Kereco Energy Ltd. Announces Second Quarter 2007 Results



    CALGARY, Aug. 7 /CNW/ - Kereco Energy Ltd. ("Kereco") or the ("Company")
is pleased to announce operational and financial results for the second
quarter and first half of 2007.

    
    FINANCIAL AND OPERATING HIGHLIGHTS

    -------------------------------------------------------------------------
    FINANCIAL                   Three months               Six months
    ($000s, unless              ended June 30             ended June 30
     otherwise                                  %                          %
     indicated)            2007     2006   Change     2007     2006   Change
    -------------------------------------------------------------------------
    Petroleum and
     natural gas sales   49,522   29,387       69   92,557   60,657       53
    Funds flow from
     operations          22,299   16,690       34   44,273   34,212       29
      Per share
       - basic ($)         0.39     0.49      (20)    0.77     1.01      (24)
      Per share
       - diluted ($)       0.38     0.48      (21)    0.76     0.97      (22)
    Net earnings          2,547    7,765      (67)     613   13,233      (95)
      Per share
       - basic ($)         0.04     0.23      (83)    0.01     0.39      (97)
      Per share
       - diluted ($)       0.04     0.22      (82)    0.01     0.38      (97)
    Capital expenditures
      Exploration and
       development       19,374   25,957      (25)  50,421   53,695       (6)
      Net acquisitions
       and dispositions  30,744        -      100   30,744        -      100
    -------------------------------------------------------------------------
      Total              50,118   25,957       93   81,165   53,695       51
    -------------------------------------------------------------------------
    Bank debt           151,892   74,284      105  151,892   74,284      105
    Working capital
     deficiency
     (surplus)(1)        (4,786)   3,381     (241)  (4,786)   3,381     (241)
    -------------------------------------------------------------------------
    Total net
     debt(2)            147,106   77,665       89   147,106  77,665       89
    -------------------------------------------------------------------------
    Shareholders'
     equity             512,814  241,371      112  512,814  241,371      112
    Common shares
     outstanding at
     the end of period
     (000s)
      Basic              57,777   35,256       64   57,777   35,256       64
      Diluted            66,046   40,138       65   66,046   40,138       65
    Weighted average
     common shares
     outstanding (000s)
      Basic              57,775   34,119       69   57,144   33,923       69
      Diluted            58,820   35,104       68   58,170   35,128       66
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    OPERATING
     HIGHLIGHTS(3)

    Average daily
     production
      Natural gas
       (mcf/day)         29,396   14,660      101   27,355   15,782       73
      Crude oil
       and NGLs
       (bbls/day)         4,617    3,015       53    4,418    3,026       46
      Barrels of oil
       equivalent
       (boe/day)          9,517    5,458       74    8,977    5,656       59
    Average selling
     prices(4)
      Natural gas
       ($/mcf)              7.79     6.39       22     7.91     7.52       5
      Crude oil and
       NGLs ($/bbl)        65.82    71.81       (8)   64.07    68.27      (6)
      Barrels of oil
       equivalent
       ($/boe)             55.99    56.82       (1)   55.64    57.51      (3)
    Wells drilled (No.)
      Gross                  6.0      8.0      (25)    19.0     17.0      12
      Net                    5.0      6.7      (25)    14.9     12.2      22
      Success (%)             83      100      (17)      79       82      (4)
    Undeveloped land
     (000s of acres)
      Gross                  351      151      132      351      151     132
      Net                    238       91      162      238       91     162
    Average working
     interest (%)             68       60       13       68       60      13
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Excluding financial derivative contracts.
    (2) Net debt - excludes debt associated with the $70 million
        principal amount of convertible debentures issued June 25, 2007.
    (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) Average selling prices are net of transportation costs and excluding
        financial derivatives.
    


    MESSAGE TO SHAREHOLDERS

    Kereco Energy Ltd. ("KCO") is pleased to provide our operational and
financial results for the second quarter and first half of 2007.
    Despite a prolonged spring breakup during second quarter which hampered
normal field operations, Kereco had a reasonably active quarter. As we had
expected, we executed a $19.0 million exploration and development capital
program in the second quarter of 2007. During the quarter we drilled six wells
with 83% success - casing five wells (three oil and two gas wells) and
abandoning one. From a production standpoint, we did achieve our exit rate of
10,500 boe/day, but it was a bumpy ride from our commencement of the quarter
also at 10,500 boe/day. During the quarter, we experienced downhole mechanical
issues at Pembina and also were impacted by a lightning strike that knocked
out a third party power substation which supplies all of our power needs at
Sturgeon Lake. These issues resulted in us not achieving our second quarter
2007 production guidance of 10,300 to 10,500 boe/day, approximately 525
boe/day related to Pembina and approximately 300 boe/day related to Sturgeon
Lake - resulting in our average for the quarter of 9,517 boe/day - in line
with our previous announcement on July 18, 2007.
    During the quarter, Kereco also reached an agreement to acquire assets in
the Ferrier area of Alberta from a third party for $36.6 million. The assets
acquired consist of 100% working interest natural gas and NGL production of
approximately 700 boe/day, 1.84 mmboe of proved plus probable reserves
(internal estimate) and 100% ownership in an 11 mmcf/d natural gas facility.
The assets include an established Rock Creek pool with numerous low risk
infill operations. The acquisition is an expansion of, and follow up to, the
Rock Creek drilling success that Kereco has had in proximity to the area on
lands acquired with the Chamaelo Exploration Ltd. corporate acquisition which
closed in the fourth quarter of 2006.
    To finance the Ferrier acquisition, to repay bank indebtedness, and to
assist in positioning the company for the future - Kereco also completed a
successful $70 million, 4.75% convertible debenture financing at a conversion
premium of approximately 40% above the then current trading price of Kereco
common shares.

    
    The following is a summary of our second quarter 2007 accomplishments:

    1.  Convertible Debenture Financing

        -  On June 25, 2007, Kereco closed a successful offering of
           $70 million of convertible unsecured subordinated debentures. The
           debentures are convertible into 7,000,000 common shares of Kereco
           at a conversion price of $10 per share, are due June 30, 2012 and
           bear interest at a rate of 4.75% per annum payable semi-annually.

    2.  Capital Expenditures, including acquisition at Ferrier

        -  During the second quarter of 2007, the Company spent $19.0 million
           on exploration and development activities and disposed of
           $6.0 million of non-strategic assets.

        -  Also during the quarter, the Company closed a $36.6 million
           acquisition of assets in the Ferrier area of Alberta. The assets
           consist of 100% working interest natural gas and NGL production of
           approximately 700 boe/day, 1.84 mmboe of proved plus probable
           reserves (internal estimate) and 100% ownership in a 11 mmcf/d
           natural gas facility.

    3.  Wells Drilled

        -  In the second quarter of 2007, Kereco drilled six wells with 83%
           success resulting in two gas wells, three oil wells and one dry
           and abandoned well.

    4.  Production

        -  Second quarter average production was 9,517 boe/day, a 74%
           increase over the second quarter of 2006 and a 13% increase over
           the first quarter of 2007.

    5.  Drilling Inventory

        -  Kereco currently has in excess of 250 drilling prospects in
           inventory of which provides in excess of three years of drilling
           potential for our company at currently budgeted spending levels.

    6.  Funds Flow

        -  Funds flow from operations for the second quarter of 2007 was
           $22.3 million ($0.39 per basic share), a 34% increase from the
           second quarter of 2006.
    

    OUTLOOK

    As we had mentioned in our first quarter report, our objective is to
position Kereco to not only withstand the current soft investment environment
but also to build the foundation which will allow us to take full advantage of
the opportunities we see emerging later this year and continuing into 2008. As
the commodity markets have evolved over the second quarter, we now see the
horizon for natural gas price recovery being longer than originally thought,
but the aggregation opportunities we expected to appear are now starting to
present themselves. Subsequent to the end of the second quarter we therefore
announced that we are undertaking an investigative process to determine how we
can best reposition ourselves to take advantage of these opportunities, and
have engaged BMO Capital Markets Inc., GMP Securities L.P. and Tristone
Capital Inc. to assist us in the investigation and to advise us how best to
proceed.
    As we move down our investigative path, Kereco will limit the amount of
capital we direct towards natural gas drilling prospects while the soft
natural gas price environment continues. At this time we expect to restrict
third quarter 2007 capital expenditures to less than $40 million, down from
our previously projected $50 - 55 million. As for production, our third
quarter will be affected by our planned one month facility
maintenance/turnaround at Sturgeon Lake with company production estimated to
average 8,800 - 9,200 boed for the quarter. Upon completion of the turnaround
and exiting the third quarter, we forecast production to be approximately
10,500 boed. For the fourth quarter of 2007, the level of capital expenditures
and resultant average production will be dependant upon the commodity price
environment at that time.
    Our industry is currently faced with challenges of both lower natural gas
prices, still higher than acceptable service costs and we will explore all
avenues possible to ensure the long-term value of Kereco shareholders.
    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
    August 7, 2007


    MANAGEMENT'S DISCUSSION AND ANALYSIS

    The following management's discussion and analysis ("MD&A") should be
read in conjunction with the unaudited consolidated interim financial
statements for the three and six months ended June 30, 2007, and 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 August 7, 2007. The reader should be
aware that historical results are not necessarily indicative of future
performance. Additional information relating to Kereco can be found at
www.sedar.com.
    Funds flow from operations, which is determined as cash provided by
operating activities  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.
    Net debt, which is determined as bank debt and working capital (comprised
of accounts receivable, prepaid expenses and accounts payable and accrued
liabilities) is used by us as a key indicator of the financial position of the
Company.  Net debt 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.
    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 INFORMATION

    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 over the second quarter of 2007 averaged 9,517 boe/day (29,396
mcf/day of natural gas and 4,617 bbls/day of crude oil and NGLs) up 74 percent
from the 5,458 boe/day (14,660 mcf/day of natural gas and 3,015 bbls/day of
crude oil and NGLs) averaged in the second quarter of 2006. Production over
the first half of 2007 averaged 8,977 boe/day (27,355 mcf/day of natural gas
and 4,418 bbls/day of crude oil and NGLs) up 59 percent from the 5,656 boe/day
(15,782 mcf/day of natural gas and 3,026 bbls/day of crude oil and NGLs)
averaged in the first half of 2006. Capital expenditures in the second quarter
of 2007 were $50.1 million, including an acquisition in the Ferrier area of
Alberta for $36.6 million and net of $5.9 million of dispositions of
non-strategic assets. The $19.4 million exploration and development capital
program included drilling six wells which resulted in two cased gas wells,
three cased oil wells and one dry and abandoned wells with an 83 percent
success rate. Two gas wells and two oil wells were completed in our Central
Alberta area, one oil well in our Northern Sturgeon area and one dry well was
in the Noel area of British Columbia.

