Cinch Energy Corp. releases 2006 results



    CALGARY, March 9, 2007 /CNW/ - Cinch Energy Corp ("Cinch" or the
"Company") is pleased to announce its financial and operational results for
the year ended December 31, 2006.

    
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    HIGHLIGHTS                      Three Months Ended            Year Ended
                                           December 31,          December 31,
                                       2006       2005       2006       2005
    -------------------------------------------------------------------------
                                        (unaudited)
    Petroleum and natural gas sales,
     net of transportation ($000's)   5,733      8,323     20,112     27,413
    Production per day
    Natural gas (Mcf/d)               6,500      6,248      5,851      6,478
    Natural gas liquids (Bbl/d)         236        203        207        217
    Equivalence at 6:1 (BOE/d)        1,320      1,245      1,182      1,297

    Sales Price
    Natural gas ($/Mcf)                7.49      12.44       7.14       9.59
    Natural gas liquids ($/Bbl)       57.56      62.69      64.53      59.83
    Equivalence at 6:1 ($/BOE)        47.22      72.68      46.62      57.90

                                          $          $          $          $
    Funds from operations (000's)(1)  2,970      4,899      9,966     15,042
      - per share, basic(1)            0.06       0.10       0.21       0.38
      - per share, diluted(1)          0.06       0.10       0.20       0.36

    Net income (000's)                 (488)     1,364       (317)     3,364
      - per share, basic              (0.01)      0.03      (0.01)      0.08
      - per share, diluted            (0.01)      0.03      (0.01)      0.08

    Capital expenditures ($000's)     9,324     11,982     36,966     36,045

    Basic weighted average shares
     outstanding (000's)             47,813     47,813     47,813     40,047
    Working capital (net debt)(2)
     ($000's)                                                   $
      As at December 31, 2006                             (23,745)
      As at December 31, 2005                               3,490

                                                            As at
                                                  March 7, 2007(3)
    Common Shares and Special Warrants
     outstanding                                       55,625,132
    Options outstanding                                 4,078,000
    - average exercise price                                 1.95
    -------------------------------------------------------------------------
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    (1) Funds from operations is not a generally accepted accounting
        principle ("GAAP") measure and represents cash provided by operating
        activities on the statement of cash flows less the effect of changes
        in non-cash working capital related to operating activities.
    (2) Net debt is a non-GAAP measure and represents the sum of the working
        capital (deficiency) and the outstanding credit facility balance.
    (3) Subsequent to December 31, 2006, the Company issued, for gross
        proceeds of $10 million, a total of 7,812,500 common shares on a flow
        through basis at a price of $1.28 per common share.


    2006 ACCOMPLISHMENTS

    -   Increased the reserve base by 1.1 million barrels of oil equivalent
        on a proven and probable basis
    -   Exited the year with a production rate of 1600 boe/d
    -   Acquired additional interests in the Company's core area of Chime for
        $7.75 million
    -   Subsequent to year end, closed a flow through share financing for
        gross proceeds of $10 million
    

    Exploration

    During 2006, Cinch continued its exploration program in its core area of
Chime and Kakwa along with pursuing opportunities in other areas. A total of
17 wells (5.87 net) were participated in, of which 11 wells (3.19 net) were
cased as potential gas wells, and 2 wells (0.90 net) were cased as potential
oil wells.
    At CHIME, Cinch has reprocessed its 3-D seismic data over the Chime area,
incorporating log data from a new offsetting well which is producing at rates
in excess of 25 mmcfpd from the Falher B zone since October. The Company has
identified several prospective locations and expects to commence drilling in
May. The reprocessed seismic data indicates three to five follow up locations
on this Falher trend. During 2006, Cinch operated the drilling of two wells in
the Chime area, one of which was completed and tied in as a gas well. In
addition, the Company acquired additional working interests in 7 producing
natural gas wells for approximately $7.75 million (net) after selling the
undeveloped lands thereon.
    During 2006, three potential gas wells were participated in at MUSREAU.
One well is to be completed in the first quarter of 2007, one well resulted in
a gas well, and Cinch did not participate in the completion on the third well.
Operators in the area have filed down-spacing applications which are expected
to be approved in early 2007. The Company is planning to drill several
down-spaced wells in the area along with re-completing additional prospective
horizons in existing well bores.
    At KAKWA, Cinch participated in drilling four wells in 2006, resulting in
three gas wells and one abandoned well. These gas wells have all been
completed and placed on production. Additional down spaced drilling is
currently planned for 2007. In KAKWA NORTH, Cinch operated the re-entry of a
well in 2006 which was completed as a gas well in the Cardium zone at a
stabilized flow rate of 2 mmcfpd. This well has now been placed on production
by the operator.
    At RESTHAVEN, the Company participated, through farmout, in a significant
dual zone gas discovery. The 9-25-60-3W6 well commenced production in November
at 6.5 mmcfpd along with significant natural gas liquids from the Dunvegan
zone. In February 2007, the operator shut in the Dunvegan zone and placed the
Gething zone on production at an initial rate of 7 mmcfpd, along with
significant natural gas liquids. The operator will be commingling the Dunvegan
and Gething zones once the Gething pressures have declined. Cinch is
projecting a commingled rate of 3 mmcfpd for this well in 2007. Additional
drilling opportunities exist on the Company's acreage once down spacing
applications are approved.
    At CHIME EAST, Cinch operated the drilling of the 12-24-60-4W6 dual zone
gas well. The Company is currently evaluating tie-in options for this well and
additional drilling opportunities on the acreage for 2007.
    In the KAKWA EAST area, the Company operated and completed an oil
discovery at 15-12-61-4W6. This well is being evaluated for tie-in as the oil
zone has associated natural gas production. Cinch has identified a number of
development locations offsetting this discovery. The timing of these locations
is dependent on access being granted by the Forestry department and economics
of this project due to the associated natural gas production which must be
conserved and tied-in.
    Cinch is continuing to pursue and evaluate new projects and hence
participated in two prospects located in the vicinity of the Company's DAWSON
area. Cinch participated in the drilling of a Boundary Lake oil well at DOE
which has extended the Doe Boundary Lake C pool westward. The Company has
earned interests ranging from 40-50% in 3,200 acres on this prospect.
Additional drilling plans will depend on the productive rates from this oil
well. At DAWSON, the Company acquired 3-D seismic which has identified a
Kiskatinaw prospect. Drilling for this prospect is scheduled for mid 2007.
    At WILDER British Columbia, the Company has committed to a new prospect
for 2007, which requires Cinch to complete a cased potential gas well, and
drill and complete a new well for a 50% working interest in 4 sections of
land. The Company will have the option to drill a well to earn a 50% working
interest in an additional 8 sections of land. This prospect is consistent with
Cinch's strategy to acquire prospects which have considerable growth
opportunities through drilling commitments.

