the normal course of business which are not material, and are therefore not disclosed here. RISK MANAGEMENT AND HEDGING We have entered into financial and physical derivative contracts as outlined in notes 10 and 12 to the unaudited interim consolidated financial statements. These positions were undertaken in order to secure pricing on a portion of our future production and to protect against reductions in future commodity prices. We have not designated any of these financial derivative contracts as hedges and they have therefore been recorded on the balance sheet as assets or liabilities with changes in their fair value recorded in net earnings for the applicable periods. As an alternative presentation, were Kereco to have locked in the volumes currently hedged at the December 31, 2006 strip pricing for both crude oil and natural gas, over the term of those hedges, Kereco would actually realize a net $2.7 million cash gain over the term of the hedges entirely from the natural gas contracts in place. The financial and physical derivative contracts entered up to and including March 7, 2006 and as listed in note 8 and 10 to the Consolidated Financial Statements result in the following downside price protection and ceiling prices on future production: 2007 ----------------------------------- Q1 Q2 Q3 Q4 ------------------------------------------------------------------------- Natural Gas Volume (GJ/day) 12,278 14,000 14,00 7,370 Floor price (AECO CDN $/GJ) 7.44 6.79 6.79 7.00 Ceiling price (AECO CDN $/GJ) 10.73 8.79 8.79 9.72 ------------------------------------------------------------------------- Crude Oil Volume (bbls/day) 1,750 1,750 1,750 1,750 Floor price (WTI US$/bbl) 62,43 62.43 62.43 62.43 Ceiling Price (WTI US$/bbl) 88.34 88.34 88.34 88.34 ------------------------------------------------------------------------- ------------------------------------------------------------------------- 2008 ----------------------------------- Q1 Q2 Q3 Q4 ------------------------------------------------------------------------- Gas GJ/day 4,000 - - - Floor price (AECO CDN $/GJ) 7.38 - - - Ceiling price (AECO CDN $/GJ) 11.38 - - - ------------------------------------------------------------------------- Oil bbls/day 250 250 250 250 Floor price (WTI US$/bbl) 60.00 60.00 60.00 60.00 Ceiling Price (WTI US$/bbl) 77.00 77.00 77.00 77.00 ------------------------------------------------------------------------- ------------------------------------------------------------------------- DISCLOSURE CONTROLS AND PROCEDURES AND INTERNAL CONTROLS OVER FINANCIAL REPORTING In accordance with the requirements of Multilateral Instrument 52-109 of the Canadian Securities Administrators, the President and Chief Executive Officer and Vice President Finance and Chief Financial Officer performed an evaluation of Kereco's disclosure controls and procedures and have concluded that such controls and procedures are effective at December 31, 2006. Management with the participation of the Company's President and Chief Executive Officer and Vice-President Finance and Chief Financial Officer, has evaluated the design of the Company's internal controls over financial reporting. Based on that evaluation, the Company's President and Chief Executive Officer and Vice-President Finance and Chief Financial Officer have concluded that as of December 31, 2006, the Company's internal controls over financial reporting are designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial reporting for the year ended December 31, 2006 that have materially affected, or are reasonably likely to affect, the Company's internal control over financial reporting. Because of their inherent limitations, disclosure controls and procedures and internal controls over financial reporting may not prevent or detect misstatements, errors or fraud. Control systems, no matter how well conceived or operated, can provide only reasonable, not absolute assurance that the objectives of the control systems are met. CRITICAL ESTIMATES Management is required to make judgments and use estimates in the application of generally accepted accounting principles that have a significant impact on the financial results of Kereco. The following discussion outlines the accounting policies and practices that will be critical to determining Kereco's financial results. Full Cost Accounting Kereco follows the Canadian Institute of Chartered Accountants' guideline on full cost accounting in the oil and gas industry to account for oil and gas properties. Under this method, all costs associated with the acquisition of, exploration for and development of natural gas and crude oil reserves are capitalized and costs associated with production are expensed. The capitalized costs are depreciated, depleted and amortized using the unit-of-production method based on estimated proved reserves. Reserve estimates can have a significant impact on earnings, as they are a key component in the calculation of depreciation, depletion and accretion ("DD&A"). A downward revision in a reserve estimate could result in a higher DD&A charge to earnings. In addition, if net capitalized costs are determined to be in excess of the calculated ceiling, which is based largely on reserve estimates, the excess must be written off as an expense and charged against earnings. In the event of a property disposition, proceeds are normally deducted from the full cost pool without recognition of a gain or loss unless there is a change in the DD&A rate of 20 percent or greater. Asset Retirement Obligations Kereco records a liability for the fair value of legal obligation associated with the retirement of long-lived tangible assets in the period in which they are incurred, normally when the asset is purchased or developed. On recognition of the liability there is a corresponding increase in the carrying amount of the related asset and the asset retirement obligation. The total amount of the asset retirement obligation is an estimate based on the Company's net ownership interest 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 amount of the estimated cash flows required to settle the asset retirement obligation, the timing of those cash flows and the discount rate used to calculate the present value of those cash flows are estimates subject to measurement uncertainty. Any change in these estimates would impact the asset retirement liability. Reserves Determination The proved crude oil, natural gas and natural gas liquid reserves used in determining our depletion rates, the magnitude of the borrowing base available to us from our lender and the ceiling test are based upon management's best estimates, and are subject to uncertainty. Through the use of geological, geophysical and engineering data, the reservoirs and deposits of natural gas, crude oil and natural gas liquids are examined to determine quantities available for future production, given existing operating and economic conditions and technology. The evaluation of recoverable reserves is an ongoing process impacted by current production, continuing development activities and changing economic conditions as reflected in crude oil and natural gas prices and costs. Consequently, the reserves are estimates which are subject to variability. To assist with the reserve evaluation process, we employ the services of independent oil and gas reservoir engineers. Income Taxes The determination of Kereco's income and other tax liabilities requires interpretation of complex laws and regulations often involving multiple jurisdictions. All tax filings are subject to audit and potential reassessment after lapse of considerable time. Accordingly, the actual income tax liability may differ significantly from the liability estimated or recorded. Other Estimates The accrual method of accounting requires management to incorporate certain estimates including estimates of revenues, royalties and production costs as at a specific reporting date but for which actual revenues and costs have not yet been received; and estimates on capital projects which are in progress or recently completed where actual costs have not been received at a specific reporting date. Ceiling Test Under the full cost accounting method, a ceiling test is performed at least