Kereco Energy Ltd. Announces Third Quarter 2007 Results



    CALGARY, Nov. 6 /CNW/ - Kereco Energy Ltd. ("Kereco") or the ("Company")
is pleased to announce operational and financial results for the third quarter
and first nine months of 2007.

    
    FINANCIAL AND OPERATING HIGHLIGHTS

    -------------------------------------------------------------------------
    FINANCIAL                Three months ended            Nine months ended
                                   September 30                 September 30

    ($000s, unless                            %                            %
    otherwise indicated) 2007      2006  Change       2007      2006  Change
    -------------------------------------------------------------------------
    Petroleum and
     natural gas
     sales             43,697    31,264      40    136,254    91,921      48
    Funds flow
     from operations   23,345    17,422      34     67,618    51,634      31
      Per share
       - basic ($)       0.40      0.49     (18)      1.18      1.50     (21)
      Per share
       - diluted ($)     0.40      0.48     (17)      1.18      1.45     (19)
    Net earnings
     (loss)(1)       (122,643)    7,006  (1,851)  (122,030)   20,239    (703)
      Per share
       - basic(1)       (2.12)     0.20  (1,160)     (2.13)     0.59    (461)
      Per share
       - diluted(1)     (2.12)     0.19  (1,216)     (2.13)     0.57    (474)
    Capital
     expenditures
      Exploration and
       development     38,914    25,470      53     89,335    79,165      13
      Net
       acquisitions
       and
       dispositions      (352)    7,475    (105)    30,392     7,475     306
    -------------------------------------------------------------------------
      Total            38,562    32,945      17    119,727    86,640      38
    -------------------------------------------------------------------------
    Bank debt         150,713    84,695      78    150,713    84,695      78
    Working capital
     deficiency(2)     11,609     8,525      36     11,609     8,525      36
    -------------------------------------------------------------------------
    Total net
     debt(3)          162,322    93,220      74    162,322    93,220      74
    -------------------------------------------------------------------------
    Shareholders'
     equity           391,373   249,425      57    391,373   249,425      57
    Common shares
     outstanding at
     the end of
     period (000s)
      Basic            57,777    35,256      64     57,777    35,256      64
      Diluted          66,051    40,292      64     66,051    40,292      64
    Weighted average
     common shares
     outstanding
     (000s)
      Basic            57,777    35,256      64     57,357    34,372      67
      Diluted(4)       57,777    36,193      60     57,357    35,520      61
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    OPERATING
     HIGHLIGHTS(5)
    Average daily
     production
      Natural gas
       (mcf/day)       26,364    13,579      94     27,021    15,039      80
      Crude oil
       and NGLs
       (bbls/day)       4,295     3,193      35      4,376     3,082      42
      Barrels of oil
       equivalent
       (boe/day)        8,689     5,456      59      8,880     5,589      59
    Average selling
     prices(6)
      Natural gas
       ($/mcf)           5.66      6.36     (11)      7.17      7.17       -
      Crude oil and
       NGLs ($/bbl)     73.24     75.94      (4)     67.11     70.95      (5)
      Barrels of oil
       equivalent
       ($/boe)          53.38     60.26     (11)     54.89     58.42      (6)
    Wells
     drilled (No.)
      Gross              14.0       5.0     180       33.0      22.0      50
      Net                12.4       2.0     520       27.3      15.1      81
      Success (%)          93       100      (7)        85        86      (1)
    Undeveloped land
     (000s of acres)
      Gross               348       151     130        348       151     130
      Net                 238        92     159        238        92     159
    Average working
     interest (%)          68        61      12         68        61      12
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    (1) Includes goodwill impairment write-down of $119.3 million in the
        third quarter of 2007.
    (2) Excluding financial derivative contracts.
    (3) Net debt - excludes debt associated with the $70 million principal
        amount of convertible debentures issued June 25, 2007.
    (4) Excludes anti-dilutive incremental options and warrants of 580,064
        and 908,926 for the third quarter and the year to date respectively.
    (5) 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.
    (6) 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 third quarter and nine months ended September 30,
2007.
    As expected, Kereco had an active quarter - both in drilling and
operational activities. During the quarter, we executed a $38.6 million
exploration and development capital program, participating in the drilling of
14 wells with 93% success - casing 13 wells (nine oil and four gas wells) and
abandoning one. From a production standpoint, we produced an average of
8,689 boe/day - slightly below the lower end or our previous guidance for the
quarter of 8,800 to 9,200 boe/day. As anticipated, we executed the major plant
and field turnaround at Sturgeon Lake which resulted in the entire production
from the area being down for 24 days of the quarter. As experienced in
previous turnarounds at Sturgeon Lake, after a shutdown of this duration many
of the wells in the field take a period of time to return to their
pre-shutdown rates and, although a significant amount had not by the end of
September, we are pleased that the plant and field have now returned to their
pre-turnaround production and efficiency rates.
    The following is a summary of our third quarter 2007 accomplishments:

    
    1.  Capital Expenditures

        -  Spent $38.6 million on exploration and development activities.

    2.  Wells Drilled

        -  Drilled 14 wells with 93% success resulting in 9 oil wells, 4 gas
           wells and one well that did not reach projected total drilling
           depth.

    3.  Production

        -  Third quarter 2007 average production was 8,689 boe/day, a 59%
           increase over the third quarter of 2006 and a 9% decrease from the
           second quarter of 2007, due mainly to the anticipated full
           turnaround in the third quarter of 2007 at Sturgeon Lake.

    4.  Funds Flow

        -  Funds flow from operations for the third quarter of 2007 was
           $23.3 million ($0.40 per basic share), a 34% increase from the
           third quarter of 2006.
    

    Also in the quarter, as a result of a decline in the market valuation for
Kereco versus the valuation Kereco had when we acquired both Chariot Energy
Inc. (April 19, 2005) and Chamaelo Exploration Ltd. (October 19, 2006), we
have taken a non-cash charge against earnings for our entire pre-existing
balance of goodwill - $119 million, all of which related to those two
acquisitions. Based on our updated reserves, as press released on September 4,
2007 (pre Alberta New Royalty Framework) and October 31, 2007 (including the
Alberta New Royalty Framework), we still have a cushion (excess) on our
ceiling test and therefore there has been no impairment of property plant and
equipment.
    On September 18, 2007 the Alberta Royalty Review Panel ("ARRP"), a panel
commissioned by the Government of Alberta to review the province's royalty
regime, issued their recommendations. Those recommendations were the subject
of a very lively public debate involving not only our industry, but all
Albertans that ensued following its release. The debate was answered with the
Government of Alberta releasing their proposed New Royalty Framework ("NRF")
on October 25, 2007. Although the recommendations in the NRF did serve to make
future investments in our industry less attractive, we nevertheless now have
some certainty with respect to what the rules will likely be after January 1,
2009 and can plan our business accordingly. On October 31, 2007, we press
released that the impact to our current reserves and our estimated 2009 cash
flows on those reserves as a result of the proposed NRF to be both less than
5%. However, this analysis did not attempt to estimate what impact, if any,
future capital spending might have on our future reserves or cash flows in
2009 and beyond.