    Undeveloped Land

    Cinch's undeveloped land base of 120,367 gross acres (52,988 net acres)
continues to represent a significant asset to the Company. Industry has
continued to pay record land prices during 2006 for undeveloped lands,
particularly in the Deep Basin fairway, which is the core area for Cinch.
Based on an internal evaluation, Cinch places a value of approximately
$15 million on its undeveloped lands.
    The Company holds an average net working interest of 44% in its
undeveloped land inventory, the majority of which is operated by Cinch. This
land base allows the Company to continue with an active exploration program
without having to compete with industry at high priced land sales and to
farmout lands to obtain leverage.

    
    Undeveloped Land Holdings
    -------------------------------------------------------------------------
                                                   December 31,  December 31,
                                                          2006          2005
    -------------------------------------------------------------------------

    Gross Acres                                        120,367       108,307
    Net Acres                                           52,988        48,826
    Average Working Interest                               44%           45%
    -------------------------------------------------------------------------
    

    RESERVES

    The corporate reserves estimates, effective December 31, 2006, were
prepared by the independent engineering firm of GLJ Petroleum Consultants Ltd.
("GLJ") in accordance with the definitions set out under National Instrument
51-101 Standards of Disclosure for Oil and Gas Activities ("NI 51-101"). The
reserve highlights are:

    
    -   Total proven reserves at December 31, 2006 increased 18% to
        3.9 million BOE compared to 3.3 million BOE at December 31, 2005.
    -   Total proven plus probable reserves at December 31, 2006 increased
        21% to 5.8 million BOE compared to 4.8 million BOE at December 31,
        2005
    -   On a proven plus probable basis, the finding, development and
        acquisition costs were $25.53 per BOE ($34.92 per BOE on a proven
        basis).
    -   On a proven plus probable basis, the finding and development costs
        were $31.12 per BOE ($39.11 per BOE on a proven basis).

    FORECASTED PRICES AND COSTS

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

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                               Light
                                and
                              Medium  Natural                           Var
                               Crude    Gas   Natural  Total   Total   (2006
                                Oil   Liquids   Gas     2006    2005     vs
                              (mbbls) (mmbls)  (mmcf)  (mboe)  (mboe)   2005)
    -------------------------------------------------------------------------
    Proved
      - Developed Producing       29     530  17,471   3,471   2,920     551
      - Developed
         Non-Producing             8      39   2,131     402     325      77
      - Undeveloped                0       1     263      45      49      (4)
    -------------------------------------------------------------------------
    Total Proved                  37     571  19,865   3,918   3,295     623
    Probable                      36     292   9,497   1,911   1,489     422
    -------------------------------------------------------------------------
    Total Proved Plus Probable    73     863  29,363   5,830   4,784   1,046
    -------------------------------------------------------------------------
    Note: May not add due to rounding

    (1) "Company interest" means the total working interest (operating and
        non-operating) share before deduction of royalties payable to others
        and including any royalty interest of Cinch.


    Net Present Value of Reserves Before Income Taxes - Forecasted Prices
    and Costs

    -------------------------------------------------------------------------
                              Undis-               Discounted at
                            counted
    -------------------------------------------------------------------------
    December 31,                          8%        10%       15%       20%
     2006(1)(2)(3)            ($M)       ($M)      ($M)      ($M)      ($M)
    -------------------------------------------------------------------------
    Proved - Developed
              Producing      101,932    64,659    59,606    50,263    43,826
           - Developed
              Non-Producing   11,383     6,342     5,673     4,457     3,640
           - Undeveloped         358        74        22       (84)     (164)
    -------------------------------------------------------------------------
    Total Proved             113,673    71,074    65,301    54,637    47,302
    Probable                  62,825    21,509    18,151    12,847     9,741
    -------------------------------------------------------------------------
    Total Proved Plus
     Probable                176,498    92,583    83,452    67,484    57,043
    -------------------------------------------------------------------------
    Note: May not add due to rounding

    (1) Utilizing GLJ January 1, 2007 price forecast.
    (2) As required by NI 51-101, undiscounted well abandonment costs of
        $1.7 million for total proved reserves and $2.1 million for total
        proved plus probable reserves are included in the Net Present Value
        determination. No allowance was made for reclamation of wellsites or
        the abandonment and reclamation of any facilities.
    (3) Prior to provision of income taxes, interest, debt service charges
        and general and administrative expenses. It should not be assumed
        that the undiscounted and discounted future net revenues estimated by
        GLJ represent the fair market value of the reserves.


    Pricing Assumptions - Forecasted Prices and Costs

    The January 1, 2007 pricing forecasts presented below have been prepared
by GLJ. These prices have been utilized in determining the reserves and cash
flow forecasts above.

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                       Oil        Natural
                     Edmonton       Gas                             Pentanes
                     Par Price    Alberta                             Plus
                    40 degrees     Plant      Propane     Butane    Edmonton
                       API          Gate      Edmonton   Edmonton     Light
    Year            ($CDN/Bbl)  ($CDN/MMBtu) ($CDN/Bbl) ($CDN/Bbl) ($CDN/Bbl)
    -------------------------------------------------------------------------
    2007               70.25        7.00       45.00       56.25       71.75
    2008               68.00        7.25       43.50       50.25       69.25
    2009               65.75        7.55       42.00       48.75       67.00
    2010               64.50        7.60       41.25       47.75       65.75
    2011               64.50        7.65       41.25       47.75       65.75
    2012               65.00        7.95       41.50       48.00       66.25
    2013               66.25        8.10       42.50       49.00       67.50
    2014               67.75        8.30       43.25       50.25       69.00
    2015               69.00        8.50       44.25       51.00       70.50
    2016               70.50        8.65       45.00       52.25       72.00
    2017               71.75        8.85       46.00       53.00       73.25
    2018+           +2.0%/yr    +2.0%/yr    +2.0%/yr    +2.0%/yr    +2.0%/yr
    -------------------------------------------------------------------------


    CONSTANT PRICES AND COSTS

    Net Present Value of Reserves Before Income Taxes - Constant Prices
    and Costs