    
    Selected Quarterly Information

                                    2007                                2006
    -------------------------------------------------------------------------
    ($000s, except
     per share
     amounts)                Q2       Q1       Q4       Q3       Q2       Q1
    -------------------------------------------------------------------------
    Revenues
     (net of royalties)  38,051   34,150   31,461   24,152   22,984   24,048
    Funds flow from
     operations          22,299   21,974   20,592   17,422   16,690   17,522
      Per share
       - basic ($)         0.39     0.39     0.40     0.49     0.49     0.52
      Per share
       - diluted ($)       0.38     0.38     0.39     0.48     0.48     0.50
    -------------------------------------------------------------------------
    Net earnings (loss)   2,547   (1,934)    (234)   7,006    7,765    5,468
      Per share
       - basic ($)         0.04    (0.03)   (0.01)    0.20     0.23     0.16
      Per share
       - diluted ($)       0.04    (0.03)   (0.01)    0.19     0.22     0.16
    -------------------------------------------------------------------------
    Total assets        806,637  784,570  767,411  391,933  364,342  347,063
    -------------------------------------------------------------------------
    Bank debt           151,892  179,576  188,673   84,695   74,284   79,565
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


                                    2005
    -------------------------------------
    ($000s, except
     per share
     amounts)                Q4       Q3
    -------------------------------------
    Revenues
     (net of royalties)  28,312   23,471
    Funds flow from
     operations          20,984   17,523
      Per share
       - basic ($)         0.62     0.52
      Per share
       - diluted ($)       0.59     0.49
    -------------------------------------
    Net earnings (loss)   9,381    4,645
      Per share
       - basic ($)         0.28     0.14
      Per share
       - diluted ($)       0.26     0.13
    -------------------------------------
    Total assets        328,267  312,030
    -------------------------------------
    Bank debt            71,737   66,628
    -------------------------------------
    -------------------------------------

    The increase in revenue from first quarter 2007 to second quarter 2007 was
a result of increased production volumes.  Increases in revenues, funds flow
from operations and net earnings in the second half of 2005 were a result of
increased production due to increased drilling activities and also due to
increasingly stronger commodity prices.  Decreases in the same metrics over
the first three quarters of 2006 compared to the fourth quarter of 2005 were
driven predominantly by lower natural gas prices.  The pronounced increase in
revenues and funds flow from operations the fourth quarter of 2006 and first
and second quarters of 2007 were largely a result of the Chamaelo acquisition
which closed on October 19, 2006 and whose results are included from that
point forward.  Losses realized in the first quarter of 2007 and fourth
quarter of 2006 and lower earnings in the second quarter of 2007 are
predominantly due to higher depletion, depreciation and accretion resulting
from the Chamaelo acquisition.

    FUNDS FLOW FROM OPERATIONS

    Funds flow from operations increased 34 percent in the second quarter of
2007 to $22.3 million or $0.38 per share on a diluted basis from $16.7
million, or $0.48 per share on a diluted basis for the second quarter of 2006,
largely as a result of increased production volumes over the two respective
periods. Funds flow from operations increased 29 percent in the first half of
2007 to $44.3 million or $0.39 per share on a diluted basis from $34.2
million, or $0.97 per share on a diluted basis for the first half of 2006,
largely as a result of increased production volumes over the two respective
periods. Funds flow from operations is calculated as follows.

                                  Three months ended       Six months ended
                                        June 30                 June 30
    ($000s)                         2007        2006        2007        2006
    -------------------------------------------------------------------------
    Cash provided by operating
     activities                   28,691      19,899      53,784      36,916
    Change in non-cash working
     capital                      (6,392)     (3,209)     (9,511)     (2,704)
    -------------------------------------------------------------------------
    Funds flow from operations    22,299      16,690      44,273      34,212
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    Net Operating Income

                                   Three months ended       Six months ended
    ($000s, except per                   June 30                 June 30
     share amounts)                 2007        2006        2007        2006
    -------------------------------------------------------------------------
    Natural gas sales             21,329       8,749      40,174      22,024
    Crude oil and NGLs sales      28,193      20,638      52,383      38,633
    Transportation                (1,033)     (1,165)     (2,152)     (1,776)
    Realized financial
     derivative gain (loss)           77         539       1,080         569
    -------------------------------------------------------------------------
    Total net sales               48,566      28,761      91,485      59,450
    Royalty expenses             (11,471)     (6,403)    (20,356)    (13,625)
    Operating expenses            (9,909)     (4,478)    (18,340)     (9,044)
    -------------------------------------------------------------------------
    Net operating income          27,186      17,880      52,789      36,781
    -------------------------------------------------------------------------
      Per share - Basic ($)         0.47        0.52        0.92        1.08
                - Diluted ($)       0.46        0.51        0.91        1.05
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    OPERATING NETBACKS

                                   Three months ended       Six months ended
                                         June 30                 June 30
    -------------------------------------------------------------------------
                                    2007        2006        2007        2006
    -------------------------------------------------------------------------
    Boe netback ($/boe)
      Sales price                  57.18       59.17       56.96       59.25
      Transportation               (1.19)      (2.35)      (1.32)      (1.74)
      Realized gain (loss)
       on financial derivatives     0.09        1.09        0.66        0.56
    -------------------------------------------------------------------------
      Sales price, net of
       transportation and
       realized gain on financial
       derivatives                 56.08       57.91       56.30       58.07
      Royalty expenses - ($/boe)  (13.25)     (12.89)     (12.53)     (13.31)
                       - (%)       23.70       22.70       22.50       23.10
      Operating expenses          (11.44)      (9.02)     (11.29)      (8.83)
    -------------------------------------------------------------------------
      Netback                      31.39       36.00       32.48       35.93
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Natural gas netback ($/mcf)
      Sales price                  7.98         6.56        8.11        7.71
      Transportation              (0.19)       (0.17)      (0.20)      (0.19)
      Realized gain (loss) on
       financial derivatives       0.01         0.42        0.05        0.20
    -------------------------------------------------------------------------
      Sales price, net of
       transportation and
       realized gain on
       financial derivatives       7.80         6.81        7.96        7.72
      Royalty expenses
       - ($/mcf)                  (1.75)       (1.42)      (1.68)      (1.73)
       - (%)                      22.50        22.30        21.3        23.0
      Operating expenses          (1.92)       (1.51)      (1.88)      (1.48)
    -------------------------------------------------------------------------
      Netback                      4.13         3.88        4.40        4.51
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Crude oil and NGL
     netback ($/bbl)
      Sales price                 67.10        75.23       65.49       70.54
      Transportation              (1.28)       (3.42)      (1.42)      (2.27)
      Realized gain on
       financial derivatives       0.14        (0.06)       1.07       (0.03)
    -------------------------------------------------------------------------
      Sales price, net of
       transportation realized
       gain on financial
       derivatives                65.96        71.75       65.14       68.26
      Royalty expenses
       - ($/bbl)                 (16.08)      (16.41)     (15.04)     (15.87)
       - (%)                      24.40        22.90       23.50       23.20
      Operating expenses         (11.33)       (8.96)     (11.26)      (8.81)
    -------------------------------------------------------------------------
      Netback                     38.55        46.38       38.84       43.56
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    PETROLEUM AND NATURAL GAS SALES

    Production for the second quarter of 2007 averaged 9,517 boe/day and net
realized prices of $55.99/boe resulted in revenues of $49.5 million, a 74
percent increase in production and a one percent decrease in realized prices
compared to the second quarter of 2006 which had production of 5,458 boe/day
and net realized prices of $56.82/boe. Production increases in the second
quarter of 2007 compared to the second quarter of 2006 were a result of
additional production from the acquisition of Chamaelo on October 19, 2006,
adding approximately 4,600 boe/day, which was offset by higher production
declines over the two respective periods, mainly from our north eastern
British Columbia property. Second quarter 2007 production was approximately
800 boe/day short of our expectation primarily as a result of two unexpected
operational issues - downhole mechanical and performance issues at Pembina
(approximately 525 boe/day) and the power outage at Sturgeon caused by a
lightning strike at the power substation that services the plant and field
(approximately 300 boe/day).
    Average price realizations for the second quarter of 2007, net of
transportation costs, were $55.99/boe ($7.79/mcf for natural gas, $65.82/bbl
for crude oil and NGLs). Financial derivative contracts in place (see note 11
to the consolidated financial statements for further details) resulted in
realized gains of $0.1 million ($0.09/boe) for the second quarter. 
Comparatively, average price realizations for the second quarter of 2006, net
of transportation costs, were $56.82/boe ($6.39/mcf for natural gas,
$71.81/bbl for crude oil & NGLs). The change in price realizations tracked
changes in the underlying commodity prices over these periods. WTI crude oil
averaged U.S.$65.00/bbl for the second quarter of 2007, eight percent lower
than the U.S. $70.70/bbl averaged in the second quarter of 2006. The average
daily index AECO natural gas price ($Cdn/mcf) price was $7.07/mcf for the
second quarter of 2007, 18 percent higher than $6.01/mcf from the second
quarter of 2006, and the average monthly index AECO natural gas price was
$7.37/mcf for the second quarter of 2007, 17 percent higher than $6.27/boe
from the second quarter of 2006. We market a relatively even mix of our
natural gas at both AECO daily index and at AECO monthly index pricing.
    Production for the first half of 2007 averaged 8,977 boe/day and net
realized prices of $55.64/boe resulted in revenues of $92.6 million, a 59
percent increase in production and a three percent decrease in realized prices
compared to the first half of 2006 which had production of 5,656 boe/day and
net realized prices of $57.51/boe. Production increases in the first half of
2007 compared to the first half of 2006 were also a result of additional
production from the acquisition of Chamaelo on October 19, 2006, adding
approximately 4,600 boe/day, which was offset by higher production declines
over the two respective periods, mainly from our north eastern British
Columbia property. Production for the year to date 2007 was curtailed as a
result of the second quarter operational issues at Pembina and Sturgeon
discussed above as well operational issues experienced in the first quarter of
2007 including the Pembina sales line hydrate problem, third party facility
downtime and performance issues at Sturgeon Lake and Wilson Creek.
    Average price realizations for the first half of 2007, net of
transportation costs, were $55.64 /boe ($7.91/mcf for natural gas, $64.07/bbl
for crude oil and NGLs). Financial derivative contracts in place (see note 11
to the consolidated financial statements for further details) resulted in
realized gains of $1.1 million ($0.66/boe) for the first half of 2007. 
Comparatively, average price realizations for the first half of 2006, net of
transportation costs, were $57.51/boe ($7.52/mcf for natural gas, $68.27/bbl
for crude oil & NGLs). The change in price realizations tracked changes in the
underlying commodity prices over these periods. WTI crude oil averaged
U.S.$61.58/bbl for the first half of 2007, eight percent lower than U.S.
$67.14/bbl averaged in the first half of 2006. The average daily index AECO
natural gas price ($Cdn/mcf) price was $7.22/mcf for the first half of 2007,
seven percent higher than $6.78/mcf from the first half of 2006, and the
average monthly index AECO natural gas price was $7.42/mcf for the first half
of 2007, five percent lower than $7.78/boe from the first half of 2006.
    All of our production is sold within Canada, and revenues are received in
Canadian dollars. The commodities we produce and sell are sensitive to both
worldwide (crude oil) and North American (natural gas) price fluctuations as
well as fluctuations in the Canada/U.S. exchange rate. A decrease in the value
of the Canadian dollar versus the U.S. dollar positively impacts our net price
realizations. The average Canada/U.S. exchange rate remained relatively static
at 1.10 for the second quarter of 2007 compared to 1.12 for the second quarter
of 2006 and 1.13 for the first half of both 2006 and 2007.