    OUTLOOK

    As we had mentioned in our second quarter report, our current objective
is to reposition Kereco to withstand the current soft investment environment
that has precipitated from lower than required economic returns from natural
gas drilling, higher labour and service costs and volatile capital markets.  
The first stage of the repositioning process that was commenced on July 18,
2007, was to perform a mid-year update of our reserves and have them
re-evaluated by GLJ Petroleum Consultants Ltd. ("GLJ").  On September 4, 2007
we released the results of that review and also further updated that review on
October 31, 2007 to incorporate the impact of the proposed NRF.  A Special
Committee of the Board of Directors of Kereco has now been formed and will
continue to work with management and our advisors, BMO Capital Markets Inc.,
GMP Securities L.P. and Tristone Capital Inc., to determine the optimal future
strategic direction of the Company.  Kereco will be proceeding with the
disposition of approximately 1,700 boe/day of non-core assets to multiple
industry participants and we are actively working towards the conclusion of
that process.  Above and beyond the dispositions, we are continuing to also
consider a multitude of various alternatives for the remaining components of
the Company and hope to be able to report back to you on those alternatives in
the coming weeks.
    During the fourth quarter, we plan to tie-in the production we have
behind pipe from capital activities earlier in the year and limit the amount
of capital we direct specifically towards natural gas drilling prospects as we
are cautious about the near term economic environment for natural gas.  Our
expectation is to spend less than $25 million in capital in the fourth
quarter.  As a result of the property dispositions we expect to conclude in
the fourth quarter of approximately 1,700 boe/day, we anticipate production
for the fourth quarter to average approximately 9,400 and 9,800 boe/day,
inclusive of the majority of our successful drilling and optimization program
for 2007 to date.
    In addition to the challenges of lower natural gas prices, higher than
acceptable service costs and a strengthening Canadian dollar, we must now also
consider the effects on investment as a result of higher future royalty rates.
 Contrasting these negative factors is the fact that we are experiencing WTI
oil prices that have recently touched record high levels of $96.00/bbl.
    We believe that there are long term future opportunities that exist in
the Canadian oil and gas business and we look forward to being able to
communicate back to you shortly on how we plan to reposition Kereco to take
advantage of them.
    Thank you again for your continued interest in Kereco.

    On behalf of the Board of Directors,

    Grant B. Fagerheim
    President and Chief Executive Officer
    November 6, 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 nine months ended September 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 November 6, 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 third quarter of 2007 averaged 8,689 boe/day
(26,364 mcf/day of natural gas and 4,295 bbls/day of crude oil and NGLs) up 59
percent from the 5,456 boe/day (13,579 mcf/day of natural gas and
3,193 bbls/day of crude oil and NGLs) averaged in the third quarter of 2006.
Production over the first nine months of 2007 averaged 8,880 boe/day
(27,021 mcf/day of natural gas and 4,376 bbls/day of crude oil and NGLs) also
up 59 percent from the 5,589 boe/day (15,039 mcf/day of natural gas and
3,082 bbls/day of crude oil and NGLs) averaged in the nine months of 2006.
Capital expenditures in the third quarter of 2007 were $38.6 million on
exploration and development which included drilling 14 wells which resulted in
four cased gas wells, nine cased oil wells and one abandoned well - 93 percent
success. Two gas wells and four oil wells were completed in our Central
Alberta area, five oil wells were completed in our Sturgeon area, and two gas
wells were completed in the Sikanni and Fireweed areas of British Columbia.
The one well that was not successful was in the Fireweed area of British
Columbia where drilling problems were encountered before projected total
drilling depth was reached and we elected to abandon the well rather than
continue drilling.

    
    Selected Quarterly Information

    -------------------------------------------------------------------------
                                                                        2007
    -------------------------------------------------------------------------
    ($000s, except per share amounts)                   Q3       Q2       Q1
    -------------------------------------------------------------------------
    Revenues (net of royalties)                     33,485   38,051   34,150
    Funds flow from operations                      23,345   22,299   21,974
      Per share - basic ($)                           0.40     0.39     0.39
      Per share - diluted ($)                         0.40     0.38     0.38
    -------------------------------------------------------------------------
    Net earnings (loss)                           (122,643)   2,547   (1,934)
      Per share - basic ($)                          (2.12)    0.04    (0.03)
      Per share - diluted ($)                        (2.12)    0.04    (0.03)
    -------------------------------------------------------------------------
    Total assets                                   697,275  806,637  784,570
    -------------------------------------------------------------------------
    Bank debt                                      150,713  151,892  179,576
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    -------------------------------------------------------------------------
                                                               2006     2005
    -------------------------------------------------------------------------
    ($000s, except per
    share amounts)                   Q4        Q3       Q2       Q1       Q4
    -------------------------------------------------------------------------
    Revenues (net of royalties)  31,461    24,152   22,984   24,048   28,312
    Funds flow from operations   20,592    17,422   16,690   17,522   20,984
      Per share - basic ($)        0.40      0.49     0.49     0.52     0.62
      Per share - diluted ($)      0.39      0.48     0.48     0.50     0.59
    -------------------------------------------------------------------------
    Net earnings (loss)            (234)    7,006    7,765    5,468    9,381
      Per share - basic ($)       (0.01)     0.20     0.23     0.16     0.28
      Per share - diluted ($)     (0.01)     0.19     0.22     0.16     0.26
    -------------------------------------------------------------------------
    Total assets                767,411   391,933  364,342  347,063  328,267
    -------------------------------------------------------------------------
    Bank debt                   188,673    84,695   74,284   79,565   71,737
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Decreases in revenues and funds flow from operations in the first quarter
of 2006 compared to the fourth quarter of 2005 were driven predominantly by
lower natural gas prices. Relatively flat production volumes and commodity
prices in the first, second and third quarters of 2006 resulted in relatively
flat revenues and funds flow from operations over that period. The pronounced
increase in revenues and funds flow from operations in the fourth quarter of
2006 was largely a result of the Chamaelo acquisition which closed on
October 19, 2006 and whose results are included from that point forward. The
increase in revenue from the first quarter of 2007 to the second quarter of
2007 was a result of increased production volumes followed by reduced revenues
in the third quarter of 2007 from lower production volumes related to the
Sturgeon Lake plant turnaround, and reduced natural gas prices. Losses
realized in fourth quarter of 2006 and first quarter of 2007 in addition to
lower earnings in the second quarter of 2007 are predominantly due to higher
depletion, depreciation and accretion resulting from the Chamaelo acquisition.
The substantial loss recognized in the third quarter of 2007 is a result of
the recognition of a goodwill impairment of the goodwill recognized with both
the Chariot and Chamaelo acquisitions.

    FUNDS FLOW FROM OPERATIONS

    Funds flow from operations increased 34 percent in the third quarter of
2007 to $23.3 million or $0.40 per share on a diluted basis from
$17.4 million, or $0.48 per share on a diluted basis for the third quarter of
2006, largely as a result of increased production volumes over the two
respective periods. Funds flow from operations increased 31 percent in the
first nine months of 2007 to $67.6 million or $1.18 per share on a diluted
basis from $51.6 million, or $1.45 per share on a diluted basis for the first
nine months 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       Nine months ended
                                        September 30            September 30
    ($000s)                         2007        2006        2007        2006
    -------------------------------------------------------------------------
    Cash provided
     by operating activities      20,644      21,879      74,428      58,795
    Change in non-cash
     working capital               2,701      (4,457)     (6,810)     (7,161)
    -------------------------------------------------------------------------
    Funds flow from operations    23,345      17,422      67,618      51,634
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    Net Operating Income