    -------------------------------------------------------------------------
                          Undiscounted              Discounted at
    -------------------------------------------------------------------------

    December 31,               0%         8%        10%       15%       20%
     2006(1)(2)(3)            ($M)       ($M)      ($M)      ($M)      ($M)
    -------------------------------------------------------------------------
    Proved - Developed
              Producing       73,523    50,086    46,613    39,980    35,245
           - Developed
              Non-Producing    7,649     4,522     4,072     3,229     2,645
           - Undeveloped          16      (183)     (219)     (294)     (350)
    -------------------------------------------------------------------------
    Total Proved              81,188    54,425    50,466    42,916    37,540
    Probable                  36,335    14,964    12,862     9,326     7,119
    -------------------------------------------------------------------------
    Total Proved Plus
     Probable                117,523    69,389    63,328    52,242    44,658
    -------------------------------------------------------------------------
    Note: May not add due to rounding

    (1) Price assumptions: $67.58/Bbl Cdn Edmonton Light Sweet Crude,
        $71.55/bbl Cdn. Edmonton Pentanes Plus and $5.87/mmbtu Cdn. Alberta
        Plant Gate - Spot.
    (2) As required by NI 51-101, undiscounted well abandonment costs of
        $1.2 million for total proved reserves and $1.3 million for total
        proved plus probable reserves are included in the Net Present Value
        determination. No allowance was made for reclamation of wellsites or
        the abandonment and reclamation of any facilities.
    (3) Prior to provision of income taxes, interest, debt service charges
        and general and administrative expenses. It should not be assumed
        that the undiscounted and discounted future net revenues estimated by
        GLJ represent the fair market value of the reserves.


    Reserve Reconciliation

    Reconciliation of Company Interest Reserves(1) by Principal Product
    Type - Forecast Prices and Costs

    -------------------------------------------------------------------------
                                Light and Medium Oil    Natural Gas Liquids
    -------------------------------------------------------------------------
                                             Total                   Total
                                             Proved                  Proved
                                              Plus                    Plus
                                 Proved     Probable     Proved     Probable
    FACTORS                      (mbbls)     (mbbls)     (mbbls)     (mbbls)
    -------------------------------------------------------------------------

    December 31, 2005               67.5        95.6       565.5       823.2
    Technical Revisions            (54.9)      (81.0)      (48.2)      (63.5)
    Discoveries                        0           0        20.3        24.4
    Drilling Extensions             25.5        59.9        26.2        36.2
    Infill Drilling                    0           0        50.7        70.4
    Improved Recovery                  0           0           0           0
    Acquisitions                       0           0        30.4        46.3
    Dispositions                       0           0           0           0
    Economic Factors                   0           0           0           0
    Production                      (1.3)       (1.3)      (74.2)      (74.2)
    -------------------------------------------------------------------------
    December 31, 2006               36.8        73.2       570.7       862.8
    -------------------------------------------------------------------------


    -------------------------------------------------------------------------
                                  Associated and
                                Non-Associated Gas           Equivalence
    -------------------------------------------------------------------------
                                             Total                   Total
                                             Proved                  Proved
                                              Plus                    Plus
                                 Proved     Probable     Proved     Probable
    FACTORS                      (mmcf)      (mmcf)      (mboe)      (mboe)
    -------------------------------------------------------------------------

    December 31, 2005           15,971.6    23,192.2     3,294.9     4,784.2
    Technical Revisions            732.5       417.2        19.0       (74.9)
    Discoveries                    494.8       593.8       102.8       123.4
    Drilling Extensions          1,668.2     2,488.2       329.7       510.8
    Infill Drilling              1,447.4     1,993.0       292.0       402.6
    Improved Recovery                  0           0           0           0
    Acquisitions                 1,686.7     2,814.2       311.5       515.3
    Dispositions                       0           0           0           0
    Economic Factors                   0           0           0           0
    Production                  (2,135.7)   (2,135.7)     (431.5)     (431.5)
    -------------------------------------------------------------------------
    December 31, 2006           19,865.5    29,362.8     3,918.4     5,829.8
    -------------------------------------------------------------------------
    Note: May not add due to rounding

    (1) Company interest reserves means the total working interest (operating
        and non-operating) share before deduction of royalties payable to
        others and including royalty interests of Cinch.


    Reconciliation of Company Net Reserves(1) By Principal Product
    Type - Forecast Prices and Costs

    -------------------------------------------------------------------------
                           Light and Medium Oil       Natural Gas Liquids
                         ----------------------------------------------------
                                            Net                        Net
                                           Proved                     Proved
                           Net      Net     Plus      Net      Net     Plus
                         Proved  Probable Probable  Proved  Probable Probable
    FACTOR               (mbbl)   (mbbl)   (mbbl)   (mmcf)   (mmcf)   (mmcf)
    -------------------------------------------------------------------------

    December 31, 2005        55       23       78      366      163      529

    Extensions               23       29       52       17        6       23
    Infill Drilling           0        0        0       34       13       47
    Improved Recovery         0        0        0        0        0        0
    Technical Revisions     (43)     (21)     (64)     (24)     (11)     (35)
    Discoveries               0        0        0       15        3       17
    Acquisitions              0        0        0       16        9       25
    Dispositions              0        0        0        0        0        0
    Economic Factors          0        0        0        0        0        0
    Production               (1)       0       (1)     (56)       0      (56)
    -------------------------------------------------------------------------
    December 31, 2006        34       31       65      368      183      551
    -------------------------------------------------------------------------


    ----------------------------------------------
                              Associated and
                            Non-Associated Gas
    ----------------------------------------------
                                            Net
                                           Proved
                           Net      Net     Plus
                         Proved  Probable Probable
    FACTOR               (mmcf)   (mmcf)   (mmcf)
    ----------------------------------------------

    December 31, 2005    12,019    5,262   17,281

    Extensions            1,224      584    1,807
    Infill Drilling       1,074      411    1,486
    Improved Recovery         0        0        0
    Technical Revisions     378     (244)     134
    Discoveries             441       84      525
    Acquisitions          1,196      808    2,004
    Dispositions              0        0        0
    Economic Factors          0        0        0
    Production           (1,516)       0   (1,516)
    ----------------------------------------------
    December 31, 2006    14,815    6,906   21,721
    ----------------------------------------------
    Note: May not add due to rounding

    (1) Net reserves means the Company's interest (operating and non-
        operating) share after deduction of royalty obligations, plus the
        Company's royalty interest in production or reserves.
    