    Realized Financial Derivatives

    On an ongoing basis we enter into several financial and physical
commodity contracts to assist in minimizing exposure to commodity prices. 
These activities resulted in gains of $1.1 million ($0.9 million on crude oil
and $0.2 million on natural gas) in the first half of 2007 compared to a gain
of $0.6 million in the first half of 2006.

    Transportation Costs

    Transportation costs decreased to $1.19/boe for second quarter of 2007
compared to $2.35/boe for the second quarter of 2006 which were largely
influenced by the transportation expenses associated with prior period sales
recorded in the second quarter of 2006. Transportation costs decreased 11
percent to $1.0 million for the second quarter of 2007 compared to $1.2
million for the second quarter of 2006, based on increased sales volumes over
the two periods as well as increases in total transportation costs. For the
first half of 2007 transportation costs decreased to $1.32/boe from $1.74/boe
in the first half of 2006.

    Royalties

    Our royalty burdens are predominantly Crown, along with some overriding,
freehold and net profits interest royalties ("other royalties"). For the
second quarter of 2007, average royalty rates increased slightly to 23.7
percent (Crown royalties of 20.6 percent and other royalties of 3.1 percent)
compared to 22.7 percent (Crown royalties of 20.7 percent and other royalties
of 2.0 percent) for the second quarter of 2006. The increase in "other
royalties" is attributable to a higher percentage freehold royalties
associated with the Chamaelo properties acquired in fourth quarter 2006. For
the first half of 2007, average royalty rates decreased slightly to 22.5
percent (Crown royalties of 19.3 percent and other royalties of 3.2 percent)
compared to 23.1 percent (Crown royalties of 21.2 percent and other royalties
of 1.9 percent) compared to the first half of 2006. Decreases in the crown
rate were a result of operating cost and capital cost royalty adjustments
being recognized.
    Kereco's overall corporate royalty rate is expected to be maintained at
the second half 2007 rate throughout 2007 but could decrease in the future as
a result of a reduced corporate Crown royalty rate expected through reductions
due to capital cost allowance, operating expense and custom processing
deductions.

    CASH COSTS

    Cash costs (operating, general and administrative and interest) increased
to $16.82/boe in the second quarter of 2007 compared to $12.10/boe in the
second quarter of 2006. Cash costs increased to $16.41/boe in the first half
of 2007 compared to $11.61/boe in the first half of 2006. There was an
increase in costs on a per boe basis in all three categories driven largely by
the effects of lower than expected production volumes and higher than expected
costs resulting from the Chamaelo properties acquired. Remainder of year cash
costs are expected to decrease with additional production volumes.

    Operating Costs

    Operating costs on a per boe basis increased in the second quarter of
2007 to $11.44/boe ($1.92/mcf for natural gas and $11.33/bbl for crude oil and
NGLs) compared to second quarter of 2006 costs of $9.02/boe ($1.51/mcf for
natural gas and $8.96/bbl for crude oil and NGLs). First half 2007 operating
costs increased to $11.29/boe ($1.88/mcf for natural gas and $11.26/bbl for
crude oil and NGLs) compared to first half 2006 costs of $8.83/boe ($1.48/mcf
for natural gas and $8.81/bbl for crude oil and NGLs). The increase over these
respective periods is largely attributable to the lower production volumes
than expected in the second quarter and the year to date, higher power costs
associated with our Sturgeon Lake property and the realization of higher than
expected costs on the Chamaelo assets.
    We continue to see downward pressure on all costs due to low levels of
industry activity, and when coupled with incremental production volumes we
expect our operating cost rate to decline and should average between $10.00 -
$11.00/boe for the second half of the year with the third quarter being higher
as a result of the planned Sturgeon Lake maintenance/turnaround which will
have the Sturgeon Lake plant offline for approximately four weeks. Given the
fixed nature many costs at Sturgeon Lake (and the loss of one month's
production), this will place some upward pressure on our third quarter
operating costs.

    General and Administrative Expenses

    General and Administrative ("G&A") costs increased 73 percent on a boe
basis to $1.65/boe for the second quarter of 2007 from $0.96/boe in the second
quarter of 2006. Total costs increased to $1.4 million for the second quarter
of 2007 compared to $0.5 million for the second quarter of 2006. G&A costs
increased 63 percent on a boe basis to $1.55/boe for the first half of 2007
from $0.95/boe in the first half of 2006. Total costs increased to $2.5
million for the first half of 2007 compared to $1.0 million for the first half
of 2006. The increase in total costs is a result of increased staff levels and
support costs in the first and second quarters of 2007 as additions and
expenditures were made to transition the company from a junior to intermediate
producer. Increases on a boe basis were influenced by both the higher overall
expenses realized in the quarter in addition to the relative lower production
base realized in the quarter. G&A costs per boe are expected to decrease
slightly from the first half of 2007 rate for the remainder of the year with
additional production volumes.

    Interest Expense

    Interest expense increased to $3.2 million in the second quarter of 2007
compared to $1.1 million in the second quarter of 2006. The $3.1 million of
second quarter interest expense is comprised of $2.9 million in bank debt
interest expense, with the remainder made up of interest related to property
acquisitions and dispositions closed in the quarter and cash interest expense
and non-cash accretion expense associated with the convertible debentures.
This increase in bank debt interest expense is a result of the significant
increase in the company's size and asset base as a result of the acquisitions
and increased activity over the two respective periods. The average draw on
our bank line during the second quarter of 2007 was $184.0 million (at an
average interest rate of 6.6 percent) compared to $76.9 million (at an average
interest rate of 5.5 percent) for the second quarter of 2006. The average
interest rate rose as a result of increases in prime lending rates over the
two respective periods. On a per boe basis, interest expense increased to
$3.73/boe in the second quarter of 2007 compared to $2.12/boe in the second
quarter of 2006.
    The issuance of convertible debentures on June 25, 2006 resulted in the
recognition of cash interest expense of $55,000 and non cash interest
accretion expense of $52,000 in the second quarter of 2007. The cash interest
expense is calculated at a rate of 4.75 percent on $70 million over a five
year and six day term beginning on June 25, 2007 and ending on June 30, 2012.
See note 6, "Convertible Debentures" to the consolidated financial statements
for more details.
    Total bank cash interest expense is expected to be maintained at
approximately the second quarter amount through the remainder of 2007 as draws
on the bank line should only increase slightly from its current level as our
capital expenditure program for the third quarter is expected to be mostly
funded from cash flow.

    NET EARNINGS

    Earnings of $2.5 million ($0.04 per diluted share) were realized in the
second quarter of 2007 compared to earnings of $7.8 million ($0.22 per diluted
share) in the second quarter of 2006. Earnings of $0.6 million ($0.01 per
diluted share) were realized in the first half of 2007 compared to earnings of
$13.2 million ($0.38 per diluted share) in the first half of 2006.
    The decrease in earnings is largely attributable to the increased
depletion, depreciation and accretion expense as described below.

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

    Depletion, depreciation and accretion ("DD&A") amounted to $21.9 million,
or $25.29/boe in the second quarter of 2007 compared to $7.5 million or
$15.14/boe for the second quarter of 2006. DD&A amounted to $41.3 million, or
$25.40/boe in the first half of 2007 compared to $15.4 million or $15.06/boe
for the first half of 2006.
    The DD&A rate increased in the first half and second quarter of 2007 as a
result of the fair value of the property, plant and equipment acquired from
Chamaelo on October 19, 2006 as well as the capital expenditures added to the
depletable pool throughout 2006. These cumulative additions to the depletable
pools, relative to period end estimated reserves, result in the increased DD&A
rate per boe over the two respective periods. The DD&A rate for the remainder
of 2007 should remain mostly flat at approximately the second quarter 2007
rate of $25.00/boe.

    Stock-Based Compensation Expense

    Stock-based compensation expense for the second quarter of 2007 was $1.3
million compared to a $0.9 million in the second quarter of 2006. Stock-based
compensation expense for the first half of 2007 was $2.3 million compared to a
$1.6 million in the first half of 2006. In the first quarter of 2007, 2.4
million options of non-insiders of the company were cancelled and 1.5 million
new options were granted and an additional 2.2 million options were granted in
June of 2007. Stock-based compensation expense continues to be recognized on
the cancelled options over their original life. This, in addition to the
additional options granted during the year to date, resulted in the increased
stock-based compensation expense both in the first quarter and the first half
of 2007.

    Unrealized (Gains)/Losses on Financial Instruments

    The effect of financial instruments amounted to an unrealized loss of
$2.6 million in the first half of 2007 compared to an unrealized loss of $0.2
million for the first half of 2006. These financial instruments include our
financial and physical commodity contracts as well as our fixed price
electrical power purchase contract. Any physical commodity contracts and our
electrical power purchase contract are included as financial instruments in
accordance with the new accounting standards for Financial Instruments. See
note 2, "Changes in Accounting Policies" to the consolidated financial
statements for more details. The majority of the gains or losses on financial
derivatives are from financial commodity contracts which are based upon the
commodity benchmarks of (WTI) for oil and (AECO) natural gas. The losses
reflected to date are largely a result of the increases in commodity prices as
at the end of June 2007. Accounting standards require that the change in the
fair value ("mark to market") of these positions at December 31, 2006, and at
each quarter end, be included in earnings for the period. See note 11 in the
notes to the consolidated financial statements for additional details.