annually to ensure that the net capitalized costs in each country do not exceed the undiscounted future net revenues from proved plus probable reserves, plus the cost of unproved properties. Any excess capitalized costs will be written off as an expense and charged to earnings; however, future depletion and depreciation expense would be reduced. Good Will Goodwill is recorded when the purchase price of an acquired business exceeds the fair value of the net identifiable assets and liabilities of the acquired business. The goodwill balance is assessed for impairment by comparing the book value to the fair value of the reporting entity. If the fair value of the entity is less than the book value, impairment is deemed to have occurred. The extent of the impairment is measured by allocating the fair value of the entity to the identifiable assets and liabilities based on their fair values. Any remainder of this allocation is the implied value of goodwill, and if this excess is less than the actual goodwill recorded, an impairment exists and that difference is written off as an expense and charged to earnings. Kereco will monitor market conditions for indications of impairment on a quarterly basis. NEW ACCOUNTING STANDARDS IN 2006 AND 2007 Financial Instruments In April 2005, the Canadian Institute of Chartered Accountants issued the following new Handbook Sections: Section 1530, Comprehensive Income; Section 3251, Equity; Section 3855, Financial Instruments - Recognition and Measurement; and Section 3865, Hedges. The effective date for adoption for all four sections is for annual fiscal years beginning on or after October 1, 2006. These new accounting standards for Canadian GAAP will converge more closely with US GAAP as all financial instruments will be recorded on the balance sheet at fair value and changes in fair value will be included in earnings, except for derivative financial instruments designated as hedges, for which changes in fair value will be included in comprehensive income. The Company has not assessed the future impact these sections will have on the financial statements. RISK AND UNCERTAINTY Kereco is involved in the exploration, development, production and acquisition of petroleum and natural gas in the Western Canada Sedimentary Basin. These activities involve a number of risks and uncertainties inherent in the industry. Inherent in exploration and development are the risks, among others, of drilling dry holes, encountering production or drilling difficulties or experiencing high decline rates in producing wells. To minimize these risks, we use experienced staff to evaluate and operate wells and utilize appropriate technology in our operations. In addition, we use prudent safety programs and risk management, including insurance coverage against potential losses. We are exposed to commodity price and market risk for our principal products of petroleum and natural gas. Commodity prices are influenced by a wide variety of factors most of which are beyond our control. At times when we believe we are at risk for a significant reduction in the market price of the commodities we produce, or require a certain commodity price to fund our capital expenditure program, we may enter into contracts that provide downside price protection. We are subject to credit risk associated with the purchase of the commodities produced. In order to mitigate the risk of non-payment, we will minimize the total sales value with each particular purchaser. Kereco's expected cash flow from operations depends largely on the volume of our petroleum and natural gas production and the price received for such production, along with the associated production costs. The price we receive for oil depends on a number of factors, including WTI oil prices, Canadian/US currency exchange rates, quality differentials and Edmonton par oil prices. The price we receive for natural gas production will primarily be dependent on current Alberta market prices. Our access to markets may be restricted at times by pipeline or processing capacity. We minimize these risks by controlling as much of our processing and transportation activities as possible. The petroleum and natural gas industry is subject to extensive controls, regulatory policies and income and resource taxes imposed by various levels of government. These regulations, controls and taxation policies are amended from time to time. Kereco has no control over the level of government intervention or taxation in the petroleum and natural gas industry. However, we will operate in such a manner to ensure that we are in compliance with all applicable regulations and are able to respond to changes as they occur. The petroleum and natural gas industry is subject to both environmental regulations and an increased environmental awareness. We have reviewed our environmental risks and are in compliance with the appropriate environmental legislation and have determined that there is no current material impact on our operations. Kereco is subject to financial market risk. In order to achieve substantial rates of growth, we need to keep reinvesting in drilling for or acquiring petroleum and natural gas properties. One source of funding for our expenditure program is through the issuance of equity. If we are not able to access the equity markets due to unfavorable market conditions for an extended period of time, this may adversely impact our growth rate. In addition, Kereco utilizes bank financing and cash flow from operations to fulfill capital requirements. Kereco minimizes the financial market risk by maintaining a conservative financing structure. We are exposed to interest rate risk due to the floating nature of interest rates on our bank loan. Kereco has retained an independent engineering consulting firm that assists Kereco in evaluating recoverable amounts of oil and gas reserves. Values of recoverable reserves are based on a number of variable factors and assumptions such as commodity prices, projected production, future production costs and government regulation. Such estimates may vary from actual results. Oil and gas exploration and production can involve environmental risks such as pollution of the environment and destruction of natural habitat, as well as safety risks such as personal injury. We conduct our operations with high standards in order to protect the environment and the general public, we maintain insurance coverage for comprehensive and general liability as well as limited pollution liability. The amount and terms of this insurance are reviewed on an on going basis and adjusted as necessary to reflect current corporate requirements, as well as industry standards and government regulations. KERECO ENERGY LTD. CONSOLIDATED BALANCE SHEETS ------------------------------------------------------------------------- As at December 31 ($000s) 2006 2005 ------------------------------------------------------------------------- ASSETS Current Accounts receivable $ 41,268 $ 20,732 Prepaid expenses 3,459 1,100 Financial derivative contracts (Note 10) 4,990 - ------------------------------------------------------------------------- 49,717 21,832 Property, plant and equipment, net (Note 3) 600,964 241,056 Goodwill (Note 4) 116,730 65,379 ------------------------------------------------------------------------- Total assets $ 767,411 $ 328,267 ------------------------------------------------------------------------- ------------------------------------------------------------------------- LIABILITIES Current Accounts payable and accrued liabilities $ 51,955 $ 29,515 Bank debt (Note 5) 27,000 71,737 Financial derivative contracts (Note 10) - 208 ------------------------------------------------------------------------- 78,955 101,460 ------------------------------------------------------------------------- Bank debt - long term (Note 5) 161,673 - Asset retirement obligation (Note 7) 16,038 8,292 Future income taxes (Note 6) 29,497 7,931 ------------------------------------------------------------------------- 207,208 16,223 ------------------------------------------------------------------------- Total liabilities 286,163 117,683 ------------------------------------------------------------------------- SHAREHOLDERS' EQUITY Share