    Finding and Development Costs (F&D) and Finding, Development and Net
    Acquisition Costs (FD&A)

    NI 51-101 specifies how finding and development ("F&D") costs should be
calculated if they are reported. Essentially NI 51-101 requires that the
exploration and development costs incurred in the year along with the change
in estimated future development costs be aggregated and then divided by the
applicable reserve additions. The calculation specifically excludes the
effects of acquisitions and dispositions on both reserve and costs. By
excluding the effects of acquisitions and dispositions Cinch believes that the
provisions of NI 51-101 do not fully reflect Cinch's ongoing reserve
replacement costs. Since acquisitions can have a significant impact on Cinch's
annual reserve replacement costs, to not include these amounts could result in
an inaccurate portrayal of Cinch's cost structure. Accordingly, Cinch will
also report finding, development and acquisition ("F,D&A") costs that will
incorporate all acquisitions net of any dispositions during the year.

    
    -------------------------------------------------------------------------
    Finding, Development
     and Net Acquisition
     Costs                     2006              2005         3 year average
    -------------------------------------------------------------------------
                                 Proven +          Proven +          Proven +
                         Proven  Probable  Proven  Probable  Proven  Probable
    -------------------------------------------------------------------------
    Capital ($'000s)
    Exploration and
     development(1)      29,058   29,058   36,045   36,045   27,051   27,051
    Acquisition capital   7,779    7,779    1,515    1,515   19,646   19,646
    Change in future
     capital                 23      874    1,796    5,638      915    2,479
    -------------------------------------------------------------------------
    Total capital
     including change
     in future capital   36,860   37,711   39,356   43,198   47,612   49,177
    -------------------------------------------------------------------------
    Total capital
     excluding goodwill  36,860   37,711   39,356   43,198   42,740   44,305
    -------------------------------------------------------------------------

    Reserve additions
     (mboe)(2)
    Exploration and
     development            744      962      715    1,201      910    1,222
    Acquisition             312      515      187      259      614      814
    -------------------------------------------------------------------------
    Total reserve
     additions (mboe)(2)  1,056    1,477      902    1,460    1,523    2,083
    -------------------------------------------------------------------------

    Costs ($/boe)
    F&D                   39.11    31.12    52.92    34.71    30.75    24.17
    FD&A                  34.92    25.53    43.63    29.59    31.26    23.60
    FD&A excluding
     goodwill             34.92    25.53    43.63    29.59    28.06    21.27
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Note: May not add due to rounding

    (1) The aggregate of the exploration and development costs incurred in
        the most recent financial year and the change during that year in
        estimated future development costs generally will not reflect total
        finding and development costs related to reserves additions for that
        year.
    (2) Company interest, meaning the total working interest (operating and
        non-operating) share before deduction of royalties payable to others
        and including any royalty interest of Cinch.


    Production & Reserve Life Index

    The Company's reserve life index using annualized fourth quarter
production is 8.1 years for proven BOE reserves compared to 7.3 years in 2005
and 12.1 years for proven plus probable BOE reserves compared to 10.5 years in
2005.

    Cinch exited the year with production of approximately 1,600 BOED.

    -------------------------------------------------------------------------
                                       2006                     2005
    -------------------------------------------------------------------------
                                             Calculated using:
    -------------------------------------------------------------------------
                              Annualized              Annualized
                                  Q4        Average       Q4        Average
                              Production  Production  Production  Production
    -------------------------------------------------------------------------
    Production (boe/d)             1,320       1,182       1,245       1,297
    Proved reserves (mboe)(1)      3,918       3,918       3,295       3,295
    Proved reserve life index
     (years)                         8.1         9.1         7.3         7.0
    Proved plus probable
     reserves (mboe)(1)            5,830       5,830       4,784       4,784
    Proved plus probable reserve
     life index (years)             12.1        13.5        10.5        10.1
    -------------------------------------------------------------------------
    (1) Company interest reserves means the total working interest (operating
        and non-operating) share before deduction of royalties payable to
        others and including royalty interests of Cinch.


    Reserve Replacement

    The Company's 2006 capital investment program replaced 2006 average
production by a factor of 2.4 times on a proved basis and 3.4 times on a
proved plus probable basis.

    -------------------------------------------------------------------------
                                              2006                    2005
                                  2006    (Annualized     2005    (Annualized
                                (Average)      Q4)      (Average)      Q4)
    -------------------------------------------------------------------------
    Production (mboe)              431.4       481.7       473.4       454.3
    Proved reserve additions
     after revisions of prior
     periods (mboe)(1)             1,056       1,056         902         902
    Proven replacement ratio         2.4         2.2         1.9           2
    Proved plus probable reserve
     additions after revision
     of prior periods (mboe)(1)    1,477       1,477       1,460       1,460
    Proved plus probable
     replacement ratio               3.4         3.1         3.1         3.2
    -------------------------------------------------------------------------
    (1) Company interest reserves means the total working interest (operating
        and non-operating) share before deduction of royalties payable to
        others and including royalty interests of Cinch.


    Recycle Ratio

    The recycle ratio is a measure for evaluating the effectiveness of a
company's re-investment program. The ratio measures the efficiency of capital
investment. It accomplishes this by comparing the operating netback per barrel
of oil equivalent to that year's reserve finding and development costs. Cinch
Energy presents the recycle ratio on both an FD&A basis (based on 2006 actual
FD&A) and an F&D basis using Company interest reserves.