    Taxes

    The total tax recovered for the year to date at June 30, 2007 was $2.2
million comprised of $2.5 million in future income tax recovery offset by $0.3
million in current income tax (June 30, 2006: expense of $3.6 million). This
results in an effective tax rate of 138 percent for the year to date in 2007,
which is largely influenced by adjustments to tax pools upon the filing of tax
returns and the positive adjustments realized from reduced enacted statutory
rates in 2011 being applied to a relatively lower loss before tax for the
period of $1.6 million.
    Current taxes of $0.3 million were recognized in the second quarter of
2007. This resulted from the disallowance by the Canada Revenue Agency of the
majority of a Scientific Research and Experimental Development claim ("SR&ED")
made by Chariot Energy Ltd. in 2004 prior to Kereco's acquisition of Chariot
in April 2005. This disallowance will not result in any further current tax
expense to Kereco.

    Income Tax Pools

    At June 30, 2007, the Company had the following tax pools and non-capital
losses that can be used to offset otherwise taxable income in future periods:

    
    (millions)                                           As at June 30, 2007
    -------------------------------------------------------------------------
    Canadian oil and gas property expense ("COGPE")                    279.4
    Canadian development expense ("CDE")                                84.5
    Canadian exploration expense ("CEE")                                30.6
    Undepreciated capital costs ("UCC")                                106.5
    Non-capital losses carried forward                                  25.7
    -------------------------------------------------------------------------
    Total pools and losses                                             526.7
    Share issue costs                                                   14.5
    -------------------------------------------------------------------------
    Total pools, losses and share issue costs                          541.2
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    As a result of the filing of the change of control tax return for Chamaelo
during the month of April and the 2006 year end tax returns in June, there
were some movements between our various tax pools. The numbers in the table
above reflect the net effect of those movements.