capital (Note 8) 438,216 191,432 Contributed surplus (Note 8) 6,539 2,664 Retained earnings 36,493 16,488 Commitments and guarantees (Note 11) ------------------------------------------------------------------------- Total shareholders' equity 481,248 210,584 ------------------------------------------------------------------------- Total liabilities and shareholders' equity $ 767,411 $ 328,267 ------------------------------------------------------------------------- ------------------------------------------------------------------------- The accompanying notes form an integral part of these consolidated financial statements. Approved by the Board of Directors: "Signed" Grant B. Fagerheim "Signed" Gerry A. Romanzin Director Director KERECO ENERGY LTD. CONSOLIDATED STATEMENTS OF EARNINGS AND RETAINED EARNINGS ($000s, except per Three months ended Year ended share amounts) December 31(1) December 31 2006 2005 2006 2005 ------------------------------------------------------------------------- REVENUES Petroleum and natural gas sales $ 39,753 $ 36,971 $ 131,674 $ 90,728 Royalties, net of ARTC 8,292 8,659 29,029 21,301 ------------------------------------------------------------------------- 31,461 28,312 102,645 69,472 ------------------------------------------------------------------------- EXPENSES Operating 7,184 5,393 21,193 13,476 Transportation 1,221 402 4,012 1,131 General and administrative 703 515 2,080 1,882 Interest and bank charges (Note 5) 2,401 726 5,329 1,709 Realized loss (gain) on financial derivatives (Note 10) (620) 195 (1,854) 479 Unrealized loss (gain) on financial derivatives (Note 10) (2,014) (2,450) (5,198) 72 Depletion, depreciation and accretion (Note 3 & 7) 19,096 7,084 42,955 19,787 Stock-based compensation (Note 8) 1,414 1,268 4,011 2,664 ------------------------------------------------------------------------- 29,385 13,133 72,528 41,200 ------------------------------------------------------------------------- EARNINGS BEFORE INCOME TAXES 2,076 15,179 30,117 28,227 ------------------------------------------------------------------------- TAXES (Note 6) Current income taxes - 138 (224) 434 Future income taxes 2,310 5,660 10,336 11,305 ------------------------------------------------------------------------- 2,310 5,798 10,112 11,739 ------------------------------------------------------------------------- NET EARNINGS (LOSS) (234) 9,381 20,005 16,488 ------------------------------------------------------------------------- Retained earnings, beginning of year 36,727 7,107 16,488 - ------------------------------------------------------------------------- Retained earnings, end of year $ 36,493 $ 16,488 $ 36,493 $ 16,488 ------------------------------------------------------------------------- ------------------------------------------------------------------------- EARNINGS (LOSS) PER SHARE (Note 8) Basic $ (0.01) $ 0.28 $ 0.52 $ 0.58 Diluted $ (0.01) $ 0.26 $ 0.50 $ 0.56 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) Unaudited The accompanying notes form an integral part of these consolidated financial statements. KERECO ENERGY LTD. CONSOLIDATED STATEMENTS OF CASH FLOWS Three months ended Year ended December 31(1) December 31 ------------------------------------------------------------------------- (000s) 2006 2005 2006 2005 ------------------------------------------------------------------------- OPERATING ACTIVITIES Net earnings $ (234) $ 9,381 $ 20,005 $ 16,488 Add items not requiring cash: Depletion, depreciation and accretion 19,096 7,084 42,955 19,787 Provision for future income taxes 2,310 5,660 10,336 11,305 Unrealized (gain) loss on financial derivatives (2,014) (2,450) (5,198) 72 Employee common share benefit plan expense (Note 8) 20 41 117 41 Stock-based compensation 1,414 1,268 4,011 2,664 ------------------------------------------------------------------------- 20,592 20,984 72,226 50,357 Change in non- cash working capital (Note 9) (11,410) (3,109) (4,249) (8,832) ------------------------------------------------------------------------- Cash provided by operating activities (9,182) 17,875 67,977 41,525 ------------------------------------------------------------------------- FINANCING ACTIVITIES Issuance of common shares and warrants, net of share issue costs (139) - 21,069 158,522 Common shares held for employee benefit plan (Note 8) - - - (351) Bank debt 6,251 5,109 19,209 31,564 Repayment of debt assumed with Ketch Resources Ltd. Plan of Arrangement (Note 4) - - - (5,134) Change in non- cash working capital (Note 9) (1,232) (20) (1,357) (376) ------------------------------------------------------------------------- Cash provided by financing activities 4,880 5,089 38,921 184,225 ------------------------------------------------------------------------- CASH AVAILABLE FOR INVESTING ACTIVITIES 14,062 22,964 106,898 225,750 ------------------------------------------------------------------------- INVESTING ACTIVITIES Petroleum and natural gas expenditures (22,930) (20,978) (102,095) (88,207) Property acquisitions - 2,130 (7,475) 3,926 Property dispositions 10,614 (822) 10,614 (1,474) Business combinations (Note 4) (2,780) (283) (2,780) (158,772) Change in non- cash working capital (Note 9) 1,034 (3,011) (5,162) 18,777 ------------------------------------------------------------------------- Cash used in investing activities 14,062 (22,964) (106,898) (225,750) ------------------------------------------------------------------------- CASH AND CASH EQUIVALENTS, BEGINNING AND END OF YEAR $ - $ - $ - $ - ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) Unaudited The accompanying notes form an integral part of these consolidated financial statements. Notes to the Consolidated Financial Statements Years ended December 31, 2006 and 2005 (Unless otherwise stated, amounts presented in these notes are in thousands of Canadian dollars.) 1. BASIS OF PRESENTATION Kereco Energy Ltd. (the "Company" or "Kereco") has been active in oil and gas exploration and production since January 18, 2005 following a Plan of Arrangement between Ketch Resources Ltd. and Bear Creek Energy Ltd. The Arrangement was approved at meetings of security holders, and received court approval, on January 17, 2005 and was implemented on January 18, 2005. Under the Arrangement and the terms of the Kereco Conveyance Agreement dated January 18, 2005 Kereco was reorganized as a public oil and gas exploration and development company receiving interests in various producing oil and gas properties and facilities as well as interests in several undeveloped properties. The consolidated financial statements have been prepared in accordance with Canadian generally accepted accounting principles ("GAAP"). These principles require management to use estimates and assumptions that affect the reported amounts of assets and liabilities as 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. 2. SIGNIFICANT ACCOUNTING POLICIES The accounting policies of the Company are in accordance with generally accepted accounting principles in Canada. Those policies considered significant are outlined below. Principles of Consolidation The consolidated financial statements include those of the Company and its subsidiaries. Joint Venture Operations The majority of the Company's petroleum and natural gas exploration activities are conducted jointly with others. These financial statements reflect only the Company's proportionate interest in such activities. Measurement Uncertainty Amounts recorded for depletion, depreciation and accretion, goodwill, asset retirement costs and obligations, future income taxes and amounts used for impairment calculations ("ceiling test") are based on estimates of oil and natural gas reserves and future costs required to develop those reserves. By their nature, these estimates and related future cash flows are subject to measurement uncertainty, and the impact of changes in those estimates on the financial statements of future periods could be material. Property, Plant and Equipment (i) Petroleum and Natural Gas Properties The Company follows the full-cost method of accounting for petroleum and natural gas operations, whereby all costs related to the exploration and development of petroleum and natural gas reserves are capitalized on