    -------------------------------------------------------------------------
                                       2006       2006       2005       2005
                                      (FD&A)      (F&D)     (FD&A)      (F&D)
    -------------------------------------------------------------------------
    Operating netbacks ($/BOE)        30.20      30.20      36.92      36.92
    Proved finding, development
     and net acquisition costs
     after revision of prior
     periods and including the
     change in future development
     capital ($/BOE)                  34.92      39.11      43.63      52.92
    -------------------------------------------------------------------------
    Proved recycle ratios               0.9        0.8        0.9        0.7
    -------------------------------------------------------------------------
    Proved plus probable finding,
     development and acquisition
     costs after revisions of
     prior periods and including
     the change in future
     development capital ($/BOE)      25.53      31.12      29.59      34.70
    -------------------------------------------------------------------------
    Proved plus probable recycle
     ratios                             1.2        1.0        1.2        1.1
    -------------------------------------------------------------------------
    Note: May not add due to rounding
    


    OUTLOOK

    The 2006 year presented challenges to the oil and gas industry with
natural gas prices fluctuating dramatically, particularly in the third and
fourth quarters, causing the industry to reconsider and delay its drilling
programs. The cost structure for all services continued to escalate, which in
combination with falling natural gas prices challenged the economic
feasibility of natural gas prospects. Cinch views this as an opportunity,
since the down turn in drilling is causing the service sector to lower its
costs, and also services are now available to operators which were not in late
2005 and early 2006. In addition, with the drop in natural gas prices, the
Company is observing new drilling opportunities becoming available from other
industry partners as capital budgets are lowered. The Company still remains
very optimistic about the natural gas industry and has seen natural gas prices
firm up in the first quarter of 2007 due to cold weather and resultant natural
gas storage withdrawals.
    A flow through share financing for $10 million gross proceeds was
completed in the first quarter of 2007, strengthening the Company's balance
sheet and allowing more flexibility for the Company's 2007 drilling program.
    For the 2007 year, the Company is budgeting capital expenditures of
$30 million. Drilling activities are weighted to the latter half of 2007.
    In particular, your Company's management is looking forward to the
upcoming drilling program planned for the Chime area, which may lead to
significant production adds if successful, and to the new prospect and program
planned in British Columbia.

    Other Information

    Common shares of Cinch trade on the Toronto Stock Exchange under the
symbol of "CNH". Additional information relating to the Company is available
on SEDAR at www.sedar.com. The Annual and Special Meeting will be held on the
16th day of May, 2007 at 2:30 p.m. (Calgary time) in Great Room 3 at the
Sandman Hotel Calgary, 888- 7th Avenue S.W., Calgary, Alberta.

    Barrel of Oil Equivalency

    Natural gas volumes are converted to barrels of oil equivalent (BOE) on
the basis of six thousand cubic feet (mcf) of gas to one barrel (bbl) of oil.
The term "barrels of oil equivalent" may be misleading, particularly if used
in isolation. A BOE conversion ratio of six mcf to one bbl is based on an
energy equivalency conversion method primarily applicable at the burner tip
and does not represent a value equivalency at the wellhead.

    Forward Looking Statements

    Statements throughout this release that are not historical facts may be
considered to be "forward looking statements". These forward looking
statements sometimes include words to the effect that management believes or
expects a stated condition or result. All estimates and statements that
describe the Company's objectives, goals, or future plans, including
management's assessment of future plans and operations, results potential from
drilling on seismic information, anticipated commodity prices, production
estimates and expected production rates and declines, timing of bringing on
additional productive capacity, timing of drilling, completion and tie-in of
wells and the effects of infrastructure issues and plant capacity, expected
royalty rates and expenses related thereto, general and administrative
expenses and other expenses, effects of the results of successful wells, level
of capital expenditures and the method of funding of capital expenditures, and
the expected levels of activities may constitute forward-looking statements
under applicable securities laws and necessarily involve risks including,
without limitation, risks associated with oil and gas exploration,
development, exploitation, production, marketing and transportation, loss of
markets, volatility of commodity prices, imprecision of reserve estimates,
environmental risks, competition from other producers, inability to retain
drilling rigs and other services, incorrect assessment of the value of
acquisitions, failure to complete and/or realize the anticipated benefits of
acquisitions, delays resulting from or inability to obtain required regulatory
approvals and ability to access sufficient capital from internal and external
sources. As a consequence, the Company's actual results may differ materially
from those expressed in, or implied by, the forward-looking statements.
Readers are cautioned that the foregoing list of factors is not exhaustive.
Additional information on these and other factors that could affect the
Company's operations and financial results are included elsewhere herein and
in reports on file with Canadian securities regulatory authorities and may be
accessed through the SEDAR website (www.sedar.com), or at the Company's
website (www.cinchenergy.com). Furthermore, the forward-looking statements
contained in this release are made as at the date of this release and the
Company does not undertake any obligation to update publicly or to revise any
of the included forward-looking statements, whether as a result of new
information, future events or otherwise, except as may be required by
applicable securities laws.

    MANAGEMENT'S DISCUSSION AND ANALYSIS
    March 7, 2007

    The following management's discussion and analysis ("MD&A") should be
read in conjunction with Cinch Energy Corp.'s ("Cinch" or the "Company")
audited financial statements for the years ended December 31, 2006 and 2005.
This commentary is based on the information available as at, and is dated,
March 7, 2007. Additional information relating to Cinch, including Cinch's
Annual Information Form when filed, is on SEDAR at www.sedar.com.

    Non-GAAP Measures

    The MD&A contains the term "funds from operations" which should not be
considered an alternative to, or more meaningful than, cash provided by
operating activities or net income as determined in accordance with Canadian
generally accepted accounting principles ("GAAP") as an indicator of the
Company's performance. The Company considers funds from operations to be a key
measure that demonstrates its ability to generate funds for future growth
through capital investment. Funds from operations is calculated by taking cash
provided by operating activities on the statement of cash flows less the
effect of changes in non-cash working capital related to operating activities.
The Company's determination of funds from operations may not be comparable
with the calculation of similar measures by other companies. The Company also
presents funds from operations per share, where funds from operations is
divided by the weighted average number of shares outstanding to determine per
share amounts. The Company evaluates its performance based on earnings and
funds from operations.
    The MD&A contains the term "net debt" which is the sum of the working
capital (deficiency) and the outstanding credit facility balance. This number
may not be comparable to that reported by other companies.

    OPERATIONAL UPDATE

    The Company's program for the fourth quarter of 2006 consisted primarily
of completing and tieing-in wells drilled in the third quarter of 2006 in the
Kakwa, Kakwa North and Chime areas.
    Production levels increased in the fourth quarter of 2006 compared to the
prior three quarters of 2006 due to the Resthaven 9-25 well, which came on
production at rates of approximately 200 BOE/d net to Cinch at the end of
November, 2006, after having previously been shut-in on September 30, 2006 for
testing. The Kakwa North 10-20 well also came on production in the fourth
quarter of 2006, as did the Bigstone 3-25 well. In addition, a well in Kakwa
area and a well in Chime area were tied-in and commenced production in the
last two weeks of December.
    As noted above, the Bigstone 3-25 well, the most significant well in our
Bigstone area, was brought back on production in December of 2006 at
production rates of approximately 115 BOE/d net to Cinch. This well was shut
in again on January 30, 2007 and we anticipate that production from Bigstone
will be sporadic until April of 2007 due to plant capacity issues.