    LIQUIDITY AND CAPITAL RE

SOURCES Capital Resources Three months ended Six months ended June 30 June 30 (000s) 2007 2006 2007 2006 ------------------------------------------------------------------------- Funds flow from operations 22,299 16,690 44,273 34,212 Working capital (12,016) (6,248) (12,247) (4,302) Bank debt (27,684) (5,280) (36,781) 2,547 Business combination transaction costs (71) - (484) - Proceeds from issuance of convertible debentures 67,475 - 67,475 - Proceeds from the exercise of options or warrants 105 - 626 443 Proceeds from share issuances 10 20,795 18,303 20,795 ------------------------------------------------------------------------- Total capital resources 50,118 25,957 81,165 53,695 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Bank Debt At June 30, 2007 the Company had in place a syndicated committed credit facility, in the amount of $202 million, with two major Canadian Chartered Banks and the Canadian branch of a major international bank. In conjunction with the acquisition of assets in June of 2007 this facility was increased from the previous borrowing base of $183 million. 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 June 30, 2007, $151.9 million (December 31, 2006, $188.7 million) had been drawn under the bank facility. The average interest rate on borrowings outstanding for the year to date was 6.6 percent, ($5.8 million in interest expense), including interest expense associated with the property acquisitions and dispositions realized in the quarter, compared to $1.9 million for the six months ended June 30, 2006. The entire amount drawn under the credit facility is not due within 12 months and is therefore presented as a long term liability. Working Capital Kereco ended the quarter with a working capital surplus of $4.8 million. A reduction in the capital activity in the second quarter and the associated reduction of the accounts payable and accrued liability balances since the end of the first quarter through conversion to cash, coupled with receivable collections and an increased accrued receivable associated with higher production levels in second quarter 2007 resulted in the working capital surplus. Kereco constantly monitors its working capital position in conjunction with its undrawn bank credit lines. Kereco expects that the increased credit lines and expected cash flow 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. Convertible Debentures On June 25, 2007, the Company issued $70 million of convertible unsecured subordinated debentures which mature on June 30, 2012 and bear interest at 4.75% (the "Debentures"). Interest on the Debentures is payable semi-annually in arrears on June 30 and December 31 each year, commencing on December 31, 2007. Each debenture can be converted into common shares of the Corporation at the option of the holder at any time prior to the close of business on June 29, 2012 at a conversion price of $10.00 per common share. The Debentures are not redeemable by the Corporation prior to June 30, 2010. On or after June 30, 2010 and prior to June 30, 2012, the Debentures may be redeemed at the option of the Corporation, in whole or in part at a redemption price equal to 100% of the principal amount of the Debentures to be redeemed plus accrued and unpaid interest to, but excluding, the redemption date provided that the Current Market Price (as defined in the Short Form Prospectus filed in conjunction with the offering) is at least 125% of the Conversion Price. Share Capital Six months ended Year ended June 30, 2007 December 31, 2006 ------------------------------------------------------------------------- Weighted average shares outstanding Basic 57,143,506 38,610,662 Options and warrants 1,026,884 1,373,198 ------------------------------------------------------------------------- Diluted 58,170,390 39,983,860 Common shares outstanding at period end ------------------------------------------------------------------------- Basic 57,777,332 55,336,432 Options and warrants 8,268,850 7,471,492 ------------------------------------------------------------------------- Diluted 66,046,182 62,807,924 ------------------------------------------------------------------------- ------------------------------------------------------------------------- As at June 30, 2007 and at August 7, 2007, Kereco had 57,777,332 shares outstanding reflecting the issuance of 2,250,000 flow-through common shares and the exercise of 190,900 warrants during the first half of the year. CAPITAL EXPENDITURES During the second quarter of 2007, we incurred $50.1 million in net capital expenditures itemized as follows: Three months ended Six months ended June 30 June 30 ($000s) 2007 2006 2007 2006 ------------------------------------------------------------------------- Land 737 555 1,240 1,468 Geological and geophysical 1,042 4,458 1,722 9,011 Drilling and completions 8,110 13,987 30,676 33,079 Facilities and equipment 8,843 6,615 13,894 9,811 Office and corporate costs 171 258 2,147 161 Capitalized general and administrative costs 471 84 742 165 ------------------------------------------------------------------------- Total exploration and development 19,374 25,957 50,421 53,695 ------------------------------------------------------------------------- Property acquisitions 36,605 - 36,605 - Property dispositions (5,861) - (5,861) - ------------------------------------------------------------------------- Total capital expenditures 50,118 25,957 81,165 53,695 ------------------------------------------------------------------------- ------------------------------------------------------------------------- We drilled 19 (14.9 net) wells during the first half of 2007 which resulted in seven cased gas wells (5.1 net) and eight oil wells (7.2 net) comprised of one (0.5 net) gas well in the Blair Creek British Columbia area, one (1.0 net) gas well and two (2.0 net) oil wells in the Fireweed British Columbia area, one (0.6 net) gas well and one (1.0 net) oil well in the Willesden Green Central Alberta area, one (1.0 net) oil well in the Sturgeon Lake Alberta area, one (1.0 net) gas well in the Wimborne Central Alberta area, three (2.0 net) gas wells in the Gosling Central Alberta area and four (3.2 net) oil wells in the Wilson Creek Central Alberta area. We also completed six major recompletions and workovers at Sturgeon Lake in the first half. This amounted to $30.7 million in drilling and completion expenditures for the year to date. Related equipping costs and facility costs amounted to $13.9 million, including an upgrade to our Willesden Green gas compression facility. $1.2 million was also spent on land resulting in an increase in our undeveloped land position to 238,000 net undeveloped acres at June 30, 2007. $1.7 million was spent on seismic for the year, mainly in our exploration areas of north eastern British Columbia. We acquired a producing property in the Ferrier Alberta area for $36.6 million in the second quarter of 2007 which added approximately 700 boe/day of production. Two non-strategic properties were also sold during the second quarter of 2007, resulting in $5.9 million in proceeds. CONTRACTUAL OBLIGATIONS 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 $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 $18.4 million in qualifying CEE expenditures related to this flow-through share commitment had been spent to June 30, 2007. On February 16, 2007, the Company issued 2,250,000 flow-through common shares for proceeds of $19.4 million before issue costs of $1.0 million which will require the Company to incur $19.4 million of flow-through share eligible CEE, as defined in the Canadian Income Tax Act, by December 31, 2008. The Company has executed separate contracts with two large drilling contractors for the exclusive use of two specific drilling rigs. One contract is a three year contract which commenced in December of 2006 and requires Kereco to utilize one specific rig for a minimum of 225 days per year. If not utilized Kereco is obligated to pay a minimum $5,800 rate per day. The second contract is a two year contract which commenced June 1, 2007 and requires Kereco to utilize another specific rig for a minimum of 225 days per year for two years. If not utilized Kereco is obligated to pay a minimum $4,785 rate per day. During the first half of 2007, the Company signed a nine year office lease which commences on February 1, 2008. Annual payments under the lease will be $1.6 million. 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: Drilling Office Electricity ($000s) contracts lease contract ------------------------------------------------------------------------- 2007 $ 1,014 $ - $ 1,004 2008 $ 2,382 $ 1,509 $ 2,008 2009 $ 1,754 $ 1,509 $ - 2010-2016 $ - $ 10,591 $ - ------------------------------------------------------------------------- Total $ 5,150 $ 13,609 $ 3,012 ------------------------------------------------------------------------- ------------------------------------------------------------------------- RISK MANAGEMENT AND HEDGING We have entered into financial and physical derivative contracts as outlined in notes 11 to the consolidated financial statements. These positions were undertaken in order to secure pricing on a portion of our future production and to protect against fluctuations 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 committed under financial derivative contracts at the June 30, 2007 strip pricing for both crude oil and natural gas, over the term of those financial derivative contracts, Kereco would actually realize a net $1.3 million cash gain over the term of the financial derivative contracts from the oil and natural gas contracts in place. The financial and physical derivative contracts entered up to and including August 7, 2007 and as listed in note 11 to the Consolidated Financial Statements result in the following downside price protection and ceiling prices on future production: 2007 2008 ------------------------------------------------------- Q2 Q3 Q4 Q1 Q2 Q3 Q4 ------------------------------------------------------------------------- Natural Gas Volume (GJ/day) 14,000 14,000 11,348 10,000 - - - Floor price (AECO CDN $/GJ) 6.79 6.79 7.12 7.35 - - - Ceiling price (AECO CDN $/GJ) 8.79 8.79 10.47 11.67 - - - ------------------------------------------------------------------------- Crude Oil Volume (bbls/day) 1,750 1,668 1,750 1,500 1,500 1,500 1,500 Floor price (WTI US$/bbl) 62.43 62.55 62.43 61.50 61.50 61.50 61.50 Ceiling Price (WTI US$/bbl) 88.34 88.99 88.34 78.88 78.88 78.88 78.88 ------------------------------------------------------------------------- ------------------------------------------------------------------------- NEW ACCOUNTING STANDARDS IN 2007 AND 2008 Financial Instruments Effective January 1, 2007, the Company adopted the Canadian Institute of Chartered Accountants ("CICA") Handbook section 3855, "Financial Instruments - Recognition and Measurement," section 3865, "Hedges", section 1530, "Comprehensive Income", and section 3861, "Financial Instruments - Disclosure and Presentation" and section 3251 ("Equity"). The Company has adopted these standards retroactively without restatement and comparative consolidated financial statements have not been restated. The adoption of these new financial instruments standards resulted in changes in accounting for financial instruments as well as the recognition of transitional adjustments that have been recorded into adjusted retained earnings as described below. In accordance with these new standards, all Financial Instruments including both financial and non financial derivatives and certain embedded derivatives qualify as assets or liabilities and need to be recorded on the balance sheet. Financial Instruments are categorized into one of five categories which determines their initial measurement value and subsequent recognition of gains and losses. Section 3251 introduces new standards for the presentation of Equity with "Accumulated other income" as a result of the application of section 1530. Kereco has designated its short term and long term debt as well as cash balances as Held for Trading. Held for Trading instruments are measured at fair value at each balance sheet date with gains and losses recognized in net earnings in the current period. The transaction costs or deferred financing costs related to Held for Trading financial assets and liabilities are expensed as incurred. The adoption of this CICA Handbook section and designation of Held for Trading was done retroactively without restatement, and resulted in a reduction to retained earnings of $154,000 a reduction to the future income tax liability of $81,000 and the reduction of the previous deferred financing charges current asset account to nil. All derivatives are classified as Held for Trading and are therefore carried at their fair value in the balance sheet caption "Financial Derivative Contracts". Gains or losses in the fair values between periods are recognized in net earnings through the account "Unrealized Gain or Loss on Financial Derivative Contracts". The adoption of this section resulted in the recognition of two sole derivatives. One is the three year contract to acquire electricity at a fixed rate and the other is the physical commodity collar sole contract for first quarter 2007 production. These resulted in the following retroactive adjustments without restatement: an increase in retained earnings by $707,000 and increase in the future tax liability of $372,000 and an increase in the Financial Derivative Contract asset of $1,079,000. In July 2006, the CICA issued a revised section 1506, "Accounting Changes". The new recommendations permit voluntary changes in accounting policy only if they result in financial statements which provide more reliable and relevant information. Accounting policy changes are applied retrospectively unless it is impractical to determine the period or cumulative impact of the change. Corrections of prior period errors are applied retrospectively and changes in accounting estimates are applied prospectively by including these changes in earnings. The guidance is effective for all changes in accounting policies, changes in accounting estimates and corrections of prior periods errors initiated in periods that began on or after January 1, 2007. As of January 1, 2008 the company will be required to adopt CICA Handbook section 1535, "Capital Disclosures", which requires entities to disclose their objectives, policies and processes for managing capital, and in addition, whether the entity has complied with any externally imposed capital requirements. The company is assessing the impact of this new standard on its consolidated financial statements and anticipates that the main impact will be in terms of additional disclosures required. RELATED PARTY TRANSACTIONS During 2006 and 2007, Kereco conducted business with a company controlled by a director of Kereco. These transactions were made under normal business terms and conditions at the same rates as with non-related parties. Transactions in the amount of $0.8 million were conducted in the first half of 2007 and $250,000 in the fourth quarter of 2006. None of these amounts remained outstanding at each respective period end. RISK AND UNCERTAINTY Please refer to the Management's Discussion and Analysis for the year ended 2006 for a discussion of risks and uncertainties Kereco faces. The