                                  Three months ended       Nine months ended
                                        September 30            September 30
    ($000s, except per
     share amounts)                 2007        2006        2007        2006
    -------------------------------------------------------------------------
    Natural gas sales             14,264       8,308      54,438      30,332
    Crude oil and NGLs sales      29,433      22,956      81,816      61,589
    Transportation                (1,028)     (1,015)     (3,180)     (2,791)
    Realized financial
     derivative gain               2,678         665       3,758       1,234
    -------------------------------------------------------------------------
    Total net sales               45,347      30,914     136,832      90,364
    Royalty expenses             (10,212)     (7,112)    (30,568)    (20,737)
    Operating expenses            (7,889)     (4,965)    (26,229)    (14,009)
    -------------------------------------------------------------------------
    Net operating income          27,246      18,837      80,035      55,618
    -------------------------------------------------------------------------
      Per share - Basic ($)         0.47        0.53        1.40        1.62
                - Diluted ($)       0.47        0.52        1.40        1.57
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    OPERATING NETBACKS

                                  Three months ended       Nine months ended
                                        September 30            September 30
    -------------------------------------------------------------------------
                                    2007        2006        2007        2006
    -------------------------------------------------------------------------
    Boe netback ($/boe)
      Sales price                  54.66       62.28       56.20       60.25
      Transportation               (1.28)      (2.02)      (1.31)      (1.83)
      Realized gain on
       financial derivatives        3.35        1.32        1.55        0.81
    -------------------------------------------------------------------------
      Sales price, net of
       transportation and
       realized gain on
       financial derivatives       56.73       61.58       56.44       59.23

      Royalty expenses - ($/boe)  (12.77)     (14.17)     (12.61)     (13.59)
                       - (%)       23.90       23.50       23.00       23.30
      Operating expenses           (9.87)      (9.89)     (10.82)      (9.18)
    -------------------------------------------------------------------------
      Netback                      34.09       37.52       33.01       36.46
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Natural gas netback ($/mcf)
      Sales price                   6.99        8.12        8.42        8.48
      Transportation               (1.33)      (1.76)      (1.25)      (1.31)
      Realized gain on
       financial derivatives        1.10        0.64        0.39        0.34
    -------------------------------------------------------------------------
      Sales price, net of
       transportation and
       realized gain on
       financial derivatives        6.76        7.00        7.56        7.51

      Royalty expenses - ($/mcf)   (1.36)      (1.42)      (1.57)      (1.64)
                       - (%)       23.90       22.40        22.0       22.80
      Operating expenses           (1.65)      (1.66)      (1.81)      (1.53)
    -------------------------------------------------------------------------
      Netback                       3.75        4.10        4.18        4.34
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Crude oil and
     NGL netback ($/bbl)
      Sales price                  74.48       78.15       68.48       73.20
      Transportation               (1.24)      (2.21)      (1.37)      (2.25)
      Realized gain on
       financial derivatives        0.00       (0.46)       0.72       (0.18)
    -------------------------------------------------------------------------
      Sales price, net of
       transportation realized
       gain on financial
       derivatives                 73.24       75.48       67.83       70.77
      Royalty expenses - ($/bbl)  (17.62)     (18.15)     (15.86)     (16.67)
                       - (%)       24.10       23.90       23.60       23.50
      Operating expenses           (9.81)      (9.83)     (10.78)      (9.16)
    -------------------------------------------------------------------------
      Netback                      45.81       47.50       41.19       44.94
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    PETROLEUM AND NATURAL GAS SALES

    Production for the third quarter of 2007 averaged 8,689 boe/day and net
realized prices of $53.38/boe resulted in revenues of $43.7 million, a 59
percent increase in production and an 11 percent decrease in realized prices
compared to the third quarter of 2006 which had production of 5,456 boe/day
and net realized prices of $60.26/boe. Production increases in the third
quarter of 2007 compared to the third quarter of 2006 were a result of
additional production from the acquisition of Chamaelo on October 19, 2006,
and the Ferrier property acquisition which closed late in the second quarter
of 2007. Additional production from these acquisitions is included in the
entire third quarter 2007 production results. These were offset by higher
production declines over the two respective periods, mainly from our north
eastern British Columbia property in addition to lower production from our
Sturgeon Lake property as a result of the planned Sturgeon plant and field
turnaround. The main Sturgeon Lake plant went through a full turnaround in the
third quarter which required shutting in production in the entire field for a
period of 24 days. As anticipated, this resulted in lost production of 950
boe/day in the quarter.
    Average price realizations for the third quarter of 2007, net of
transportation costs, were $53.38/boe ($5.66/mcf for natural gas, $73.24/bbl
for crude oil and NGLs). Financial derivative contracts in place resulted in
realized gains of $2.7 million ($3.35/boe) for the third quarter.
Comparatively, average price realizations for the third quarter of 2006, net
of transportation costs, were $60.26/boe ($6.36/mcf for natural gas,
$75.94/bbl for crude oil & NGLs). Financial derivative contracts in place
resulted in realized gains of $0.7 million ($1.32/boe) for the third quarter
of 2006. The change in price realizations tracked changes in the underlying
commodity prices over these periods. WTI crude oil averaged U.S. $75.33/bbl
for the third quarter of 2007, seven percent higher than the U.S. $70.55/bbl
averaged in the third quarter of 2006. We realized slightly lower oil and
liquids prices in lieu of this as a result of lower NGL prices, the increased
value of the Canadian dollar and widening differentials between Edmonton light
sweet and WTI over these two respective periods. The average daily index AECO
natural gas price ($Cdn/mcf) price was $5.18/mcf for the third quarter of
2007, eight percent lower than $5.65/mcf from the third quarter of 2006, and
the average monthly index AECO natural gas price was $5.61/mcf for the third
quarter of 2007, seven percent lower than $6.03/boe from the third quarter of
2006. We market a relatively even mix of our natural gas at both AECO daily
index and at AECO monthly index pricing.
    For the first nine months of 2007, production averaged 8,880 boe/day and
net realized prices of $54.89/boe resulted in revenues of $136.3 million, a 59
percent increase in production and a six percent decrease in realized prices
compared to the first nine months of 2006 which had production of
5,589 boe/day and net realized prices of $58.42/boe. Production increases over
the first nine months of 2007, when compared to the first nine months of 2006,
were also a result of additional production from the acquisition of Chamaelo
on October 19, 2006, and the Ferrier acquisition in June of 2007 which are
reflected in the year to date production totals from these acquisition dates
forward. These increases were offset however by several factors for the year
to date. One factor was higher production declines over the two respective
periods, mainly from our north eastern British Columbia property. The first
quarter of 2007 had reduced production as a result of the Pembina sales line
hydrate problem, third party facility downtime and performance issues at
Sturgeon Lake and Wilson Creek. The second quarter saw performance issues at
Pembina and a power outage at Sturgeon caused by a lightning strike at the
power substation that services the plant and field. The Sturgeon plant
turnaround, as discussed above, also negatively impacted production in the
third quarter of 2007.
    Average price realizations for the first nine months of 2007, net of
transportation costs, were $54.89/boe ($7.17/mcf for natural gas, $67.11/bbl
for crude oil and NGLs). Financial derivative contracts in place resulted in
realized gains of $3.8 million ($1.55/boe) for the first nine months of 2007.
Comparatively, average price realizations for the first nine months of 2006,
net of transportation costs, were $58.42/boe ($7.17/mcf for natural gas,
$70.95/bbl for crude oil & NGLs). Financial derivative contracts in place
resulted in realized gains of $1.2 million ($0.81/boe) for the first nine
months of 2007. The change in price realizations tracked changes in the
underlying commodity prices over these periods. WTI crude oil averaged
U.S.$66.21/bbl for the first nine months of 2007, three percent lower than
U.S. $68.29/bbl averaged in the first nine months of 2006. The average daily
index AECO natural gas price ($Cdn/mcf) price was $6.54/mcf for the first nine
months of 2007, relatively unchanged from $6.40 in 2006 and the average
monthly index AECO natural gas price was $6.81/mcf for the first nine months
of 2007, five percent lower than $7.19/boe from the first nine months 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. An increase in the
value of the Canadian dollar versus the U.S. dollar negatively impacts our net
price realizations. The average Canada/U.S. exchange rate for the first nine
months of 2007 increased to average 1.10 compared to 1.13 for the first nine
months of 2006. The exchange rate for the third quarter of 2007 averaged 1.04
and it is continuing to increase in value having recently reached parity with
the U.S. dollar.