a country-by-country basis. Such costs include land acquisition costs, costs of drilling both productive and non- productive wells, well equipment, gathering line and plant costs, geological and geophysical expenses and overhead expenses directly related to exploration and development activities. Gains or losses on sales of properties are recognized only when crediting the proceeds against the recorded costs would result in a change of 20 percent or more in the depletion and depreciation rate. Capitalized costs plus estimated future capital costs are depleted using the unit-of-production method based on estimated proven reserves of petroleum and natural gas before royalties as determined by independent petroleum engineers. Costs relating to unproved properties are excluded from costs subject to depletion and depreciation until it is determined whether or not proved reserves exist or if impairment occurs. Proved natural gas reserves and production are converted to equivalent volumes of crude oil based on the basis of six thousand cubic feet of natural gas to one barrel of crude oil equivalent. Depreciation of gas plants and related facilities is calculated on a straight-line basis over periods ranging from 10 to 40 years. The net book value of the Company's petroleum and natural gas properties and equipment is subject to a ceiling test. 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 Company's proved reserves. If the carrying value is not fully recoverable, the amount of impairment is measured by comparing the carrying amount of property, plant and equipment to an amount equal to the estimated net present value of future cash flows from proved plus probable reserves. This calculation 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 expensed immediately. (ii) Asset Retirement Obligations The Company recognizes the estimated liability associated with an asset retirement obligation ("ARO") in the financial statements at the time the liability is incurred. The estimated fair value of the ARO is recorded as a long-term liability, with a corresponding increase in the capitalized amount of the related asset. The capitalized amount is depleted on a unit-of-production method over the life of the proved reserves. The liability amount is increased each reporting period due to the passage of time, and therefore as the reserves are produced, and the amount of accretion is charged to earnings in the period. The ARO can also periodically increase or decrease due to changes in the estimates of timing of cash flows or changes in the original estimated undiscounted cost. Actual costs incurred upon settlement of the ARO are charged against the ARO to the extent of the liability recorded. (iii) Office Furniture, Equipment and Leaseholds Office furniture, equipment and leaseholds are recorded at the lower of cost less accumulated amortization or fair value. Office furniture and equipment is depreciated on a declining-balance method at annual rates of 10 to 33 percent. Leasehold improvements are depreciated over the remaining lease term. Income Taxes The Company follows the liability method of accounting for income taxes. Under this method, the Company records future income taxes based on the differences between the book value and the income tax value of its assets and liabilities, as temporary differences, using substantively enacted income tax rates that are expected to apply in the year in which the temporary differences are estimated to reverse. Income tax assets are also recognized for the benefits from tax losses and deductions with no accounting basis provided those benefits are more likely than not to be realized. Future income tax assets and liabilities are determined based on the tax laws and rates that are anticipated to apply in the period of estimated realization. Stock-Based Compensation Plan The Company follows the fair-value method of accounting for stock options granted and initial private placement share purchase warrants issued to employees, officers and directors. Fair value is determined at the grant date using the Black-Scholes option-pricing model and recognized over the vesting periods of the options granted and the share purchase warrants issued as stock-based compensation expense with a corresponding credit to contributed surplus. The contributed surplus balance is reduced as the options are exercised with the amount initially recorded being credited to share capital. Revenue Recognition Revenues from the sale of crude oil, natural gas and natural gas liquids are recorded when title transfers to an external party. Financial Instruments The accounts receivable, accounts payable and accrued liabilities, bank debt and financial derivative contracts are financial instruments. It is management's opinion that the Company is not exposed to significant interest, currency or credit risks arising from these financial instruments. The fair values of these financial instruments approximate their carrying values, unless otherwise noted, due to their short terms to maturity or floating interest rates. 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 stock method assumes that proceeds from the exercise of "in-the-money" stock options and warrants, net of "in-the-money" unamortized stock based compensation expense, is used to re-purchase common shares at the average market price over the period. Hedging Relationships and Financial Derivative Contracts Kereco applies Accounting Guideline 13 - Hedging Relationships, which deals with the identification, designation, documentation and effectiveness of hedging relationships for the purpose of applying hedge accounting. Where hedge accounting does not apply, any changes in the fair value of the financial derivatives contracts relating to a financial period can either reduce or increase net earnings for that period. Kereco enters into financial derivative contracts to manage commodity price and foreign exchange risk. Kereco has elected to not apply hedge accounting and to follow the fair value accounting method for all financial instruments. Goodwill Goodwill is the residual amount that results when the purchase price of an acquired business exceeds the fair value of the net identifiable assets and liabilities of the acquired business. Goodwill is stated at cost less impairment and is not amortized. The goodwill balance is assessed for impairment each year-end or more frequently if events or changes in circumstances indicate that the asset may be impaired. The test for impairment is conducted by comparing the book value to the fair value of the reporting entity. If the fair value of the Company is less than the book value, impairment is deemed to have occurred. The extent of the impairment is measured by allocating the fair value of the Company to the identifiable assets and liabilities at their fair values. Any remainder of this allocation is the implied value of goodwill. Any excess of the book value of goodwill over this implied value is the impairment amount. Impairment is charged to income in the period in which it is determined to occur. Flow-Through Shares The resource expenditure deductions for income tax purposes related to exploratory activities funded by flow-through share arrangements are renounced to investors in accordance with applicable tax legislation. The future income liability associated with the flow- through shares is recognized by the Company when the tax credits are renounced. Share capital is reduced and the future income tax liability is increased by the tax related to the renounced tax deductions. 