following developments have been added as items of risk and uncertainty in addition to those stated in the Management's Discussion and Analysis for the year ended December 31, 2006. Environmental Regulation and Risk All phases of the oil and natural gas business present environmental risks and hazards and are subject to environmental regulation pursuant to a variety of federal, provincial and local laws and regulations. Compliance with such legislation can require significant expenditures and a breach may result in the imposition of fines and penalties, some of which may be material. Environmental legislation is evolving in a manner expected to result in stricter standards and enforcement, larger fines and liability and potentially increased capital expenditures and operating costs. In 2002, the Government of Canada ratified the Kyoto Protocol (the "Protocol"), which calls for Canada to reduce its greenhouse gas emissions to specified levels. There has been much public debate with respect to Canada's ability to meet these targets and the Government's strategy or alternative strategies with respect to climate change and the control of greenhouse gases. Implementation of strategies for reducing greenhouse gases whether to meet the limits required by the Protocol or as otherwise determined could have a material impact on the nature of oil and natural gas operations, including those of the Company. The Federal Government released on April 26, 2007, its Action Plan to Reduce Greenhouse Gases and Air Pollution (the "Action Plan"), also known as ecoACTION and which includes the Regulatory Framework for Air Emissions. This Action Plan covers not only large industry, but regulates the fuel efficiency of vehicles and the strengthening of energy standards for a number of energy-using products. Regarding large industry and industry related projects the Government's Action Plan intends to achieve the following: (i) an absolute reduction of 150 megatonnes in greenhouse gas emissions by 2020 by imposing mandatory targets; and (ii) air pollution from industry is to be cut in half by 2015 by setting certain targets. New facilities using cleaner fuels and technologies will have a grace period of three years. In order to facilitate the companies' compliance of the Action Plan's requirements, while at the same time allowing them to be cost-effective, innovative and adopt cleaner technologies, certain options are provided. These are: (i) in-house reductions; (ii) contributions to technology funds; (iii) trading of emissions with below-target emission companies; (iv) offsets; and (v) access to Kyoto's Clean Development Mechanism. On March 8, 2007, the Alberta Government introduced Bill 3, the Climate Change and Emissions Management Amendment Act, which intends to reduce greenhouse gas emission intensity from large industries. Bill 3 states that facilities emitting more than 100,000 tones of greenhouse gases a year must reduce their emissions intensity by 12% starting July 1, 2007; if such reduction is not initially possible the companies owning the large emitting facilities will be required to pay $15 per tonne for every tonne above the 12% target. These payments will be deposited into an Alberta-based technology fund that will be used to develop infrastructure to reduce emissions or to support research into innovative climate change solutions. As an alternate option, large emitters can invest in projects outside of their operations that reduce or offset emissions on their behalf, provided that these projects are based in Alberta. Prior to investing, the offset reductions, offered by a prospective operation, must be verified by a third party to ensure that the emission reductions are real. Given the evolving nature of the debate related to climate change and the control of greenhouse gases and resulting requirements, it is not possible to predict the impact of those requirements on the Company and its operations and financial condition. Review of Alberta Royalty and Tax Regime On February 16, 2007, the Alberta Government announced that a review of the province's royalty and tax regime (including income tax and freehold mineral rights tax) pertaining to oil and gas resources, including oil sands, conventional oil and gas and coalbed methane, will be conducted by a panel of experts, with the assistance of individual Albertans and key stakeholders. The review panel is to produce a final report that will be presented to the Minister of Finance by August 31, 2007. CRITICAL ESTIMATES Management is required to make judgments and use estimates in the application of generally accepted accounting principals that have a significant impact on the financial results of Kereco. Please refer to the Management's Discussion and Analysis for the year ended 2006 for a discussion outlining these accounting policies and practices which are critical in determining Kereco's financial results. DISCLOSURE CONTROLS AND PROCEDURES AND INTERNAL CONTROLS OVER FINANCIAL REPORTING There are no changes to the disclosure controls and procedures and internal controls over financial reporting from those disclosed in the Management's Discussion and Analysis for the year ended December 31, 2006. OUTLOOK As we had mentioned in our first quarter report, our objective is to position Kereco to not only withstand the current soft investment environment but also to build the foundation which will allow us to take full advantage of the opportunities we see emerging later this year and continuing into 2008. As the commodity markets have evolved over the second quarter, we now see the horizon for natural gas price recovery being longer than originally thought, but the aggregation opportunities we expected to appear are now starting to present themselves. Subsequent to the end of the second quarter we therefore announced that we are undertaking an investigative process to determine how we can best reposition ourselves to take advantage of these opportunities, and have engaged BMO Capital Markets Inc., GMP Securities L.P. and Tristone Capital Inc. to assist us in the investigation and to advise us how best to proceed. As we move down our investigative path, Kereco will limit the amount of capital we direct towards natural gas drilling prospects while the soft natural gas price environment continues. At this time we expect to restrict third quarter 2007 capital expenditures to less than $40 million, down from our previously projected $50 - 55 million. As for production, our third quarter will be affected by our planned one month facility maintenance/turnaround at Sturgeon Lake with company production estimated to average 8,800 - 9,200 boed for the quarter. Upon completion of the turnaround and exiting the third quarter, we forecast production to be approximately 10,500 boed. For the fourth quarter of 2007, the level of capital expenditures and resultant average production will be dependant upon the commodity price environment at that time. Our industry is currently faced with challenges of both lower natural gas prices, still higher than acceptable service costs and we will explore all avenues possible to ensure the long-term value of Kereco shareholders. 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 August 7, 2007 KERECO ENERGY LTD. CONSOLIDATED BALANCE SHEETS As at As at June 30, December 31, ($000s) (unaudited) 2007 2006 ------------------------------------------------------------------------- ASSETS Current Accounts receivable $ 39,059 $ 41,268 Prepaid expenses 3,040 3,459 Financial derivative contracts (Note 11) 3,515 4,990 ------------------------------------------------------------------------- 45,614 49,717 Property, plant and equipment, net (Note 3) 641,745 600,964 Goodwill (Note 4) 119,278 116,730 ------------------------------------------------------------------------- Total Assets 806,637 767,411 ------------------------------------------------------------------------- ------------------------------------------------------------------------- LIABILITIES Current Accounts payable and accrued liabilities 37,313 51,955 Bank debt (Note 5) - 27,000 ------------------------------------------------------------------------- 37,313 78,955 ------------------------------------------------------------------------- Bank debt (Note 5) 151,892 161,673 Asset retirement obligation (Note 8) 16,932 16,038 Convertible debentures (Note 6) 52,008 - Future income taxes (Note 7) 35,678 29,497 ------------------------------------------------------------------------- 256,510 207,208 ------------------------------------------------------------------------- Total Liabilities 293,823 286,163 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Commitments and guarantees (Note 12) Contingencies (Note 14) SHAREHOLDERS' EQUITY Share capital (Note 9) 450,797 438,216 Contributed surplus (Note 9) 8,654 6,539 Convertible debentures (Note 6) 15,704 - Retained earnings 37,659 36,493 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Total shareholders' equity 512,814 481,248 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Total liabilities and shareholders' equity $ 806,637 $ 767,411 ------------------------------------------------------------------------- ------------------------------------------------------------------------- The accompanying notes form an integral part of these consolidated financial statements. KERECO ENERGY LTD. CONSOLIDATED STATEMENT OF EARNINGS, COMPREHENSIVE INCOME AND RETAINED EARNINGS Three months ended Six months ended June 30 June 30 ------------------------------------------------------------------------- ($000s, except per share amounts) (unaudited) 2007 2006 2007 2006 ------------------------------------------------------------------------- REVENUE Petroleum and natural gas sales $ 49,522 29,387 $ 92,557 60,657 Royalties, net of ARTC 11,471 6,403 20,356 13,625 ------------------------------------------------------------------------- 38,051 22,984 72,201 47,032 ------------------------------------------------------------------------- EXPENSES Operating 9,909 4,478 18,340 9,044 Transportation 1,033 1,165 2,152 1,776 General and administrative 1,431 475 2,521 972 Interest and bank charges (Note 5 & 6) 3,230 1,051 5,799 1,878 Loss/(gain) on financial derivatives (Note 11) (2,741) (125) 1,475 (403) Depletion, depreciation and accretion (Notes 3 & 8) 21,905 7,520 41,278 15,413 Stock-based compensation expense (Note 9) 1,313 907 2,270 1,567 ------------------------------------------------------------------------- 36,080 15,471 73,835 30,247 ------------------------------------------------------------------------- EARNINGS (LOSS) BEFORE INCOME TAXES 1,971 7,513 (1,634) 16,785 ------------------------------------------------------------------------- TAXES (Note 7) Future income tax expense (recovery) (882) 56 (2,553) 3,776 Current tax expense (recovery) 306 (308) 306 (224) ------------------------------------------------------------------------- (576) (252) (2,247) 3,552 ------------------------------------------------------------------------- NET EARNINGS 2,547 7,765 613 13,233 ------------------------------------------------------------------------- OTHER COMPREHENSIVE INCOME - - - - ------------------------------------------------------------------------- COMPREHENSIVE INCOME 2,547 7,765 613 13,233 ------------------------------------------------------------------------- Retained earnings, beginning of period 35,112 21,956 36,493 16,488 Transitional adjustment upon adoption of new accounting policy (Note 2) - - 553 - Retained earnings, end of period $ 37,659 29,721 $ 37,659 29,721 ------------------------------------------------------------------------- ------------------------------------------------------------------------- EARNINGS PER SHARE (Note 9) Basic $ 0.04 0.23 $ 0.01 0.39 Diluted $ 0.04 0.22 $ 0.01 0.38 ------------------------------------------------------------------------- ------------------------------------------------------------------------- The accompanying notes form an integral part of these consolidated financial statements. KERECO ENERGY LTD. CONSOLIDATED STATEMENTS OF CASH FLOWS Three months ended Six months ended June 30 June 30 ------------------------------------------------------------------------- ($000s, unaudited) 2007 2006 2007 2006 ------------------------------------------------------------------------- OPERATING ACTIVITIES Net earnings $ 2,547 7,765 $ 613 13,233 Add items not requiring cash: Depletion, depreciation and accretion 21,905 7,520 41,278 15,413 Future income tax expense (recovery) (882) 56 (2,553) 3,776 Unrealized loss (gain) on financial derivatives (2,665) 414 2,555 166 Employee share benefit plan expense (Note 9) 29 28 58 57 Non-cash interest expense on convertible debentures (Note 6) 52 - 52 - Stock-based compensation expense 1,313 907 2,270 1,567 ------------------------------------------------------------------------- 22,299 16,690 44,273 34,212 Change in non-cash working capital (Note 10) 6,392 3,209 9,511 2,704 ------------------------------------------------------------------------- Cash provided by operating activities 28,691 19,899 53,784 36,916 ------------------------------------------------------------------------- FINANCING ACTIVITIES Issuance of common shares and warrants, net of share issue costs 115 20,795 18,929 21,238 Issuance of convertible debentures - net of issue costs 67,475 - 67,475 - Bank debt (27,684) (5,280) (36,781) 2,547 Change in non-cash working capital (Note 10) (153) (423) 320 (439) ------------------------------------------------------------------------- Cash provided by financing activities 39,753 15,092 49,943 23,346 ------------------------------------------------------------------------- INVESTING ACTIVITIES Petroleum and natural gas expenditures (19,374) (25,957) (50,421) (53,695) Property acquisitions (36,604) - (36,604) - Property dispositions 5,860 - 5,860 - Business combinations (Note 4) (71) - (484) - Change in non-cash working capital (Note 10) (18,255) (9,034) (22,078) (6,567) ------------------------------------------------------------------------- Cash used in investing activities (68,444) (34,991) (103,727) (60,262) ------------------------------------------------------------------------- CASH AND CASH EQUIVALENTS, BEGINNING AND END OF PERIOD $ - - $ - - ------------------------------------------------------------------------- ------------------------------------------------------------------------- The accompanying notes form an integral part of these consolidated financial statements. Notes to the Consolidated Financial Statements Six months ended June 30, 2007 and 2006 (Unless otherwise stated, amounts presented in these notes are in thousands of Canadian dollars) (unaudited) 1. BASIS OF PRESENTATION The interim consolidated financial statements of Kereco Energy Ltd. (the "Company" or "Kereco") have been prepared in accordance with Canadian Generally Accepted Accounting Principles ("GAAP") and are consistent with the presentation and disclosure in the audited consolidated financial statements and notes thereto for the year ended December 31, 2006 except for the changes described in note 2. "Changes in Accounting Policies ". These interim consolidated financial statements should be read in conjunction with the audited annual consolidated financial statements for the year ended December 31, 2006. 