    Realized Financial Derivatives

    On an ongoing basis we enter into several financial and physical
commodity contracts to assist in minimizing exposure to commodity prices. 
Gains from our natural gas financial derivative contracts of $3.8 million were
realized in the first nine months of 2007 compared to a gain of $1.2 million
in the first nine months of 2006. All of our remaining October natural gas
contracts were closed out in late September which resulted in the realization
of $0.7 million in gains which are included in the $3.8 million for the year
to date. Subsequent to September 30, 2007 all of remaining Nov 2007 - March
2008 natural gas financial derivative contracts were also unwound, resulting
in additional realized gains of $1.6 million, all to be realized in the fourth
quarter of 2007.

    Transportation Costs

    Transportation costs decreased to $1.29/boe in the third quarter of 2007
compared to $2.02/boe for the third quarter of 2006 which were largely
influenced by the transportation expenses associated with prior period sales
recorded in the third quarter of 2006. Transportation costs remained static at
$1.0 million over the two respective periods. The higher transportation costs
in the third quarter of 2006 resulted from increased expenses from prior
period gas byproducts and additional transportation expenses associated with
the Blair Creek facility being recognized. For the first nine months of 2007
transportation costs decreased to $1.31/boe from $1.84/boe in the first nine
months of 2006. Transportation expenses are expected to be in the $1.30 -
$1.40/boe range on a go forward basis.

    Royalties

    Our royalty burdens are predominantly Crown, along with some overriding,
freehold and net profits interest royalties ("other royalties"). For the third
quarter of 2007, average royalty rates increased slightly to 23.9 percent
(Crown royalties of 18.6 percent and other royalties of 5.3 percent) compared
to 23.5 percent (Crown royalties of 21.9 percent and other royalties of 1.6
percent) for the third quarter of 2006. For the first nine months of 2007,
average royalty rates decreased slightly to 23.0 percent (Crown royalties of
19.1 percent and other royalties of 3.9 percent) compared to 23.3 percent
(Crown royalties of 21.5 percent and other royalties of 1.8 percent) compared
to the first nine months 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. Third quarter "other royalties" also increased as a result of
additional overriding royalties associated with the Willesden Green area and
the non-recurring catch up payment of a prior period royalty on these
properties. Decreases in the crown rate were a result of operating cost and
capital cost royalty adjustments being recognized in the quarter based upon
our recent successful submission of additional capital cost allowance
applications with the Alberta government. Kereco's overall corporate royalty
rate is expected to be maintained at the 22 to 23 percent level for the
remainder of 2007.

    CASH COSTS

    Cash costs (operating, general and administrative and interest) increased
to $14.97/boe in the third quarter of 2007 compared to $12.79/boe in the third
quarter of 2006. Cash costs increased to $15.91/boe in the first nine months
of 2007 compared to $12.00/boe in the first nine months 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 remained relatively static in the
third quarter of 2007 at $9.87/boe ($1.65/mcf for natural gas and $9.81/bbl
for crude oil and NGLs) compared to third quarter of 2006 costs of $9.89/boe
($1.66/mcf for natural gas and $9.83/bbl for crude oil and NGLs). Operating
costs for the first nine months of 2007 increased slightly to $10.82/boe
($1.81/mcf for natural gas and $10.78/bbl for crude oil and NGLs) compared to
$9.18/boe ($1.53/mcf for natural gas and $9.16/bbl for crude oil and NGLs).
The increase in costs over these respective periods is largely attributable to
the lower production volumes than expected for the year to date, the
realization of higher than expected costs on the Chamaelo assets and higher
power costs associated with our Sturgeon Lake property. Reduced costs in the
third quarter of 2007 benefited from lower prior period expenditures being
recognized in the quarter than were originally expected in addition to a lower
cost rate being realized from our Willesden Green and Ferrier areas.
    We expect our operating cost rate to decline and should be approximately
$10.00/boe for the fourth quarter of 2007.

    General and Administrative Expenses

    General and Administrative ("G&A") costs increased 47 percent on a boe
basis to $1.18/boe for the third quarter of 2007 from $0.81/boe in the third
quarter of 2006. Total costs increased to $0.9 million for the third quarter
of 2007 compared to $0.4 million for the third quarter of 2006. G&A costs
increased 58 percent on a boe basis to $1.43/boe for the first nine months of
2007 from $0.90/boe in the first nine months of 2006. Total costs increased to
$3.5 million for the first nine months of 2007 compared to $1.4 million for
the first nine months of 2006. The increase in total costs is a result of
increased staff levels and support costs in the first nine months 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 be maintained at the first nine months of 2007 rate for the remainder of
the year.

    Interest Expense

    Interest expense increased to $3.9 million in the third quarter of 2007
compared to $1.1 million in the third quarter of 2006. The $3.9 million of
third quarter interest expense is comprised of $2.2 million in bank debt
interest expense, and $0.9 million of accrued interest related to the 4.75%
convertible debenture and $0.8 million in 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 third
quarter of 2007 was $150.7 million (at an average interest rate of 6.1
percent) compared to $73.9 million (at an average interest rate of 5.64
percent) for the third 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, cash-based interest expense increased to $3.92/boe in the
third quarter of 2007 compared to $2.09/boe in the third quarter of 2006.
    The issuance of convertible debentures on June 25, 2007 resulted in the
recognition of cash interest expense of $0.9 million and non cash interest
accretion expense of $0.8 million for the year to date. 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 7, "Convertible Debentures" to the consolidated financial statements
for more details.
    Total bank cash interest expense is expected to be maintained at
approximately the third quarter amount through the remainder of 2007 as draws
on the bank line should only decrease slightly from its current level as our
capital expenditure program for the fourth quarter is expected to be less then
projected cash flow.

    NET EARNINGS (LOSS)

    A significant non cash goodwill impairment write-down in the third
quarter of 2007 resulted in a loss of $122.6 million ($2.12 per diluted share)
in the third quarter of 2007 compared to earnings of $7.0 million ($0.19 per
diluted share) in the third quarter of 2006. This also resulted in a loss of
$122.0 million ($2.13 per diluted share) for the first nine months of 2007
compared to earnings of $20.2 million ($0.57 per diluted share) for the first
nine months of 2006. Lower earnings are also largely attributable to the
increased depletion, depreciation and accretion expense as described below.

    Goodwill Impairment

    As at September 30, 2007 the Company assessed its balance of goodwill and
determined that based on the currently prevailing market conditions there is a
full impairment of recorded goodwill of $119.3 million and therefore it has
been written down with a corresponding non-cash charge to the income statement
in the third quarter of 2007. Market conditions have resulted in a
significantly reduced market valuation of Kereco at the end of the third
quarter of 2007 compared to the prevailing valuations when Kereco acquired
Chariot and Chamaelo and upon which the resultant goodwill was recognized.
This decrease in the market valuation of Kereco resulted in the writedown of
the goodwill.
    This eliminates the entire balance of goodwill from the balance sheet and
therefore, there will be no further charges to income with respect to the
impairment of goodwill.