3. PROPERTY, PLANT AND EQUIPMENT As at December 31 2006 --------------------------------------------------------------------- Accumulated Depletion, and Net Book Cost Depreciation Value Petroleum and natural gas properties $ 661,581 $ 61,521 $ 600,060 Office equipment & corporate 1,102 198 904 --------------------------------------------------------------------- Total $ 662,683 $ 61,719 $ 600,964 --------------------------------------------------------------------- --------------------------------------------------------------------- As at December 31 2005 --------------------------------------------------------------------- Accumulated Depletion, and Net Book Cost Depreciation Value Petroleum and natural gas properties $ 259,888 $ 19,366 $ 240,522 Office equipment & corporate 593 59 534 --------------------------------------------------------------------- Total $ 260,481 $ 19,425 $ 241,056 --------------------------------------------------------------------- --------------------------------------------------------------------- The Company capitalized $0.8 million of indirect general and administrative overhead in 2006 (2005 - $0.2 million). $51.4 million of undeveloped land was excluded from the year end depletion calculation in 2006 (2005 - $28.3 million). The Company closed property acquisitions and dispositions with other oil and gas companies totaling a net $7.5 million and $10.6 million respectively in 2006 (2005 - $3.9 million and $1.5 million respectively). The Company had no impairment under the December 31, 2006 year end ceiling test using the following reference prices from the December 31, 2006 GLJ Petroleum Consultants reserve report: 2007 2008 2009 2010 2011 2012 ------------------------------------------------------------- WTI (Oil) ($US/bbl) 62.00 60.00 58.00 57.00 57.00 57.50 AECO (Gas) ($Can/mcf) 7.20 7.45 7.75 7.80 7.85 8.15 2013 2014 2015 2016 2017 2018+ --------------------------------------------------------------------- WTI (Oil) ($US/bbl) 58.50 59.75 61.00 62.25 63.50 63.50 + 2.0%/yr AECO (Gas) ($Can/mcf) 8.30 8.50 8.70 8.90 9.10 9.10 + 2.0%/yr 4. BUSINESS COMBINATIONS Chamaelo Exploration Ltd. On October 19, 2006, Kereco acquired all of the common shares of Chamaelo Exploration Ltd., a publicly traded Company listed on the Toronto Stock Exchange. The acquisition was financed through the issuance of 20,080,034 Kereco common shares to the former shareholders of Chamaelo Exploration Ltd which exchanged each Chamaelo common share into 0.51 of a Kereco common share. The 20,080,034 common shares issued were valued at $11.49 per share based on the five day average trading price on the announcement date of the transaction on August 17, 2006. The acquisition has been accounted for using the purchase method and the purchase price has been allocated to the fair value of the assets acquired and liabilities assumed as follows: ($000s) Cost of Acquisition --------------------------------------------------------------------- Issuance of common shares $ 230,720 Transaction costs 2,780 --------------------------------------------------------------------- $ 233,500 --------------------------------------------------------------------- --------------------------------------------------------------------- Allocation of Purchase Price --------------------------------------------------------------------- Property, plant and equipment $ 302,397 Goodwill 51,351 Accounts receivable 10,870 Prepaid expenses 705 Asset retirement obligation (6,235) Future income tax liability (5,974) Accounts payable and accrued liabilities (21,887) Bank debt (97,727) --------------------------------------------------------------------- $ 233,500 --------------------------------------------------------------------- --------------------------------------------------------------------- The above allocation of purchase price is based on the best available information at this time and could be subject to change. Chariot Energy Inc. On April 19, 2005, Kereco acquired all of the common shares of a private company (Chariot Energy Inc. or "Chariot") for cash consideration of $156,428,000, assumed debt and working capital of $29,725,000, and the issuance of 200,000 non-voting Kereco common shares with an ascribed value of $10.23 per share totaling $2,046,000. Kereco funded the cash portion of the acquisition from the proceeds received on April 19, 2005 from a private placement of 13 million Kereco common shares at a price of $11.00 per share (total proceeds of $143 million, before issue costs of $7.3 million) and from arranged bank financing. Prior to December 31, 2005 the former shareholders of Chariot agreed with Kereco upon the final working capital settlement resulting in an additional $200,000 in cash paid to Chariot. The acquisition has been accounted for using the purchase method and the purchase price was allocated to the fair value of the assets acquired and liabilities assumed as follows: ($000s) Cost of Acquisition: --------------------------------------------------------------------- Cash paid $ 156,428 Shares issued to vendor 2,046 Transaction costs 647 --------------------------------------------------------------------- $ 159,121 --------------------------------------------------------------------- --------------------------------------------------------------------- Allocation of Purchase Price: --------------------------------------------------------------------- Property, plant and equipment $ 143,278 Goodwill 65,379 Accounts receivable 4,953 Prepaid expenses 561 Asset retirement obligation (4,737) Future income tax liability (6,378) Accounts payable and accrued liabilities (3,626) Bank debt (40,173) Financial derivative contracts (136) --------------------------------------------------------------------- $ 159,121 --------------------------------------------------------------------- --------------------------------------------------------------------- KETCH RE

SOURCES LTD. PLAN OF ARRANGEMENT In conjunction with the January 17, 2005 Plan of Arrangement, Ketch transferred the Kereco Assets on January 18, 2005. At the time of the transaction, the companies were considered to be related, and consequently, the assets were transferred to Kereco at their carrying value. At that time, a future income tax asset of $7.0 million was recorded due to transferring tax pools of $48.0 million, which were in excess of the net book value consideration of $29.6 million and an asset retirement obligation of $1.4 million. Consideration: Common shares issued $ 28,392 Cash 1,696 --------------------------------------------------------------------- Total consideration $ 30,088 --------------------------------------------------------------------- --------------------------------------------------------------------- Assets transferred: Petroleum and natural gas properties $ 29,629 Future income tax asset 6,968 Asset retirement obligation (1,375) --------------------------------------------------------------------- Total assets transferred 35,222 Bank indebtedness assumed (5,134) --------------------------------------------------------------------- Net assets transferred and reduction in capital $ 30,088 --------------------------------------------------------------------- --------------------------------------------------------------------- 5. BANK DEBT At December 31, 2006 the Company had in place a syndicated committed credit facility, in the amount of $198 million, with two major Canadian Chartered Banks and the Canadian branch of a major international bank. Interest on this facility is charged at monthly rates and borrowings can be made in Canadian or U.S. dollars. Borrowings can also be made by way of prime rate advances or Banker's Acceptances which attract interest at increments to prime based on the Company's debt/cash flow ratio, calculated utilizing the two most recent fiscal quarters. The Company has provided a $500 million demand fixed and floating charge debenture as collateral for the facility. As at December 31, 2006, $188.7 million (December 31, 2005, $71.7 million) had been drawn under the bank facility. The average interest rate on borrowings outstanding for the year was 5.48 percent, totaling $5.3 million in interest expense (December 31, 2005 - 4.10 percent and $1.7 million in interest expense). $162 million of the balance outstanding under the credit facility is not due within 12 months and is therefore presented as a long term liability. $27 million of the balance under the credit facility is potentially repayable within 12 months and is therefore presented as current on the balance sheet. Subsequent to December 31, 2006, the credit facility was reduced from $198 million to $183 million. This reduction was the result of the effect of two minor property dispositions and a flow-through share financing subsequent to year end. This reduction is not related to the annual review of our credit facility currently being conducted by the syndicate of lenders, expected to be completed by the first week of April 2007. 