2. CHANGES IN ACCOUNTING POLICIES A) Financial Instruments Effective January 1, 2007, the Company adopted the Canadian Institute of Chartered Accountants ("CICA") section 3855, "Financial Instruments - Recognition and Measurement," section 3865, "Hedges", section 1530, "Comprehensive Income" and section 3861, "Financial Instruments - Disclosure and Presentation" and section 3251 ("Equity"). The Company has adopted these standards retroactively without restatement and comparative consolidated financial statements have not been restated. The adoption of these new financial instruments standards resulted in changes in accounting for financial instruments as well as the recognition of transitional adjustments that have been recorded into adjusted retained earnings as described below. In accordance with these new standards, all financial instruments including both financial and non financial derivatives and certain embedded derivatives qualify as assets or liabilities and need to be recorded on the balance sheet. Financial Instruments are categorized into one of five categories which determines their initial measurement value and subsequent recognition of gains and losses. Section 3251 introduces new standards for the presentation of Equity with "Accumulated other comprehensive income" as a result of the application of section 1530. Financial Instruments Upon adoption of these standards, Kereco has classified all financial instruments into one of the following five categories: 1) loans and receivables 2) assets held to maturity 3) assets available for sale 4) held for trading and 5) other liabilities. Kereco has designated its short term and long term debt as well as cash balances as held for trading. These are measured at fair value at each balance sheet date with gains and losses recognized in net earnings in the current period. The transaction costs or deferred financing costs related to Held for Trading financial assets and liabilities are expensed as incurred. The adoption of this section and designation of Held for Trading was done retroactively without restatement, and resulted in a reduction to retained earnings of $154, a reduction to the future income tax liability of $81 and the reduction of the previous deferred finance charges current asset account to nil. Kereco has designated its accounts receivable as Loans and Receivables which are accounted for at amortized cost with gains or losses recognized in net earnings in the current period. The Company's accounts payable and accrued liabilities have been designated as Other Liabilities which are also recorded at amortized cost. The convertible debentures issued by the company have been designated as "other liabilities" and therefore, the transaction costs associated with the issuance of the debentures are netted against the carrying value of the debentures and are accreted over the life of the debentures using the effective interest rate method. Kereco has not designated any financial instruments as Held to Maturity which include non-derivative financial assets with fixed or determinable payments and a fixed maturity which the Company intends to hold until maturity. These financial instruments are recognized at amortized cost. Kereco also has not designated any financial instruments as Available for Sale. Available for Sale assets are non derivative financial assets which are not designated into any of the other four categories. Available for Sale assets are carried at fair value with gains or losses recognized in other comprehensive income until realized when the cumulative gain or loss is transferred to earnings or loss. Derivatives All derivatives are classified as held for trading and are therefore carried at their fair value in the balance sheet caption "Financial Derivative Contracts". Gains or losses in the fair values between periods are recognized in net earnings through the account "Unrealized Gain or Loss on Financial Derivative Contracts". The adoption of this section resulted in the recognition of two derivatives. One was a three year contract to acquire electricity at a fixed rate and the other was a physical commodity collar sole contract. These resulted in the following retroactive adjustments without restatement: an increase in retained earnings by $707, an increase in the future tax liability of $372 and an increase in the Financial Derivative Contract asset of $1,079. Embedded Derivatives Embedded derivatives are components within a host contract that have features that are similar to a derivative. Under the new standards, the embedded derivatives are to be accounted for separately from the host contract as a derivative when their economic characteristics and risks are not clearly and closely related to those of the host instrument, the terms of the embedded derivative are the same as those of a stand alone derivative and the combined contract is not held for trading or designated at fair value. Embedded derivatives are designated as held for trading and are measured at fair value with subsequent gains or losses recognized in earnings. Kereco does not have any embedded derivatives. Comprehensive Income Comprehensive income is comprised of the Company's net earnings and other comprehensive income. Other comprehensive income is comprised of unrealized gains and losses on available for sale securities, net of taxes, and financial contracts designated as hedges among other elements. Kereco does not have any assets designated as available for sale and therefore has no other comprehensive income. The fair value of all financial instruments and derivatives are determined from the independent banks or corporations in which Kereco has entered into these contracts with. These fair values are calculated using forward market pricing forecasts at the applicable ending balance sheet dates. B) Accounting Changes In July 2006, the CICA issued a revised section 1506, "Accounting Changes". The new recommendations permit voluntary changes in accounting policy only if they result in financial statements which provide more reliable and relevant information. Accounting policy changes are applied retrospectively unless it is impractical to determine the period or cumulative impact of the change. Corrections of prior period errors are applied retrospectively and changes in accounting estimates are applied prospectively by including these changes in earnings. The guidance is effective for all changes in accounting policies, changes in accounting estimates and corrections of prior periods errors initiated in periods that began on or after January 1, 2007. C) Capital Disclosures As of January 1, 2008 the Company will be required to adopt CICA Handbook section 1535, "Capital Disclosures", which requires entities to disclose their objectives, policies and processes for managing capital, and in addition, whether the entity has complied with any externally imposed capital requirements. The Company is assessing the impact of this new standard on its consolidated financial statements and anticipates that the main impact will be in terms of additional disclosures required. 3. PROPERTY, PLANT AND EQUIPMENT As June 30, 2007 As at December 31, 2006 ------------------------------------------------------------------------- Accumulated Accumulated Depletion, Depletion, and Net and Net Depreci- Book Depreci- Book (000's) Cost ation Value Cost ation Value ------------------------------------------------------------------------- Petroleum and natural gas properties $740,669 $101,989 $638,680 $661,581 $ 61,521 $600,060 Office equipment & corporate 3,504 439 3,065 1,102 198 $ 904 ------------------------------------------------------------------------- Total $744,173 $102,428 $641,745 $662,683 $ 61,719 $600,964 ------------------------------------------------------------------------- ------------------------------------------------------------------------- The Company capitalized $0.7 million of indirect general and administrative overhead for the year to date in 2007 (June 30, 2006 - $0.2 million). $51.0 million of undeveloped land was excluded from the depletion calculation (June 30, 2006 - $26.6 million). 4. BUSINESS COMBINATIONS Chamaelo Exploration Ltd. Adjustments to the Chamaelo purchase equation were realized for the first half of 2007. Adjustments identified as part of the filing of the Chamaelo change of control tax return resulted in an increase in future tax liability of $2,063 and a corresponding increase in goodwill. Additional transaction costs in the amount of $484 related to the acquisition of Chamaelo were also realized in the first half of 2007 which resulted in an adjustment to the purchase equation with an increase in transaction costs and a corresponding increase in goodwill. Following is the adjusted purchase equation for the acquisition which has been accounted for using the purchase method which has the purchase price allocated to the fair value of the assets acquired and liabilities assumed as follows: Cost of Acquisition --------------------------------------------------------------------- Issuance of common shares $ 230,720 Transaction costs 3,265 --------------------------------------------------------------------- $ 233,985 --------------------------------------------------------------------- --------------------------------------------------------------------- Allocation of Purchase Price --------------------------------------------------------------------- Property, plant and equipment $ 302,397 Goodwill 53,899 Accounts receivable 10,870 Prepaid expenses 705 Asset retirement obligation (6,235) Future income tax liability (8,037) Accounts payable and accrued liabilities (21,887) Bank debt (97,727) --------------------------------------------------------------------- $ 233,985 --------------------------------------------------------------------- --------------------------------------------------------------------- The above allocation of purchase price is based on the best available information at this time and could be subject to change. 5. BANK DEBT At June 30, 2007 the Company had in place a syndicated committed credit facility, in the amount of $202 million, with two major Canadian Chartered Banks and the Canadian branch of a major international bank. In conjunction with the acquisition of assets in June 2007, this facility was increased in April 2007 from the previous borrowing base of $183 million. 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 June 30, 2007, $151.9 million (December 31, 2006, $188.7 million) had been drawn under the bank facility. The average interest rate on borrowings outstanding for the year to date was 6.5 percent, ($5.8 million in interest expense), including interest expense associated with the property acquisitions and dispositions realized in the quarter, compared to $1.9 million for the six months ended June 30, 2006. The entire amount drawn under the credit facility is not due within 12 months and is therefore presented as a long term liability. 6. CONVERTIBLE DEBENTURES On June 25, 2007, the Company issued $70 million of convertible unsecured subordinated debentures which mature on June 30, 2012 and bear interest of 4.75% (the "Debentures"). The interest is payable semi-annually in arrears on June 30 and December 31 each year, commencing on December 31, 2007. Each debenture can be converted into common shares of the Corporation at the option of the holder at any time prior to the close of business on June 29, 2012 at a conversion price of $10.00 per common share. The Debentures are not redeemable by the Corporation prior to June 30, 2010. On or after June 30, 2010 and prior to June 30, 2012, the Debentures may be redeemed at the option of the Corporation, in whole or in part at a redemption price equal to 100% of the principal amount of the Debentures to be redeemed plus accrued and unpaid interest to, but excluding, the redemption date provided that the Current Market Price (as defined in the Short Form Prospectus filed in conjunction with the offering) is at least 125% of the Conversion Price. The Debentures are classified as debt and equity with the equity portion representing the fair value of the conversion feature of the Debentures. As the Debentures are converted, a portion of the debt and equity amounts are transferred to share capital. The debt balance accretes over the life of the Debentures using the effective interest rate method to the amount owing on maturity and the increases in the debt balance are reflected as non cash interest expense in the consolidated statement of cash flows. The debentures are designated as "other liabilities" and the transaction costs associated with the issuance of the debentures are netted against the carrying value of the debentures and are accreted over the life of the debentures using the effective interest rate method. Following is a reconciliation of the debt and equity components of the convertible debentures: Convertible debentures - debt Issued on June 25, 2007 $ 70,000 Transaction fees and costs (2,525) Portion allocated to equity (15,519) Accretion of non cash interest expense 52 --------------------------------------------------------------------- Debt balance as at June 30, 2007 $ 52,008 --------------------------------------------------------------------- Convertible debentures - equity Issued on June 25, 2007 $ 15,519 Tax effect of transaction fees and costs 185 Conversion of debentures - --------------------------------------------------------------------- Equity balance as at June 30, 2007 $ 15,704 --------------------------------------------------------------------- 7. INCOME TAXES The total tax recovered for the year to date at June 30, 2007 was $2.2 million comprised of $2.5 million in future income tax recovery offset by $0.3 million in current income tax (June 30, 2006: expense of $3.6 million). Current taxes of $0.3 million were recognized in the quarter. This resulted from the disallowance by the Canada Revenue Agency of the majority of a Scientific Research and Experimental Development claim "(SR&ED)" made by Chariot Energy Ltd. in 2004 prior to Kereco's acquisition of Chariot in April 2005. These will not result in any further current tax expense to Kereco. This results in an effective tax rate of 138 percent for the year to date in 2007, which is largely influenced by adjustments to tax pools upon the filing of tax returns and the positive adjustments realized from reduced enacted statutory rates in 2011 being applied to a relatively lower loss before tax for the period of $1.6 million. At June 30, 2007, the Company had tax pools and non-capital losses of approximately $526.7 million, comprised of $30.6 million in Canadian Exploration Expense (CEE), $279.4 million in Canadian Oil & Gas Property Expense (COGPE), $84.5 million in Canadian Development Expense (CDE), and $106.5 million in Capital Cost Allowance (CCA) pools as well as accumulated non-capital losses for income tax purposes of approximately $25.7 million (December 31, 2006 - $14.5 million) that can be used to offset otherwise taxable income in future periods. Non capital losses of $25.7 million and expire as follows: Year of expiry ($millions) --------------------------------------------------------------------- 2010 9.2 2015 16.5 --------------------------------------------------------------------- 25.7 --------------------------------------------------------------------- --------------------------------------------------------------------- In addition to the above losses and tax pools, the Company also has accumulated capital losses of approximately $21.5 million for which no future income tax benefit has been recognized on the financial statements. 