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

    Depletion, depreciation and accretion ("DD&A") amounted to $22.1 million,
or $27.65/boe in the third quarter of 2007 compared to $8.4 million or
$16.83/boe for the third quarter of 2006. For the first nine months of 2007,
DD&A amounted to $63.4 million, or $26.14/boe compared to $23.8 million or
$15.64/boe for the first nine months of 2006.
    The DD&A rate increased in the first nine months and third 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 2007. We had an updated independent
review of our reserves by GLJ Petroleum Consultants as of August 1, 2007
resulting in proven reserves of 24,450 mboes compared to proven reserves of
23,126 mboes at December 31, 2006. These cumulative additions to the
depletable pools, relative to period end estimated reserves at September 30,
2007, 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 third quarter 2007 rate of $27.65/boe.

    Stock-Based Compensation Expense

    Stock-based compensation expense for the third quarter of 2007 was
$1.2 million compared to a $1.0 million in the third quarter of 2006.
Stock-based compensation expense for the first nine months of 2007 was $3.4
million compared to $2.6 million for the first nine months 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 as well as additional expense for the incremental fair value of
the replacement options granted. This, in addition to the additional options
granted during the year to date resulted in the increased stock-based
compensation expense both in the third quarter and the first nine months of
2007.

    Unrealized Loss/(Gain) on Financial Instruments

    The effect of financial instruments amounted to an unrealized loss of
$5.2 million in the first nine months of 2007 compared to an unrealized gain
of $3.2 million for the first nine months 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 WTI oil prices as
at the end of September 30, 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 12
in the notes to the consolidated financial statements for additional details.

    Taxes

    The total tax recovered for the year to date at September 30, 2007 was
$2.5 million comprised of $2.7 million in future income tax recovery offset by
$0.2 million in current income tax (September 30, 2006: expense of
$7.8 million comprised of $8.0 million of future income taxes and a recovery
of $0.2 million of large corporations tax). Current taxes of $0.2 million were
recognized which 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 two percent for
the year to date in 2007, which is largely influenced by the goodwill
impairment writedown realized in the third quarter of $119.3 million which is
a permanent difference and has no tax basis.