6. INCOME TAXES Total tax expense for the year was $10.1 million, $10.3 million of future income taxes and a recovery of $0.2 million of current income tax recoveries (December 31, 2005: $11.7 million, $11.3 million of future income taxes and $0.4 million of current income tax). This results in an effective tax rate of 34 percent for the year compared to a rate of 42 percent for 2005. This decrease in the effective tax rate is mainly a result of the reduced federal and provincial corporate tax rates which were substantively enacted in 2006. The provision for income taxes in the Consolidated Statement of Earnings and Retained Earnings differs from that which would be expected by applying the applicable statutory tax rates. Differences for the respective periods are as follows: 2006 2005 --------------------------------------------------------------------- Earning before income taxes $ 30,117 $ 28,227 Statutory income tax rate (%) 34.50 37.62 --------------------------------------------------------------------- Expected income taxes 10,390 10,619 Effect on income taxes of: Non-deductible crown charges 3,211 4,938 Resource allowance (2,822) (4,263) Statutory rate change (910) (892) Stock-based compensation 1,384 1,003 Alberta Royalty Tax credit 60 109 Change due to adjustment of opening tax pools (1,018) (165) Other 41 (44) --------------------------------------------------------------------- Provision for future income taxes 10,336 11,305 --------------------------------------------------------------------- Current income tax (224) 434 --------------------------------------------------------------------- Provision for taxes $ 10,112 $ 11,739 --------------------------------------------------------------------- --------------------------------------------------------------------- --------------------------------------------------------------------- The future income tax liability is comprised of the following: 2006 2005 --------------------------------------------------------------------- Property, plant and equipment $ 41,871 $ 24,952 Asset retirement obligation (4,650) (2,798) Non capital losses (4,439) (10,855) Financial derivative contract 1,602 (78) ACRI (1,280) (977) Share issue costs (3,607) (2,313) --------------------------------------------------------------------- Future income tax liability $ 29,497 $ 7,931 --------------------------------------------------------------------- --------------------------------------------------------------------- At December 31, 2006, the Company had tax pools and non-capital losses of approximately $465.9 million, comprised of $32.7 million in Canadian Exploration Expense (CEE) ($44.3 million less $11.6 million of estimated qualifying flow-through share eligible expenditures), $229.6 million in Canadian Oil & Gas Property Expense (COGPE), $98.5 million in Canadian Development Expense (CDE), and $90.6 million Capital Cost Allowance (CCA) pools as well as accumulated non-capital losses for income tax purposes of approximately $14.5 million (2005 - $30.4 million) that can be used to offset otherwise taxable income in future periods. The remaining non-capital losses, after deductions taken to date, amount to $14.5 million and expire as follows: --------------------------------------------------------------------- Year of expiry ($millions) --------------------------------------------------------------------- 2010 $ 9.2 2015 5.3 --------------------------------------------------------------------- $ 14.5 --------------------------------------------------------------------- --------------------------------------------------------------------- In addition to the above losses and tax pools, the Company also has accumulated capital losses of approximately $21.5 million (2005 - $21.5 million) as well as research and development tax credits of approximately $2.0 million (2005 - $2.0 million) which will expire at various times up to the end of 2013. Cash tax paid for the year ended December 31, 2006 was $Nil. On June 8, 2005 the Company issued 1,200,000 flow-through common shares for gross proceeds of $16.8 million before issue costs of $0.9 million. As of March 31, 2006 the entire $16.8 million of qualifying expenditures had been spent and renounced and the related tax impact of $5.7 million has been recorded as a reduction to share capital. On June 9, 2006 the Company issued 1,500,000 flow-through common shares for gross proceeds of $22.0 million before issue costs of $1.2 million. The related tax impact will be recorded when the tax expenditures are renounced to shareholders. Approximately $11.6 million in qualifying CEE expenditures related to this flow- through share commitment have been incurred as of December 31, 2006. See note 12 for subsequent events regarding a flow-through common share offering which closed subsequent to year end. 7. ASSET RETIREMENT OBLIGATION The Company has recorded an asset retirement obligation associated with the present value of the estimated future costs to abandon its petroleum and natural gas properties. To determine this obligation, the Company used an inflation rate of two percent and a credit- adjusted risk-free interest rate of seven percent to discount the future estimated cash flows of $42.2 million, which will be paid over a period ranging from two to forty-five years with the majority of costs being incurred between 12 and 16 years. The December 31, 2006 asset retirement obligation is comprised of the following: 2006 2005 --------------------------------------------------------------------- Balance at January 1, $ 8,292 $ - New liabilities added 735 888 Liabilities transferred to Kereco per the Ketch plan of arrangement - 1,375 Liabilities added from Chariot acquisition - 4,737 New liabilities added from Chamaelo acquisition 6,235 - Changes in estimates 393 1,110 Disposition of liabilities (278) (180) Accretion of asset retirement obligation 661 362 --------------------------------------------------------------------- Balance at December 31, $ 16,038 $ 8,292 --------------------------------------------------------------------- --------------------------------------------------------------------- 8. SHARE CAPITAL i) Issued and Outstanding Common Shares ------------------------------------------------------------------------- Class A Common Amount Common Common Non-Voting Total ($) ------------------------------------------------------------------------- Balance at end of year, December 31, 2004 1,153,846 - - 1,153,846 - Issued pursuant to a private placement - January 14, 2005 384,616 - - 384,616 1,000 Issued pursuant to a private placement - January 18, 2005 - - 2,307,692 2,307,692 6,000 Exchanged pursuant to the January 18, 2005 Agreement (1,538,462) 1,538,462 - - - Issued pursuant to the January 18, 2005 Arrangement - 15,469,424 - 15,469,424 28,392 Issued under equity offering - 13,000,000 - 13,000,000 143,000 Issued to Chariot shareholders - - 200,000 200,000 2,046 Share issue costs - - - - (8,279) Tax effect of share issue costs - - - - 2,783 Issued pursuant to flow-through share offering - 1,200,000 - 1,200,000 16,800 Common shares held for employee benefit plan - - - - (310) ------------------------------------------------------------------------- Balance at the end of December 31, 2005 - 31,207,886 2,507,692 33,715,578 191,432 ------------------------------------------------------------------------- Issued in conjunction with the acquisition of Chamaelo - 20,080,034 - 20,080,034 230,720 Issued pursuant to exercise of options and warrants - 40,820 - 40,820 443 Fair value of options exercised - - - - 137 Amortization of common shares held for employee benefit plan - - - - 117 Tax effect of flow-through shares - - - - (5,668) Conversion of common non-voting shares to common - 2,507,692 (2,507,692) - - Issued pursuant to flow-through share offering - 1,500,000 - 1,500,000 21,975 Share issue costs - - - - (1,350) Tax effect of share issue costs - - - - 410 ------------------------------------------------------------------------- Balance at the end of December 31, 2006 - 55,336,432 - 55,336,432 438,216 ------------------------------------------------------------------------- ------------------------------------------------------------------------- ii) Flow-through Common Shares On June 8, 2005 the Company issued 1,200,000 flow-through common shares for gross proceeds of $16.8 million before issue costs of $0.9 million. As of December 31, 2006 the entire $16.8 million of qualifying expenditures had been spent and renounced and the related tax impact of $5.7 million has been recorded as a reduction to share capital. On June 9, 2006 the Company issued 1,500,000 flow-through common shares for proceeds of $22.0 million before issue costs of $1.2 million. The related tax impact of the flow-through shares will be recorded when the tax expenditures are renounced to shareholders. See note 12 for subsequent events regarding a flow-through common share offering which closed subsequent to year end. iii) Share Purchase Warrants In conjunction with the private placement of non-voting shares to employees, officers and directors on January 18, 2005, each of the 2,507,692 common shares issued carried with them 0.83 share purchase warrants to purchase in the future one common share at a price of $3.12 per share. On issuance, the share purchase warrants were attributed a fair market value totaling $1.8 million that will be recognized as stock-based compensation expense over the vesting period of the warrants. The fair value of $0.96 for each warrant was determined as of the date they were issued using the Black-Scholes method with the following assumptions: risk free interest rate - 3.25 percent, expected life - 4 years and volatility - 33 percent and dividend yield - nil. No estimate has been made for forfeitures as they will be addressed when they occur. There are a total of 1,913,583 of these warrants outstanding which vest as follows: one- half on the second anniversary of the issue date and the remaining one-half on the third anniversary of the issue date one-half of which were exercisable as of December 31, 2006. In conjunction with the Chamaelo acquisition, 3,740,710 warrants held by previous officers, directors and employees of Chamaelo were converted at an exchange rate of 0.51 into 1,907,762 (1,907,609 are outstanding at December 31, 2006) warrants exercisable into Kereco common shares. The weighted average post conversion exercise price of these warrants is $10.09 per warrant. Expiry Date Number of Exercise Contractual Warrants Warrants Price Life Exercisable (000s) ($/share) (years) (000s) --------------------------------------------------------------------- April 13, 2007 32 4.61 0.3 32 January 18, 2008 957 3.12 1.0 - January 18, 2009 957 3.12 2.0 - May 26, 2009 306 4.12 2.4 306 June 21, 2010 1,569 11.37 3.5 1,569 --------------------------------------------------------------------- 3,821 6.60 2.4 1,907 --------------------------------------------------------------------- --------------------------------------------------------------------- iv) Stock-Based Compensation The Company has a stock-based compensation plan under which options to purchase common shares of the Company have been granted to employees, officers and directors. Under the plan, all options awarded have a maximum term of five years, and vest over a three year period at a rate of one-third per year. The plan currently has 5,533,647 common shares reserved for issuance upon the exercise of options, of which 3,650,300 options were granted as at December 31, 2006. Weighted Weighted Average Average Number Exercise Contractual Of Options Prices Life (000s) ($/share) (years) --------------------------------------------------------------------- Balance at December 31, 2005 2,489 10.86 3.5 Granted 2,276 9.71 4.6 Exercised (41) (10.90) 2.3 Expired or cancelled (1,074) (10.18) 4.4 --------------------------------------------------------------------- Balance December 31, 2006 3,650 10.34 3.7 --------------------------------------------------------------------- --------------------------------------------------------------------- Compensation expense for options granted and share purchase warrants issued by the Company is based on the estimated fair values at the time of the grant and is recognized as expense over the vesting periods of the options and share purchase warrants. The Company recognized $4.0 million for non-cash stock-based compensation expense in 2006 (2005 - $2.7 million) with an equal amount recorded in contributed surplus. The fair value of each option and share purchase warrant was determined as at each stock option grant date using the Black-Scholes model with the following assumptions: risk free interest rate - 3.25 percent, expected life - 4 years, and volatility - 33 percent. The weighted average fair value of the options was $3.25 per option. No estimate has been made for expected forfeitures as they are addressed when they occur. Additional details on the Company's stock options outstanding at December 31, 2006 are as follows: Range of Exercise Weighted Weighted Prices Average Average ($/share) Number of Exercise Contractual Options Options Price Life Exercisable (000s) ($/share) (years) (000s) --------------------------------------------------------------------- 7.75 - 8.93 725 8.77 4.8 0 9.55 - 10.50 1,578 9.89 3.2 515 10.94 - 11.80 1,124 11.18 3.9 161 13.80 - 16.50 223 14.42 3.6 72 --------------------------------------------------------------------- 7.75 - 16.50 3,650 10.34 3.7 748 --------------------------------------------------------------------- --------------------------------------------------------------------- v) Employee Benefit Plan During the third quarter of 2005, the Company created an employee benefit plan under which Kereco common shares have and will from time to time be purchased on behalf of certain employees. These shares will be given to certain employees, on the basis of one third per year, over a period not exceeding three years. To date 23,950 common shares have been purchased for the plan at an average price of $14.67 per common share. Of the 23,950 common shares, 7,293 were issued to certain employees in the third quarter of 2006 and 16,657 are being held in trust. The purchase of the shares is recorded as a reduction to shareholder's equity at the purchased value of the common shares of $0.4 million and will be amortized to general and administrative expense evenly over the three year vesting period. At December 31, 2006, $117 has been expensed and recorded to share capital(December 31, 2005: $41). vi) Per Share Amounts The calculation of basic and diluted net earnings per share is based on the weighted average number of common shares outstanding as shown in the table below: Year ended Year ended December 31, December 31, 2006 2005 --------------------------------------------------------------------- Net earnings $ 20,005 $ 16,488 Net earnings per share Basic $ 0.52 $ 0.58 Diluted $ 0.50 $ 0.56 Weighted average shares outstanding Basic 38,610,662 28,335,221 Options and warrants 1,373,198 1,013,887 --------------------------------------------------------------------- Diluted 39,983,860 29,349,108 Common shares outstanding --------------------------------------------------------------------- Basic 55,336,432 33,715,578 Options and warrants 7,471,492 4,408,982 --------------------------------------------------------------------- Diluted 62,807,924 38,124,560 --------------------------------------------------------------------- --------------------------------------------------------------------- 9. SUPPLEMENTAL CASH FLOW INFORMATION i) Changes in Non-Cash Working Capital Three months ended Year ended December 31, December 31, 2006 2005 --------------------------------------------------------------------- Decrease (increase) in non-cash working capital: Accounts receivable $ (9,666) $ (15,779) Prepaid expenses (1,655) (539) Accounts payable and accrued liabilities 553 25,887 --------------------------------------------------------------------- Change in non-cash working capital $ (10,768) $ 9,569 --------------------------------------------------------------------- Relating to: Operating activities $ (4,249) $ (8,832) Financing activities (1,357) (376) Investing activities (5,162) 18,777 --------------------------------------------------------------------- Change in non-cash working capital $ (10,768) $ 9,569 --------------------------------------------------------------------- --------------------------------------------------------------------- ii) Other Cash Flow Information Year ended Year ended December 31, December 31, 2006 2005 --------------------------------------------------------------------- Cash taxes paid $ - $ - Cash interest paid $ 5,329 $ 1,709 --------------------------------------------------------------------- --------------------------------------------------------------------- 10. RISK MANAGEMENT The Company's financial instruments recognized in the consolidated balance sheet consists of accounts receivable, accounts payable and accrued liabilities, financial derivatives and bank debt. The estimated fair values of financial instruments approximate their carrying values, due to their short term nature and the floating interest rate on the Company's debt. The Company has not designated any of these financial contracts as hedges 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. At December 31, 2006 the Company recognized a financial derivative contract asset of $5.0 million (December 31, 2005 - liability of $0.2 million). The following financial derivative and physical sales contracts were outstanding on December 31, 2006: Pricing Period Volume Type terms (1) --------------------------------------------------------------------- Natural Gas Apr 1, 2007 - Financial $6.50 - $8.30 Oct 31, 2007 2,000 GJ/day Collar (AECO CDN$/GJ) Jan 1, 2007 - Physical $7.50 - $12.50 Mar 31,2007 3,000 GJ/day Collar (AECO CDN$/GJ) Jan 1, 2007 - Financial $7.78 - $13.42 Mar 31,2007 4,500 GJ/day Collar (AECO CDN$/GJ) Apr 1, 2007 - Financial $6.83 - $8.87 Oct 31,2007 12,000 GJ/day Collar (AECO CDN$/GJ) Crude Oil Jan 1, 2007 - Financial $60.00 - $75.00 Dec 31, 2007 250 bbls/day Collar (WTI US$/BBL) Jan 1, 2007 - Financial $62.83 - $90.57 Dec 31, 2007 1,500 bbls/day Collar (WTI US$/BBL) Jan 1, 2008 - Financial $60.00 - $77.00 Dec 31, 2008 250 bbls/day Collar (WTI US$/BBL) --------------------------------------------------------------------- (1) Collar price indicates minimum floor and maximum ceiling. Kereco is exposed to commodity price fluctuations of crude oil and natural gas and manages a portion of this risk by entering into forward contracts. The Company is exposed to credit risk due to the potential non-performance by counter parties to these contracts. Kereco mitigates this risk by dealing with only well established marketing companies or major chartered banks. The Company deals with customers in the oil and gas industry and is subject to normal industry credit risks. The Company is exposed to interest rate risk due to the floating nature of the interest rates on its bank loan. 11. COMMITMENTS AND GUARANTEES On June 9, 2006, the Company issued 1,500,000 flow-through common shares for proceeds of $22 million which requires the Company to incur spend $22.0 million of flow-through share eligible Canadian Exploration Expenditures ("CEE"), as defined in the Canadian Income Tax Act, by December 31, 2007. Approximately $11.6 million in qualifying CEE expenditures related to this flow-through share commitment had been spent to December 31, 2006. The Company executed a three year contract with a large drilling contractor for the exclusive use of a specific drilling rig. The contract commenced in December of 2006 and requires Kereco to utilize the rig for a minimum of 225 days per year. Kereco has also fixed the price on approximately seventy percent of its electricity requirements for a period which commenced on February 1, 2006 and which ends on December 31, 2008. Following are the future minimum payments required under these contracts: Electricity Drilling ($000s) contract contract --------------------------------------------------------------------- 2007 $ 2,008 $ 3,823 2008 $ 2,008 $ 3,823 2009 - $ 3,504 The Company has other commitments and guarantees in the normal course of business which are not material, and are therefore not disclosed here. 12. SUBSEQUENT EVENTS Subsequent to December 31, 2006, the Company entered into additional financial derivative contracts to mitigate its exposure to future fluctuations in natural gas and crude oil commodity prices as follows: Period Volume Type Pricing terms --------------------------------------------------------------------- Natural Gas Nov 1,2007 - Financial $7.38 - $11.38 Mar 31, 2008 4,000 GJ/day Collar (AECO CDN$/GJ) Feb 1, 2007 - $7.50 Feb 28, 2007 6,500 GJ/day Fixed Price (AECO CDN$/GJ) Mar 1, 2007 - $7.11 Mar 31, 2007 8,000 GJ/day Fixed Price (AECO CDN$/GJ) (1) Collar price indicates minimum floor and maximum ceiling. On February 16, 2007, the Company issued 2,250,000 flow-through common shares for proceeds of $19,350,000 which will require the Company to incur $19,350,000 of flow-through share eligible Canadian Exploration Expenditures, as defined in the Canadian Income Tax Act, by December 31, 2008. Management and the board of directors approved an arrangement which will involve the cancellation of approximately 2.4 million stock options previously granted to non-insiders under the existing Kereco stock option plan. It is expected that these stock options will be re-granted to non-insiders of the Company during the month of June at a price to be determined at that time. 13. CONTINGENCIES The Company has been served with three statements of claim totaling $3.6 million. The Company has not provided for these claims in the financial statements as it is believed the Company will be successful in defending all of them. In the unlikely circumstances that the Company is not successful in defending these claims, there is in place adequate insurance coverage to mitigate any losses which may result. CORPORATE INFORMATION Kereco Energy Ltd. is a Canadian energy company engaged in the exploration, development and production of natural gas and crude oil. The Company's common shares are listed on the Toronto Stock Exchange under the trading symbol "KCO". OFFICERS BANKERS Christopher S. Barton Bank of Montreal Vice President, Exploration Calgary, Alberta Grant B. Fagerheim Canadian Imperial Bank of Commerce President and Chief Calgary, Alberta Executive Officer Nathan R. MacBey Société Générale (Canada Branch) Vice President, Negotiations Calgary, Alberta David M. Mombourquette Vice-President, Business Development ENGINEERING CONSULTANTS Stephen C. Nikiforuk GLJ Petroleum Consultants Ltd. Vice President, Finance and Calgary, Alberta Chief Financial Officer Anthony (Tony) L. Smith LEGAL COUNSEL Vice President, Land Burnet Duckworth & Palmer LLP Kirby J. Wanner Calgary, Alberta Chief Operating Officer REGISTRAR AND TRANSFER AGENT Computershare Trust Company of Canada DIRECTORS Calgary, Alberta Daryl E. Birnie WARRANT AGENT J. Paul Charron Valiant Trust Company Grant B. Fagerheim Calgary, Alberta Daryl H. Gilbert Barry M. Heck STOCK EXCHANGE LISTING Brian M. Krausert Peter J. Kurceba Toronto Stock Exchange Gerry A. Romanzin Trading Symbol "KCO" Grant A. Zawalsky AUDITORS HEAD OFFICE Deloitte & Touche LLP Chartered Accountants 1400, 530 - 8th Avenue SW Calgary, Alberta Calgary, Alberta T2P 3S8 Telephone: (403) 290-3400 Facsimile: (403) 290-3447 Email: info@kereco.com Website: www.kereco.com ABBREVIATIONS AECO Alberta Energy Company Mcf thousand cubic feet interconnect with the mcf/day thousand cubic feet per day Nova System mmbbls million barrels ARTC Alberta Royalty Tax mmboe million barrels of oil Credit equivalent Bbls barrels mmbtu million British thermal bbls/day barrels per day units Bcf billion cubic feet mmcf million cubic feet Boe barrels of oil mmcf/day million cubic feet per day equivalent MWh Mega watt hour (6mcf = 1bbl) NGLs natural gas liquids boe/day barrels of oil NI Canadian Securities equivalent per day Administrator's National GJ gigajoule Instrument GJ/day gigajoule per day WI Working Interest kWh Kilo watt hour WTI West Texas Intermediate Mbbls thousand barrels Mboe thousand barrels of oil equivalent mboe/day thousand barrels of oil equivalent per day %SEDAR: 00021661E

For further information:

For further information: Grant B. Fagerheim, President and Chief
Executive Officer, Telephone (403) 290-3401

Organization Profile

KERECO ENERGY LTD.

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