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. As of June 30, 2007 the $22.0 million had been renounced to shareholders and the related tax impact of $6.9 million was recorded as a reduction to share capital in the first quarter of 2007. Approximately $18.4 million in qualifying CEE expenditures related to this flow-through share commitment have been incurred as of June 30, 2007. On February 16, 2007, the Company issued 2,250,000 flow-through common shares for proceeds of $19.4 million before issue costs of $1.0 million which will require the Company to incur $19.4 million of flow-through share eligible Canadian Exploration Expenditures, as defined in the Canadian Income Tax Act, by December 31, 2008. 8. 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 $44.3 million (December 31, 2006: $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 June 30, 2007 asset retirement obligation is comprised of the following: --------------------------------------------------------------------- Balance at December 31, 2006 $ 16,038 --------------------------------------------------------------------- New liabilities added 325 Accretion of asset retirement obligation 569 Balance at June 30, 2007 $ 16,932 --------------------------------------------------------------------- 9. SHARE CAPITAL i) Issued and Outstanding Common Shares Common Shares Amount --------------------------------------------------------------------- Balance at the end of December 31, 2006 55,336,432 $ 438,216 --------------------------------------------------------------------- Exercise of warrants 190,900 626 Adjustment to share capital for warrants exercised - 156 Issued pursuant to flow through share offering 2,250,000 19,351 Tax effect of flow-through shares - (6,883) Amortization of common shares held for employee benefit plan - 58 Share issue costs - (1,047) Tax effect of share issue costs - 320 --------------------------------------------------------------------- Balance at the end of June 30, 2007 57,777,332 $ 450,797 --------------------------------------------------------------------- ii) On February 16, 2007, the Company issued 2,250,000 flow-through common shares for proceeds of $19.4 million before issue costs of $1.0 million. The tax impact and related reduction to share capital will be recorded when renounced in the first quarter of 2008. 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 1,710,385 of these warrants outstanding, 795,206 which vested on January 18, 2007 and the remainder will vest on January 18, 2008. 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 (1,847,665 are outstanding at June 30, 2007) warrants exercisable into Kereco common shares. The weighted average post conversion exercise price of these warrants is $10.28 per warrant. Number of Exercise Contractual Warrants Warrants Price Life Exercisable Expiry Date (000s) ($/share) (years) (000s) --------------------------------------------------------------------- January 18, 2008 795 3.12 0.6 795 January 18, 2009 915 3.12 1.6 0 May 26, 2009 278 4.12 1.9 278 June 21, 2010 1,569 11.37 3.0 1,569 --------------------------------------------------------------------- 3,558 6.84 2.0 2,643 --------------------------------------------------------------------- --------------------------------------------------------------------- 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 5,777,733 common shares reserved for issuance upon the exercise of options, of which 4,710,800 options were granted as at June 30, 2007. During the month of March, the board of directors approved the cancellation of 2,390,000 stock options which had been issued to non-insiders under Kereco's existing stock option plan. Stock-based compensation expense continues to be recognized on the cancelled options over their original life. Weighted Weighted Average Average Number Of Exercise Contractual Options Prices Life (000s) ($/share) (years) --------------------------------------------------------------------- Balance at December 31, 2006 3,650 10.34 3.7 Granted 3,720 5.78 4.9 Exercised - - - Expired or cancelled (2,659) (10.25) 3.4 --------------------------------------------------------------------- Balance June 30, 2007 4,711 6.78 4.4 --------------------------------------------------------------------- --------------------------------------------------------------------- Also during the month of March, the Company implemented a Stock Appreciation Rights ("SAR") plan under which rights were granted to officers of Kereco. Under the plan, all rights granted have a maximum term of five years, vest over a three year period at a rate of one-third per year and provide for settlement in cash. In late March, 439,875 SAR's were granted at a price of $5.79 and in June 853,875 SAR's were granted at a price of $5.73. As at June 30, 2007, there are a total of 1,293,750 SAR's outstanding at an average price of $5.75. Compensation expense for options granted and share purchase warrants issued by the Company is based on the estimated fair values at the time of their grants and is recognized as expense over the vesting periods of the options and share purchase warrants. Compensation expense for SARs is calculated based upon the intrinsic value and is recognized as expense over the vesting periods of the SARS. The Company recognized $2.3 million of non-cash stock-based compensation expense for the first half (expense of $1.6 million for the first half of 2006) with an equal amount recorded in contributed surplus. $11 thousand in non-cash stock based compensation expense is from the SARs and $156 thousand was transferred out of contributed surplus to share capital for employee warrants which were exercised in the first half. The fair value of each option and share purchase warrant has been determined as at each stock option grant date using a Black-Scholes model. For the options currently outstanding, the average terms used are: risk free interest rate - 4.28 percent, expected life - 4 years, and volatility - 35 percent. The weighted average fair value of the options outstanding is $2.30 per option. No estimate has been made for expected forfeitures as they are addressed when they occur. Additional details on the Company's stock options outstanding at June 30, 2007 are as follows: Weighted Weighted Average Average Range of Number of Exercise Contractual Options Exercise Prices Options Price Life Exercisable ($/share) (000s) ($/share) (years) (000s) --------------------------------------------------------------------- 5.39 - 7.24 3,565 5.74 4.9 13 8.93 - 9.80 641 9.37 3.1 301 10.50 - 11.20 505 10.84 2.9 306 --------------------------------------------------------------------- 5.39 - 11.20 4,711 6.78 4.4 620 --------------------------------------------------------------------- --------------------------------------------------------------------- v) Employee Benefit Plan During 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 June 30, 2007, $58 has been expensed and recorded to share capital (June 30, 2006: $57). 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: Three months ended Six months ended June 30 June 30 2007 2006 2007 2006 --------------------------------------------------------------------- Net earnings $ 2,547 $ 7,765 $ 613 $ 13,233 Net earnings per share Basic $ 0.04 $ 0.23 $ 0.01 $ 0.39 Diluted $ 0.04 $ 0.22 $ 0.01 $ 0.38 Weighted average shares outstanding Basic 57,774,838 34,118,882 57,143,506 33,922,554 Options and warrants 1,044,742 985,368 1,026,884 1,205,260 --------------------------------------------------------------------- Diluted 58,819,580 35,104,250 58,170,390 35,127,814 Common shares outstanding at period end --------------------------------------------------------------------- Basic 57,777,332 35,256,245 57,777,332 35,256,245 Options and warrants 8,268,850 4,881,282 8,268,850 4,881,282 --------------------------------------------------------------------- Diluted 66,046,182 40,137,527 66,046,182 40,137,527 --------------------------------------------------------------------- --------------------------------------------------------------------- 10. SUPPLEMENTAL CASH FLOW INFORMATION i) Changes in Non-Cash Working Capital Three months ended Six months ended June 30 June 30 2007 2006 2007 2006 --------------------------------------------------------------------- Decrease (increase) in non-cash working capital: Accounts receivable $ 10,362 $ 2,466 $ 2,209 $ 3,832 Prepaid expenses (1,191) (932) 186 (935) Accounts payable and accrued liabilities (21,187) (7,782) (14,642) (7,199) --------------------------------------------------------------------- Change in non-cash working capital $ (12,016) $ (6,248) $ (12,247) $ (4,302) --------------------------------------------------------------------- Relating to: Operating activities 6,392 3,209 9,511 2,704 Financing activities (153) (423) 320 (439) Investing activities (18,255) (9,034) (22,078) (6,567) --------------------------------------------------------------------- Change in non-cash working capital $ (12,016) $ (6,248) $ (12,247) $ (4,302) --------------------------------------------------------------------- --------------------------------------------------------------------- ii) Other Cash Flow Information Three months ended Six months ended June 30 June 30 2007 2006 2007 2006 --------------------------------------------------------------------- Cash taxes paid $ - $ - $ - $ 435 Cash interest paid $ 2,980 $ 1,051 $ 5,549 $ 1,878 --------------------------------------------------------------------- --------------------------------------------------------------------- 11. RISK MANAGEMENT & FINANCIAL INSTRUMENTS The following financial derivative and physical sales contracts were outstanding on June 30, 2007: Oil and Natural Gas Price risk management Period Volume Type Pricing terms(1) --------------------------------------------------------------------- Natural Gas Jul 1, 2007 14,000 GJ/day Financial Collar $6.79 - $8.79 - Oct 31, 2007 (AECO CDN$/GJ) Nov 1, 2007 10,000 GJ/day Financial Collar $7.35 - $11.67 - Mar 31, 2008 (AECO CDN$/GJ) Crude Oil Jul 1, 2007 1,750 bbls/day Financial Collar $62.43 - $88.34 - Dec 31, 2007 (WTI US$/BBL) Jan 1, 2008 1,500 bbls/day Financial Collar $61.50 - $78.88 - Dec 31, 2008 (WTI US$/BBL) --------------------------------------------------------------------- (1) Collar price indicates minimum floor and maximum ceiling. Power Consumption price risk management Period Volume Type Pricing terms --------------------------------------------------------------------- Electricity July 1, 2007 3.5 MW Fixed Price $65.50/ - Dec 31, 2008 megawatthour --------------------------------------------------------------------- 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 June 30, 2007, the Company had recognized a financial derivative contract asset of $3.5 million (December 31, 2006: asset of $5.0 million). 12. 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 $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 $18.4 million in qualifying CEE expenditures related to this flow-through share commitment had been spent to June 30, 2007. On February 16, 2007, the Company issued 2,250,000 flow-through common shares for proceeds of $19.4 million before issue costs of $1.0 million which will require the Company to incur $19.4 million of flow-through share eligible CEE, as defined in the Canadian Income Tax Act, by December 31, 2008. The Company has executed separate contracts with two large drilling contractors for the exclusive use of two specific drilling rigs. One contract is a three year contract which commenced in December of 2006 and requires Kereco to utilize the rig for a minimum of 225 days per year. If not utilized Kereco is obligated to pay a minimum $5,800 rate per day. The second contract is a two year contract which commenced June 1, 2007 and requires Kereco to utilize the rig for a minimum of 225 days per year for two years. If not utilized Kereco is obligated to pay a minimum $4,785 rate per day. During the first half of 2007, the Company signed a nine year office lease which commences on February 1, 2008. Annual payments under the lease will be $1.6 million. 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: Drilling Electricity ($000s) contracts Office lease contract --------------------------------------------------------------------- 2007 $ 1,014 $ - $ 1,004 2008 $ 2,382 $ 1,509 $ 2,008 2009 $ 1,754 $ 1,509 $ - 2010-2016 $ - $ 10,591 $ - --------------------------------------------------------------------- 13. RELATED PARTY TRANSACTIONS During 2006 and 2007, Kereco conducted business with a company controlled by a director of Kereco. These transactions were made under normal business terms and conditions at the same rates as with non-related parties. Transactions in the amount of $0.8 million were conducted in the first half of 2007 and $250,000 in the fourth quarter of 2006. None of these amounts remained outstanding at each respective period end. 14. 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 circumstance 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 Executive Calgary, Alberta Officer Société Générale (Canada Branch) Nathan R. MacBey Calgary, Alberta Vice President, Negotiations ENGINEERING CONSULTANTS David M. Mombourquette Vice President, GLJ Petroleum Consultants Ltd. Business Development Calgary, Alberta Stephen C. Nikiforuk LEGAL COUNSEL Vice President, Finance and Chief Financial Officer Burnet Duckworth & Palmer LLP Calgary, Alberta Anthony (Tony) L. Smith Vice President, Land REGISTRAR AND TRANSFER AGENT Kirby J. Wanner Computershare Trust Company of Canada Chief Operating Officer Calgary, Alberta DIRECTORS WARRANT AGENT Daryl E. Birnie Valiant Trust Company Calgary, Alberta J. Paul Charron STOCK EXCHANGE LISTING Grant B. Fagerheim Toronto Stock Exchange Daryl H. Gilbert Trading Symbol "KCO" Barry M. Heck HEAD OFFICE Brian M. Krausert 1400, 530 - 8th Avenue SW Calgary, Alberta T2P 3S8 Peter J. Kurceba Telephone: (403) 290-3400 Gerry A. Romanzin Facsimile: (403) 290-3447 Email: info@kereco.com Grant A. Zawalsky Website: www.kereco.com AUDITORS Deloitte & Touche LLP Chartered Accountants Calgary, Alberta ABBREVIATIONS AECO Alberta Energy Company interconnect with the Nova System ARTC Alberta Royalty Tax Credit bbls barrels bbls/day barrels per day bcf billion cubic feet boe barrels of oil equivalent (6mcf = 1bbl) GJ gigajoule GJ/day gigajoule per day kWh Kilo watt hour mbbls thousand barrels mboe thousand barrels of oil equivalent mboe/day thousand barrels of oil equivalent per day Mcf thousand cubic feet mcf/day thousand cubic feet per day mmbbls million barrels mmboe million barrels of oil equivalent mmbtu million British thermal units mmcf million cubic feet mmcf/day million cubic feet per day MWh Mega watt hour NGLs natural gas liquids NI Canadian Securities Administrator's National Instrument WI Working Interest WTI West Texas Intermediate

For further information:

For further information: Grant B. Fagerheim, President and Chief
Executive Officer, Telephone: (403) 290-3401; or Stephen C. Nikiforuk, Vice
President, Finance and Chief Financial Officer, Telephone: (403) 290-3404

Organization Profile

KERECO ENERGY LTD.

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