    
    PRODUCTION

    -------------------------------------------------------------------------
                             Three Months Ended            Year Ended
                                December 31,               December 31,
                           2006     2005   Change     2006     2005   Change
    -------------------------------------------------------------------------
    Sales volumes                               %                          %
    Natural gas (Mcf/d)   6,500    6,248        4    5,851    6,478      (10)
    Liquids (Bbl/d)         236      203       16      207      217       (5)
    Equivalence (BOE/d)   1,320    1,245        6    1,182    1,297       (9)

    Sales prices              $        $        %        $        $        %
    Natural gas ($/Mcf)    7.49    12.44      (40)    7.14     9.59      (26)
    Liquids($/Bbl)        57.56    62.69       (8)   64.53    59.83        8
    Equivalence ($/BOE)   47.22    72.68      (35)   46.62    57.90      (19)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Sales volumes for the year ended December 31, 2006 decreased compared to
2005 due to declines in production from wells that came on in late 2004 and
produced at higher rates in 2005.
    Sales volumes for the three months ended December 31, 2006 increased
compared to the same period of 2005 due to an increased number of producing
wells, with the most significant well being the Resthaven 9-25 well. This well
commenced production on November 25 at rates of approximately 200 BOE/d (net).
The Kakwa North 10-20 well also came on production late in November 2006 at
rates of approximately 90 BOE/d (net). There were also two new wells, one each
in Chime and Kakwa, which came on production late in December 2006 and as a
result the Company exited 2006 at a rate of approximately 1600 BOE/d. It is
anticipated that the new production will experience typical Deep Basin decline
rates in their first year of production.
    The Company's production is primarily from deep, tight gas, which
normally experiences high decline rates in the first year, with decline rates
typically reducing and stabilizing thereafter and providing a strong
production base. As the Company builds a larger production base, declines on
new production should have a less significant impact.
    The Company's production volumes in 2006 have been impacted by plant
capacity issues. The Bigstone production was completely shut-in for the second
and third quarter of 2006, coming back on production late in the fourth
quarter of 2006. The Musreau plant had also experienced capacity issues
throughout the first three quarters, causing wells to be sporadically shut in.
    Natural gas prices dropped 40% in the fourth quarter of 2006 compared to
the same quarter of 2005 and 26% year over year. The Company's natural gas
production continues to be unhedged and is marketed in the Alberta spot
market.
    Natural gas liquids pricing has dropped 8% in the fourth quarter of 2006
compared to the same quarter of 2005 and 17% since the third quarter of 2006.
The natural gas liquids pricing for the year ended December 31, 2006 has
increased 8% over 2005. Natural gas liquids represents approximately 24% of
oil and gas revenues. The Company has not hedged any of its liquids
production.

    
    REVENUES

    Dollars in thousands, except per unit amounts
    -------------------------------------------------------------------------
                             Three Months Ended            Year Ended
                                December 31,               December 31,
                           2006     2005   Change     2006     2005   Change
    -------------------------------------------------------------------------
                              $        $        %        $        $        %
    Oil and gas sales,
     net of
     transportation       5,733    8,323      (31)  20,112   27,413      (27)
    Per BOE               47.22    72.68      (35)   46.62    57.90      (19)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Revenues for the three months and year ended December 31, 2006 are lower
than the same periods of 2005 primarily as a result of lower natural gas
prices, as previously discussed.

    ROYALTIES

    Dollars in thousands, except per unit amounts
    -------------------------------------------------------------------------
                             Three Months Ended            Year Ended
                                December 31,               December 31,
                           2006     2005   Change     2006     2005   Change
    -------------------------------------------------------------------------
                              $        $        %        $        $        %
    Royalties, net of
     ARTC                 1,126    2,109      (47)   4,111    7,213      (43)
    Per BOE                9.27    18.42      (50)    9.53    15.23      (37)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Royalty expense, net of Alberta Royalty Tax Credit ("ARTC"), decreased in
the three months and year ended December 31, 2006 compared to the same periods
of 2005 as a result of lower commodity prices. Two higher producing wells also
paid out in the second and third quarters of 2005; hence the Company did not
pay gross overriding royalties on these wells in 2006. The Company's royalty
rate (royalties net of ARTC as a percentage of oil and gas sales) was lower in
2006 at 20% versus 26% in 2005. Some of the Company's higher producing wells
which came on production in 2006 are eligible for royalty holiday thereby
reducing the royalty rate when compared to total oil and gas sales. There was
also approximately $600 thousand more in gas cost allowance recorded in 2006
compared to 2005, thereby further reducing the royalty rate.
    The increase in royalty expense from the third quarter of 2006 can be
attributed to increased volumes as well as increased natural gas prices.
    The Company anticipates that its royalty rate in 2007 will be higher than
that of 2006, due to the exhaustion of certain royalty holidays and due to the
elimination of ARTC effective January 1, 2007, previously an annual benefit to
the Company of $500 thousand. Anticipated royalty rates can change, depending
upon commodity prices, actual success achieved and the zone in which
productive success is achieved.

    
    OPERATING EXPENSES

    Dollars in thousands, except per unit amounts
    -------------------------------------------------------------------------
                             Three Months Ended            Year Ended
                                December 31,               December 31,
                           2006     2005   Change     2006     2005   Change
    -------------------------------------------------------------------------
                              $        $        %        $        $        %
    Operating               759      633       20    3,065    2,722       13
    Per BOE                6.25     5.53       13     7.10     5.75       23
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Total operating expenses as well as operating expenses per BOE increased
in the three months and year ended December 31, 2006 compared to the same
periods of 2005, due to increased expenses relating to an additional 10
producing wells, as well as other increased operating expenses.
    For the year ended December 31, 2006 the increases related primarily to
compressor costs ($50 thousand), methanol costs ($50 thousand), contractor
costs associated with the increased activity ($120 thousand) as well as
increased property taxes ($45 thousand). Gas gathering and processing fees are
also approximately $60 thousand or $0.42/BOE higher for the year ended
December 31, 2006 compared to the same period of 2005.
    Total operating expenses as well as operating expenses per BOE were lower
in the fourth quarter of 2006 compared to the third quarter of 2006 primarily
due to property taxes expensed in the third quarter, partially offset by
increased gas gathering and processing fees in the fourth quarter attributable
to higher production.
    Operating expenses are expected to average approximately $6.50 per BOE in
2007.