    Income Tax Pools

    At September 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 September 30, 2007
    -------------------------------------------------------------------------
    Canadian oil and gas property expense ("COGPE")                    279.2
    Canadian development expense ("CDE")                               101.5
    Canadian exploration expense ("CEE")                                32.5
    Undepreciated capital costs ("UCC")                                116.2
    Non-capital losses carried forward                                  28.4
    -------------------------------------------------------------------------
    Total pools and losses                                             557.8
    Share issue costs                                                   13.1
    -------------------------------------------------------------------------
    Total pools, losses and share issue costs                          570.9
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    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 Nine months ended September 30 September 30 (000s) 2007 2006 2007 2006 ------------------------------------------------------------------------- Funds flow from operations 23,345 17,422 67,618 51,634 Working capital 16,396 5,142 4,149 840 Bank debt (1,179) 10,411 (37,960) 12,958 Business combination transaction costs - - (484) - Proceeds from issuance of convertible debentures - - 67,475 - Proceeds from the exercise of options or warrants - - 626 443 Proceeds from share issuances - (30) 18,303 20,765 ------------------------------------------------------------------------- Total capital resources 38,562 32,945 119,727 86,640 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Bank Debt At September 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 an 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 September 30, 2007, $150.7 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 6.1 percent ($8.9 million in cash interest expense), including interest expense associated with the property acquisitions and dispositions realized in the second quarter and accrued interest expense of 4.75 percent per annum related to the convertible debentures, compared to $2.9 million for the nine months ended September 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 deficiency of $11.6 million. Increased capital activity in the third quarter and the associated increase in accounts payable and accrued liability balances since the end of the second quarter resulted in the working capital deficiency. 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 Nine months ended Year ended September 30, December 31, 2007 2006 ------------------------------------------------------------------------- Weighted average shares outstanding Basic 57,357,104 38,610,662 Options and warrants(1) - 1,373,198 ------------------------------------------------------------------------- Diluted 57,357,104 39,983,860 Common shares outstanding at period end ------------------------------------------------------------------------- Basic 57,777,332 55,336,432 Options and warrants 8,273,851 7,471,492 ------------------------------------------------------------------------- Diluted 66,051,183 62,807,924 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) 908,926 anti-dilutive incremental options and warrants are excluded from the weighted average diluted shares outstanding. As at November 6, 2007, Kereco had 57,793,331 shares outstanding reflecting the issuance of 2,250,000 flow-through common shares and the exercise of 206,899 warrants during the first nine months of the year. CAPITAL EXPENDITURES During the third quarter of 2007, we incurred $38.6 million in net capital expenditures itemized as follows: Three months ended Nine months ended September 30 September 30 ($000s) 2007 2006 2007 2006 ------------------------------------------------------------------------- Land 896 367 2,136 1,835 Geological and geophysical 1,050 607 2,772 9,608 Drilling and completions 21,696 20,470 52,372 53,562 Facilities and equipment 14,633 3,511 28,527 13,320 Office and corporate costs 187 373 2,334 533 Capitalized general and administrative costs 452 142 1,194 307 ------------------------------------------------------------------------- Total exploration and development 38,914 25,470 89,335 79,165 ------------------------------------------------------------------------- Property acquisitions - 7,475 36,604 7,475 Property dispositions (352) - (6,212) - ------------------------------------------------------------------------- Total capital expenditures 38,562 32,945 119,727 86,640 ------------------------------------------------------------------------- ------------------------------------------------------------------------- We drilled 33 (27.3 net) wells during the first nine months of 2007 which resulted in 11 cased gas wells (8.3 net) and 17 oil wells (15.4 net) comprised of one (0.5 net) gas well in the Blair Creek British Columbia area, one (1.0 net) gas well in the Sikanni British Columbia area, two (1.7 net) gas wells and two (2.0 net) oil wells in the Fireweed British Columbia area, three (2.1 net) gas wells and one (1.0 net) oil well in the Willesden Green Central Alberta area, six (6.0 net) oil wells in the Sturgeon Lake Alberta area, one (1.0 net) gas well in the Wimborne Central Alberta area, two (1.4) gas and two (1.6) oil wells in the Gosling Central Alberta area and seven (5.4 net) oil wells in the Wilson Creek Central Alberta area. We also completed eight major recompletions and workovers at Sturgeon Lake in the first nine months of 2007. This amounted to $52.4 million in drilling and completion expenditures for the year to date. Related equipping costs and facility costs amounted to $28.5 million, including $3.5 million related to the Sturgeon plant turnaround and $3.3 million to upgrade to our Willesden Green gas compression facility. $1.8 million was also spent on land resulting in an increase in our undeveloped land position to 238,000 net undeveloped acres at September 30, 2007. $2.7 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 year, resulting in $6.2 million in proceeds. CONTRACTUAL OBLIGATIONS 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. As of September 30, 2007 approximately $3.3 million in qualifying expenditures have been incurred leaving $16.1 million to be incurred 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 year, the Company signed a nine year office lease which commences on February 1, 2008. Annual payments under the lease will be $1.5 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 $ 596 $ - $ 502 2008 $ 2,382 $ 1,314 $ 2,008 2009 $ 1,754 $ 1,434 $ - 2010 - 2016 $ - $ 9,962 $ - ------------------------------------------------------------------------- Total $ 4,732 $ 12,710 $ 2,510 ------------------------------------------------------------------------- ------------------------------------------------------------------------- RISK MANAGEMENT We have entered into financial and physical derivative contracts as outlined in notes 12 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 September 30, 2007 strip pricing for crude oil over the term of those financial derivative contracts, Kereco would actually realize a net $0.1 million cash loss over the term of the financial derivative contracts from the oil contracts in place. The financial and physical derivative contracts entered up to and including November 6, 2007 and as listed in note 12 to the Consolidated Financial Statements result in the following downside price protection and ceiling prices on future production: 2007 2008 -------------------------------------------- Q4 Q1 Q2 Q3 Q4 ------------------------------------------------------------------------- Crude Oil Volume (bbls/day) 1,750 1,500 1,500 1,500 1,500 Floor price (WTI US$/bbl) 62.43 61.50 61.50 61.50 61.50 Ceiling Price (WTI US$/bbl) 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 nine months of 2007 and $250,000 in the fourth quarter of 2006. None of these amounts were owing 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 September 18, 2007 the Alberta Royalty Review Panel ("ARRP"), a panel commissioned by the Government of Alberta to review the province's royalty regime, issued their recommendations. Those recommendations were the subject of a very lively public debate involving not only our industry, but all Albertans that ensued following its release. The debate was answered with the Government of Alberta releasing their proposed New Royalty Framework ("NRF") on October 25, 2007. Although the recommendations in the NRF did serve to make future investments in our industry less attractive, we nevertheless now have some certainty with respect to what the rules will likely be after January 1, 2009 and can plan our business accordingly. On October 31, 2007, we press released that the impact to our current reserves and our estimated 2009 cash flows on those reserves as a result of the proposed NRF to be both less than 5%. However, this analysis did not attempt to estimate what impact, if any, future capital spending might have on our future reserves or cash flows in 2009 and beyond. 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 second quarter report, our current objective is to reposition Kereco to withstand the current soft investment environment that has precipitated from lower than required economic returns from natural gas drilling, higher labour and service costs and volatile capital markets. The first stage of the repositioning process that was commenced on July 18, 2007, was to perform a mid-year update of our reserves and have them re-evaluated by GLJ Petroleum Consultants Ltd. ("GLJ"). On September 4, 2007 we released the results of that review and also further updated that review on October 31, 2007 to incorporate the impact of the proposed NRF. A Special Committee of the Board of Directors of Kereco has now been formed and will continue to work with management and our advisors, BMO Capital Markets Inc., GMP Securities L.P. and Tristone Capital Inc., to determine the optimal future strategic direction of the Company. Kereco will be proceeding with the disposition of approximately 1,700 boe/day of non-core assets to multiple industry participants and we are actively working towards the conclusion of that process. Above and beyond the dispositions, we are continuing to also consider a multitude of various alternatives for the remaining components of the Company and hope to be able to report back to you on those alternatives in the coming weeks. During the fourth quarter, we plan to tie-in the production we have behind pipe from capital activities earlier in the year and limit the amount of capital we direct specifically towards natural gas drilling prospects as we are cautious about the near term economic environment for natural gas. Our expectation is to spend less than $25 million in capital in the fourth quarter. As a result of the property dispositions we expect to conclude in the fourth quarter of approximately 1,700 boe/day, we anticipate production for the fourth quarter to average approximately 9,400 and 9,800 boe/day, inclusive of the majority of our successful drilling and optimization program for 2007 to date. In addition to the challenges of lower natural gas prices, higher than acceptable service costs and a strengthening Canadian dollar, we must now also consider the effects on investment as a result of higher future royalty rates. Contrasting these negative factors is the fact that we are experiencing WTI oil prices that have recently touched record high levels of $96.00/bbl. We believe that there are long term future opportunities that exist in the Canadian oil and gas business and we look forward to being able to communicate back to you shortly on how we plan to reposition Kereco to take advantage of them. Thank you again for your continued interest in Kereco. On behalf of the Board of Directors, Grant B. Fagerheim President and Chief Executive Officer November 6, 2007 KERECO ENERGY LTD. CONSOLIDATED BALANCE SHEETS As at As at September 30, December 31, ($000s) (unaudited) 2007 2006 ------------------------------------------------------------------------- ASSETS Current Accounts receivable $ 34,895 $ 41,268 Prepaid expenses 2,558 3,459 Financial derivative contracts (Note 12) 832 4,990 ------------------------------------------------------------------------- 38,285 49,717 Property, plant and equipment, net (Note 3) 658,990 600,964 Goodwill (Notes 4 & 5) - 116,730 ------------------------------------------------------------------------- Total Assets 697,275 767,411 ------------------------------------------------------------------------- ------------------------------------------------------------------------- LIABILITIES Current Accounts payable and accrued liabilities 49,062 51,955 Bank debt (Note 6) - 27,000 ------------------------------------------------------------------------- 49,062 78,955 ------------------------------------------------------------------------- Bank debt (Note 6) 150,713 161,673 Asset retirement obligation (Note 9) 17,719 16,038 Convertible debentures (Note 7) 52,804 - Future income taxes (Note 8) 35,604 29,497 ------------------------------------------------------------------------- 256,840 207,208 ------------------------------------------------------------------------- Total Liabilities 305,902 286,163 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Commitments and guarantees (Note 13) Contingencies (Note 15) SHAREHOLDERS' EQUITY Share capital (Note 10) 450,826 438,216 Contributed surplus (Note 10) 9,827 6,539 Convertible debentures (Note 7) 15,704 - Retained earnings (deficit) (84,984) 36,493 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Total shareholders' equity 391,373 481,248 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Total liabilities and shareholders' equity $ 697,275 $ 767,411 ------------------------------------------------------------------------- ------------------------------------------------------------------------- The accompanying notes form an integral part of these consolidated financial statements. KERECO ENERGY LTD. CONSOLIDATED STATEMENT OF EARNINGS (LOSS), COMPREHENSIVE INCOME (LOSS) AND RETAINED EARNINGS (DEFICIT) Three months ended Nine months ended September 30 September 30 ------------------------------------------------------------------------- ($000s, except per share amounts) (unaudited) 2007 2006 2007 2006 ------------------------------------------------------------------------- REVENUE Petroleum and natural gas sales $ 43,697 31,264 $ 136,254 91,921 Royalties, net of ARTC (10,212) (7,112) (30,568) (20,737) ------------------------------------------------------------------------- 33,485 24,152 105,686 71,184 ------------------------------------------------------------------------- EXPENSES Operating 7,889 4,965 26,229 14,009 Transportation 1,028 1,015 3,180 2,791 General and administrative 946 405 3,467 1,377 Interest and bank charges (Notes 6 & 7) 3,929 1,050 9,728 2,928 Loss (gain) on financial derivatives (Note 12) 4 (4,015) 1,479 (4,418) Depletion, depreciation and accretion (Notes 3 & 9) 22,103 8,446 63,381 23,859 Goodwill impairment (Note 5) 119,278 - 119,278 - Stock-based compensation expense (Note 10) 1,173 1,030 3,443 2,597 ------------------------------------------------------------------------- 156,350 12,896 230,185 43,143 ------------------------------------------------------------------------- EARNINGS (LOSS) BEFORE INCOME TAXES (122,865) 11,256 (124,499) 28,041 ------------------------------------------------------------------------- INCOME TAXES (Note 8) Future income tax expense (recovery) (74) 4,250 (2,627) 8,026 Current tax expense (recovery) (148) - 158 (224) ------------------------------------------------------------------------- (222) 4,250 (2,469) 7,802 ------------------------------------------------------------------------- NET EARNINGS (LOSS) (122,643) 7,006 (122,030) 20,239 ------------------------------------------------------------------------- OTHER COMPREHENSIVE INCOME - - - - ------------------------------------------------------------------------- COMPREHENSIVE INCOME (LOSS) (122,643) 7,006 (122,030) 20,239 ------------------------------------------------------------------------- Retained earnings, beginning of period 37,659 29,721 36,493 16,488 Transitional adjustment upon adoption of new accounting policy (Note 2) - - 553 - Retained earnings (deficit), end of period $ (84,984) 36,727 $ (84,984) 36,727 ------------------------------------------------------------------------- ------------------------------------------------------------------------- EARNINGS (LOSS) PER SHARE (Note 10) Basic $ (2.12) 0.20 $ (2.13) 0.59 Diluted $ (2.12) 0.19 $ (2.13) 0.57 ------------------------------------------------------------------------- ------------------------------------------------------------------------- The accompanying notes form an integral part of these consolidated financial statements. KERECO ENERGY LTD. CONSOLIDATED STATEMENTS OF CASH FLOWS Three months ended Nine months ended September 30 September 30 ------------------------------------------------------------------------- ($000s)(unaudited) 2007 2006 2007 2006 ------------------------------------------------------------------------- OPERATING ACTIVITIES Net earnings (loss) $(122,643) 7,006 $(122,030) 20,239 Items not requiring cash: Depletion, depreciation and accretion 22,103 8,446 63,381 23,859 Goodwill impairment (Note 5) 119,278 - 119,278 - Future income tax expense (recovery) (74) 4,250 (2,627) 8,026 Unrealized loss (gain) on financial derivatives 2,682 (3,350) 5,237 (3,184) Employee share benefit plan expense (Note 10) 30 40 88 97 Non-cash interest expense on convertible debentures (Note 7) 796 - 848 - Stock-based compensation expense 1,173 1,030 3,443 2,597 ------------------------------------------------------------------------- 23,345 17,422 67,618 51,634 Change in non-cash working capital (Note 11) (2,701) 4,457 6,810 7,161 ------------------------------------------------------------------------- Cash provided by operating activities 20,644 21,879 74,428 58,795 ------------------------------------------------------------------------- FINANCING ACTIVITIES Issuance of common shares and warrants, net of share issue costs - (30) 18,929 21,208 Issuance of convertible debentures - net of issue costs - - 67,475 - Bank debt (1,179) 10,411 (37,960) 12,958 Change in non-cash working capital (Note 11) 558 314 878 (125) ------------------------------------------------------------------------- Cash provided by (used in) financing activities (621) 10,695 49,322 34,041 ------------------------------------------------------------------------- INVESTING ACTIVITIES Petroleum and natural gas expenditures (38,914) (25,470) (89,335) (79,165) Property acquisitions - (7,475) (36,604) (7,475) Property dispositions 352 - 6,212 - Business combinations (Note 4) - - (484) - Change in non-cash working capital (Note 11) 18,539 371 (3,539) (6,196) ------------------------------------------------------------------------- Cash used in investing activities (20,023) (32,574) (123,750) (92,836) ------------------------------------------------------------------------- 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 Nine months ended September 30, 2007 and 2006 (Unless otherwise stated, tabular 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 $154,000 a reduction to the future income tax liability of $81,000 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 $707,000, an increase in the future tax liability of $372,000 and an increase in the Financial Derivative Contract asset of $1,079,000. 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. D) Per Share Information Basic earnings per share is calculated using the weighted average number of shares outstanding during the period. Diluted earnings per share is calculated using the treasury stock method to determine the dilutive effect of stock options and warrants. The treasury stock method assumes that proceeds from the exercise of "in-the-money" stock options, warrants and convertible debentures, net of "in-the- money" unamortized stock based compensation expense, is used to re- purchase common shares at the average market price over the period. 3. PROPERTY, PLANT AND EQUIPMENT As at September 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 $779,540 $123,674 $655,866 $661,581 $ 61,521 $600,060 Office equipment & corporate 3,686 562 3,124 1,102 198 $ 904 ------------------------------------------------------------------------- Total $783,226 $124,236 $658,990 $662,683 $ 61,719 $600,964 ------------------------------------------------------------------------- ------------------------------------------------------------------------- The Company capitalized $1.2 million of indirect general and administrative overhead for the year to date in 2007 (September 30, 2006 - $0.3 million). $50.7 million of undeveloped land was excluded from the depletion calculation (September 30, 2006 - $26.6 million). 4. BUSINESS COMBINATIONS Chamaelo Exploration Ltd. Adjustments to the Chamaelo purchase equation were recorded in 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 $2,063,000 and a corresponding increase in goodwill. Additional transaction costs in the amount of $484,000 related to the acquisition of Chamaelo were also recorded in 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. GOODWILL As at September 30, 2007 the Company assessed its balance of goodwill and determined that based on the currently prevailing market conditions there is a full impairment of recorded goodwill of $119.3 million and therefore it has been written down with a corresponding charge to the income statement in the third quarter of 2007. Market conditions have resulted in a significantly reduced market valuation of Kereco at the end of the third quarter of 2007 compared to the prevailing valuations when Kereco acquired Chariot and Chamaelo and upon which the resultant goodwill was recognized. This decrease in the market valuation of Kereco resulted in the writedown of the goodwill. 6. BANK DEBT At September 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 September 30, 2007, $150.7 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 6.1 percent ($8.9 million in cash interest expense), including interest expense associated with the property acquisitions and dispositions realized in the second quarter and accrued interest expense related to the convertible debenture, compared to $2.9 million for the nine months ended September 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. 7. 