    
    GENERAL AND ADMINISTRATIVE EXPENSES

    Dollars in thousands, except per unit amounts
    -------------------------------------------------------------------------
                             Three Months Ended            Year Ended
                                December 31,               December 31,
                           2006     2005   Change     2006     2005   Change
    -------------------------------------------------------------------------
                              $        $        %        $        $        %
    General and
     administrative         932      912        2    3,548    2,749       29
    Per BOE                7.68     7.96       (4)    8.22     5.81       41
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Total general and administrative expenses increased for the three months
and year ended December 31, 2006 compared to the same periods of 2005 due to
the hiring of additional employees and the increased use of contractors and
consultants to handle operation, administration and exploration activities.
The Company does not capitalize any general and administrative expenses. Due
to the increased number of employees and the need to remain competitive in the
marketplace, salaries and related compensation increased approximately
$600 thousand for the year ended December 31, 2006. This amount includes the
increase in non-cash stock based compensation expense of $240 thousand
attributable to a greater number of stock options outstanding (4,071,334
options at December 31, 2006 compared to 2,328,000 options at December 31,
2005). As at March 7, 2007, the Company has 4,078,000 options outstanding,
amounting to approximately 7.3% of outstanding common shares and special
warrants. Public company related expenses such as annual reports, corporate
governance compliance, audit fees, and reserve reports have also increased
approximately $130 thousand for the year ended December 31, 2006 compared to
the same period of 2005. Insurance costs have also increased $60 thousand over
the past year with increases consistent throughout the industry.
    General and administrative expenses per BOE have decreased in the fourth
quarter of 2006 compared to the same period as 2005 due to increased
production in the fourth quarter of 2006. The general and administrative
expenses per BOE for the year ended December 31, 2006 have increased over 2005
primarily due to higher expenses.
    Total general and administrative expenses increased in the fourth quarter
of 2006 compared to the third quarter due to increased compensation expense,
including $60 thousand in non-cash stock based compensation expense, as well
as increased public company related expenses, primarily relating to corporate
governance compliance.
    Cash general and administrative expenses per BOE for 2006 were lower than
the forecasted $6.50/BOE at approximately $6.22 per BOE. The non-cash stock
based compensation expense averaged approximately $2.00 per BOE for all of
2006, as anticipated.
    Cash general and administrative expenses for 2007 are expected to average
approximately $5.50 per BOE as a result of forecasted higher production
volumes for the full year. The non-cash stock based compensation expense is
expected to average $2.00 per BOE for 2007.

    
    INTEREST EXPENSE

    Dollars in thousands, except per unit amounts
    -------------------------------------------------------------------------
                             Three Months Ended            Year Ended
                                December 31,               December 31,
                           2006     2005   Change     2006     2005   Change
    -------------------------------------------------------------------------
                              $        $        %        $        $        %
    Interest expense        250        6     4067      461      299       54
    Per BOE                2.06     0.05     4020     1.07     0.63       70
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Interest expense increased in the three months and year ended
December 31, 2006 compared to the same periods of 2005 due to higher draws on
the Company's bank credit facility in 2006. The Company did not draw on its
$33 million bank line until the second quarter of 2006 and exited the year
with an amount outstanding under its credit facility of $17.3 million.

    
    ACCRETION OF ASSET RETIREMENT OBLIGATIONS EXPENSE

    Dollars in thousands, except per unit amounts
    -------------------------------------------------------------------------
                             Three Months Ended            Year Ended
                                December 31,               December 31,
                           2006     2005   Change     2006     2005   Change
    -------------------------------------------------------------------------
                              $        $        %        $        $        %
    Accretion expense        14       45      (69)      63      158      (60)
    Per BOE                0.12     0.40      (70)    0.15     0.33      (55)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Accretion expense decreased in the three months and year ended
December 31, 2006 compared to the same periods of 2005 as a result of an
extension of the abandonment dates of the wells based on evaluations completed
in 2006, in large part due to the pricing used in the reserves report
extending the economic life of the wells. The economic lives of the wells were
assessed and determined to be longer than originally estimated and as such the
liability is being accrued over a longer period of time. The decrease is
partially offset by the accretion recorded associated with new wells completed
during the year.

    
    DEPLETION AND DEPRECIATION EXPENSE

    Dollars in thousands, except per unit amounts
    -------------------------------------------------------------------------
                             Three Months Ended            Year Ended
                                December 31,               December 31,
                           2006     2005   Change     2006     2005   Change
    -------------------------------------------------------------------------
                              $        $        %        $        $        %
    Depletion and
     depreciation         3,243    2,697       20   10,897    9,257       18
    Per BOE               26.71    23.55       13    25.26    19.55       29
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Total depletion and depreciation expense as well as depletion per BOE for
the three months and year ended December 31, 2006 increased compared to the
same periods of 2005 due to a larger capital asset balance being depleted,
partially offset by reserve additions in 2006. The Company has experienced
overall higher capital costs in 2006.

    
    TAXES

    Dollars in thousands, except per unit amounts
    -------------------------------------------------------------------------
                             Three Months Ended            Year Ended
                                December 31,               December 31,
                           2006     2005   Change     2006     2005   Change
    -------------------------------------------------------------------------
                              $        $        %        $        $        %
    Current                   -       18     (100)       -       98     (100)
    Future income taxes
     (recovery)             (81)     637     (113)  (1,570)   1,710     (192)
    Per BOE               (0.66)    5.72     (112)   (3.64)    3.82     (195)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Current taxes were reduced to nil in the second quarter of 2006 to
reflect the elimination of large corporations tax effective January 1, 2006,
which became law on June 22, 2006.
    The future income tax recovery for the three months ended December 31,
2006 is consistent with the net loss experienced during the quarter.
    The future income tax recovery recorded for the year ended December 31,
2006 reflects the reduction in future tax rates as legislated by the federal
government on June 22, 2006. In the second quarter of 2006, the future tax
liability previously recognized by the Company was recalculated to reflect
these lower rates, and the difference between the original estimate of the
future tax liability and the June 30, 2006 estimate at lower tax rates
resulted in a large future tax recovery recorded in the second quarter.