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"). The interest is payable semi-annually in arrears on June 30 and December 31 each year, first 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 - inclusive of transaction costs (15,519) Accretion (non cash interest expense) 848 --------------------------------------------------------------------- Debt balance as at September 30, 2007 $ 52,804 --------------------------------------------------------------------- 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 September 30, 2007 $ 15,704 --------------------------------------------------------------------- 8. INCOME TAXES The total tax recovered for the year to date at September 30, 2007 was $2.5 million comprised of $2.7 million in future income tax recovery offset by $0.2 million in current income tax (September 30, 2006: expense of $7.8 million comprised of $8.0 million of future income taxes and a recovery of $0.2 million of large corporations tax). Current taxes of $0.2 million were recognized which 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 two percent for the year to date in 2007, which is largely influenced by the goodwill impairment writedown realized in the third quarter of $119.3 million which is a permanent difference and has no tax basis. At September 30, 2007, the Company had tax pools and non-capital losses of approximately $557.8 million, comprised of $32.5 million in Canadian Exploration Expense (CEE), $279.2 million in Canadian Oil & Gas Property Expense (COGPE), $101.5 million in Canadian Development Expense (CDE), and $116.2 million in Capital Cost Allowance (CCA) pools as well as accumulated non-capital losses for income tax purposes of approximately $28.4 million (December 31, 2006 - $17.7 million) that can be used to offset otherwise taxable income in future periods. The non capital losses expire as follows: Year of expiry ($millions) --------------------------------------------------------------------- 2010 9.2 2015 19.2 --------------------------------------------------------------------- 28.4 --------------------------------------------------------------------- --------------------------------------------------------------------- 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 in 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 September 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. All of the required $22.0 million in qualifying CEE expenditures related to this flow-through share commitment have been incurred as of September 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. As of September 30, 2007 approximately $3.3 million in qualifying CEE expenditures related to this flow-through share commitment have been incurred. 9. 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 $44.6 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 September 30, 2007 asset retirement obligation is comprised of the following: --------------------------------------------------------------------- Balance at December 31, 2006 $ 16,038 New liabilities added 816 Accretion of asset retirement obligation 865 --------------------------------------------------------------------- Balance at September 30, 2007 $ 17,719 --------------------------------------------------------------------- 10. 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 - 88 Share issue costs - (1,047) Tax effect of share issue costs - 319 --------------------------------------------------------------------- Balance at the end of September 30, 2007 57,777,332 $ 450,826 --------------------------------------------------------------------- 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 future tax impact and related reduction to share capital will be recorded when the expenditures are 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 1,674,386 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 September 30, 2007) warrants exercisable into full 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 0.3 795 January 18, 2009 879 3.12 1.3 - May 26, 2009 279 4.12 1.7 279 June 21, 2010 1,569 11.37 2.7 1,569 --------------------------------------------------------------------- 3,522 6.87 1.7 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 4,751,800 options were granted as at September 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 replaced options over their vesting 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 3,890 5.71 4.4 Exercised - - - Expired or cancelled (2,788) (9.85) 3.0 --------------------------------------------------------------------- Balance September 30, 2007 4,752 6.75 4.2 --------------------------------------------------------------------- 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 September 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 $3.4 million of non-cash stock-based compensation expense for the first nine months of 2007 (expense of $2.6 million for the first nine months of 2006) with an equal amount recorded in contributed surplus. No expense was recognized in non-cash stock based compensation expense from the SARs and $156,000 was transferred out of contributed surplus to share capital for employee warrants which were exercised in the first nine months of 2007. 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 $2.30 per option. No estimate has been made for expected forfeitures as they are addressed when they occur. Additional details on the Company's stock options outstanding at September 30, 2007 are as follows: Weighted Weighted Average Average Range of Number of Exercise Contractual Options Exercise Prices Options Price Life Exercisable ($/share) (000s) ($/share) (years) (000s) --------------------------------------------------------------------- 3.84 - 5.73 3,081 5.57 4.7 - 5.90 - 7.24 525 6.58 4.6 13 8.93 - 9.80 641 9.37 2.9 300 10.50 - 11.20 505 10.84 2.6 306 --------------------------------------------------------------------- 3.84 - 11.20 4,752 6.75 4.2 619 --------------------------------------------------------------------- --------------------------------------------------------------------- v) Employee Benefit Plan During 2005, the Company created an employee benefit plan under which Kereco common shares were purchased on behalf of certain employees. These shares were granted to certain employees and will be received by them, on the basis of one third per year, over a period not exceeding three years. 23,950 common shares were purchased for the plan at an average price of $14.67 per common share. Of the 23,950 common shares, 7,109 were delivered to certain employees in the third quarter of 2007, 7,293 were delivered to certain employees in the third quarter of 2006 and 9,548 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 September 30, 2007, $88 has been expensed and recorded to share capital (Sept 30, 2006: $97). 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 Nine months ended September 30 September 30 2007 2006 2007 2006 --------------------------------------------------------------------- Net earnings (loss) $(122,643) $ 7,006 $(122,030) $ 20,239 Net earnings (loss) per share Basic $ (2.12) $ 0.20 $ (2.13) $ 0.59 Diluted $ (2.12) $ 0.19 $ (2.13) $ 0.57 Weighted average shares outstanding Basic 57,777,332 35,256,245 57,357,104 34,372,003 Options and warrants(1) - 936,432 - 1,148,487 --------------------------------------------------------------------- Diluted 57,777,332 36,192,677 57,357,104 35,520,490 Common shares outstanding at period end --------------------------------------------------------------------- Basic 57,777,332 35,256,245 57,777,332 35,256,245 Options and warrants 8,273,851 5,035,282 8,273,851 5,035,282 --------------------------------------------------------------------- Diluted 66,051,183 40,291,527 66,051,183 40,291,527 --------------------------------------------------------------------- --------------------------------------------------------------------- (1) Anti-dilutive incremental options and warrants in the amount of 580,664 for the third quarter of 2007 and 908,926 for the year to date are excluded from the weighted average diluted shares outstanding. 11. SUPPLEMENTAL CASH FLOW INFORMATION i) Changes in Non-Cash Working Capital Three months ended Nine months ended September 30 September 30 2007 2006 2007 2006 --------------------------------------------------------------------- Decrease (increase) in non-cash working capital: Accounts receivable $ 4,164 $ 203 $ 6,373 $ 4,036 Prepaid expenses 483 110 669 (826) Accounts payable and accrued liabilities 11,749 4,829 (2,893) (2,370) --------------------------------------------------------------------- Change in non-cash working capital $ 16,396 $ 5,142 $ 4,149 $ 840 --------------------------------------------------------------------- Relating to: Operating activities (2,701) 4,457 6,810 7,161 Financing activities 558 314 878 (125) Investing activities 18,539 371 (3,539) (6,196) --------------------------------------------------------------------- Change in non-cash working capital $ 16,396 $ 5,142 $ 4,149 $ 840 --------------------------------------------------------------------- --------------------------------------------------------------------- ii) Other Cash Flow Information Three months ended Nine months ended September 30 September 30 2007 2006 2007 2006 --------------------------------------------------------------------- Cash taxes paid $ 158 $ - $ 158 $ - Cash interest paid $ 3,133 $ 1,050 $ 8,879 $ 2,928 --------------------------------------------------------------------- --------------------------------------------------------------------- 12. RISK MANAGEMENT & FINANCIAL INSTRUMENTS The following financial derivative and physical sales contracts were outstanding on September 30, 2007: Oil and Natural Gas Price risk management Period Volume Type Pricing terms(1) --------------------------------------------------------------------- Natural Gas Nov 1, 2007 - $7.35 - $11.67 Mar 31, 2008 10,000 GJ/day(2) Financial Collar (AECO CDN$/GJ) Crude Oil Oct 1, 2007 - $62.43 - $88.34 Dec 31, 2007 1,750 bbls/day Financial Collar (WTI US$/BBL) Jan 1, 2008 - $61.50 - $78.88 Dec 31, 2008 1,500 bbls/day Financial Collar (WTI US$/BBL) --------------------------------------------------------------------- (1) Collar price indicates minimum floor and maximum ceiling. (2) Subsequent to the end of the third quarter of 2007, the company unwound all of the 10,000 GJ/day natural gas financial collars, and received a cash payment of $1.6 million to do so. Power Consumption price risk management Period Volume Type Pricing terms --------------------------------------------------------------------- Electricity Oct 1, 2007 - Dec 31, 2008 3.5 MW Fixed Price $65.50/MWh --------------------------------------------------------------------- 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 September 30, 2007, the Company had recognized a financial derivative contract asset of $0.8 million (December 31, 2006: asset of $5.0 million). 13. COMMITMENTS AND GUARANTEES 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. As of September 30, 2007 approximately $3.3 million in qualifying CEE expenditures related to this flow- through share commitment have been incurred. 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 nine months of 2007, the Company signed a nine year office lease which commences on February 1, 2008. Average annual payments under the lease will be $1.5 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; net of any prepayments: Drilling Electricity ($000s) contracts Office lease contract --------------------------------------------------------------------- 2007 $ 596 $ - $ 502 2008 $ 2,382 $ 1,314 $ 2,008 2009 $ 1,754 $ 1,434 $ - 2010-2016 $ - $ 9,962 $ - --------------------------------------------------------------------- 14. 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 nine months of 2007 and $250,000 in the fourth quarter of 2006. None of these amounts were owing at each respective period end. 15. 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, Business GLJ Petroleum Consultants Ltd. 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 Computershare Trust Company of Kirby J. Wanner 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) boe/day barrels of oil equivalent per day 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

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KERECO ENERGY LTD.

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