    
    Tax pools at December 31, 2006:

    Dollars in thousands
    -------------------------------------------------------------------------
                                                              2006      2005
                                                                 $         $
    -------------------------------------------------------------------------
    COGPE                                                   12,593     7,620
    CDE                                                     23,266    18,412
    CEE                                                     18,272    15,723
    UCC                                                     21,346    15,488
    -------------------------------------------------------------------------
                                                            75,477    57,243
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    The Company's tax pools increased significantly in 2006 as a result of
capital expenditures which were higher than the tax deductions needed to
eliminate taxable income. An equity financing completed in 2005 included flow
through common shares of $10 million, for which the renunciation was completed
in 2006 and deducted from the above tax pools.

    
    NET INCOME AND FUNDS FROM OPERATIONS

    In thousands, except per share figures
    -------------------------------------------------------------------------
                             Three Months Ended            Year Ended
                                December 31,               December 31,
                           2006     2005   Change     2006     2005   Change
    -------------------------------------------------------------------------
                              $        $        %        $        $        %
    Net income             (488)   1,364     (136)    (317)   3,364     (109)
      per basic share     (0.01)    0.03     (133)   (0.01)    0.08     (113)
      per diluted share   (0.01)    0.03     (133)   (0.01)    0.08     (113)
    Funds from
     operations           2,970    4,899      (39)   9,966   15,042      (34)
      per basic share      0.06     0.10      (40)    0.21     0.38      (44)
      per diluted share    0.06     0.10      (40)    0.20     0.36      (44)
    Weighted average
     shares & special
     warrants
     outstanding         47,813   47,813        -   47,813   40,047       19
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    For the year ended December 31, 2006, the Company incurred a net loss,
attributable to lower natural gas pricing as well as higher general and
administrative costs, higher operating costs as well as higher depletion
expense compared to the same period of 2005. The Company incurred a net loss
for the three months ended December 31, 2006, a decrease compared to the same
period of 2005 due to the same factors as discussed above. In 2006, the
Company was largely affected by the decline in commodity prices and
anticipates further volatility in commodity prices in 2007.
    The Company generated positive funds from operations for the three months
and year ended December 31, 2006 but compared to the same periods of 2005
funds from operations are lower primarily due to significantly lower natural
gas prices.

    
    LIQUIDITY AND CAPITAL RE

SOURCES Dollars in thousands ------------------------------------------------------------------------- As at December 31, 2006 2005 Change ------------------------------------------------------------------------- $ $ % Working capital (deficiency), excluding credit facility (6,441) 3,490 (285) Credit facility (17,304) - (100) ------------------------------------------------------------------------- Working capital (net debt) (23,745) 3,490 (780) Capital lease obligation (277) (421) (34) Shareholders' equity (90,066) (93,400) (4) ------------------------------------------------------------------------- ------------------------------------------------------------------------- At December 31, 2006, the Company had net debt of $23.7 million, including a working capital deficiency of $6.4 million, primarily as a result of $37 million in capital expenditures incurred in 2006. The Company did not complete any financings in 2006 and funded its expenditures with cash flow and net debt. Subsequent to December 31, 2006, the Company issued 7,812,500 common shares on a flow through basis at a price of $1.28 per share for gross proceeds of $10,000,000. The fourth quarter funds from operations increased by $900 thousand from the third quarter of 2006 and, combined with capital expenditures of $9.3 million in the fourth quarter, resulted in the Company exiting 2006 with net debt of $23.7 million. Net debt was slightly lower than anticipated by the Company as a result of stronger than forecast natural gas prices in the fourth quarter and the resultant improvement in funds from operations. Management intends to fund its 2007 capital program with a combination of funds generated from operations, funds received from the financing of flow through shares noted above, and its bank credit facility. The decrease in shareholder's equity at December 31, 2006 from December 31, 2005 is due to the tax effect of $10 million in flow through share expenditures renounced in the first quarter of 2006, effective December 31, 2005. CAPITAL EXPENDITURES Additions to property, plant and equipment Dollars in thousands ------------------------------------------------------------------------- Year Ended December 31, 2006 2005 ------------------------------------------------------------------------- $ $ Land and rentals 6,462 4,083 Seismic 984 796 Drilling, completing and equipping 23,989 26,046 Pipelines and facilities 5,378 5,038 Other assets 153 82 ------------------------------------------------------------------------- Total 36,966 36,045 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Capital expenditures for the year ended December 31, 2006 were incurred primarily on drilling, completing and tieing in locations in the Chime, Kakwa, and Musreau areas. In addition, the Company purchased land in 2006, focusing on the Kakwa, Chime and Dawson West areas, further increasing the Company's land base in its core areas as well as providing opportunities for further plays in the Dawson West area, which has become increasingly active. Capital expenditures for 2006 include the April 2006 acquisitions of additional working interests in 7 producing gas wells as well as undeveloped land in the Chime area for a total of $10.75 million. The undeveloped land from these acquisitions was subsequently sold to a joint venture partner for $3 million, thereby reducing the Company's acquisition costs for the production and reserves to $7.75 million (net), which is included in the above total. Management's primary strategy is to expend capital on exploration and development drilling and earn land by drilling. The Company may, however, also purchase land where considered strategic. The Company's 2007 first quarter capital program will be focused on drilling, completing and tieing locations in the Chime, Chime East, Doe and Kakwa East areas. BUSINESS RISKS AND RISK MANAGEMENT The long-term commercial success of the Company depends on its ability to find, acquire, develop and commercially produce oil and natural gas reserves. Cinch attempts to reduce risk in accomplishing these goals through the combination of hiring experienced and knowledgeable personnel and careful evaluation. The Company's program is exploratory in nature and in areas with deep, tight gas. The wells the Company drills therefore tend to be deep (a substantial portion are deeper than 2,500 meters), and are subject to higher drilling costs than those in more shallow areas. In addition, most wells require fracture treatment before they are capable of production, also increasing costs. The Company mitigates the additional economic pressure that this creates by carefully evaluating risk/reward scenarios for each location, by taking what management considers to be appropriate working interests after considering project risk, by practicing prudent operations so that drilling risk is decreased, by ranking and limiting the zones that the Company is willing to complete, and also by drilling deep so that the multi-zone potential of the area can be accessed and potentially developed. The Company operates the majority of its lands which provides a measure of control over the timing and location of capital expenditures. In addition, the Company monitors capital spending on an ongoing and regular basis so that the Company maintains liquidity and so that future financial resource requirements can be anticipated. The financial capability of the Company's partners can pose a risk to the Company, particularly during periods when access to capital is more challenging and prices are depressed. The Company mitigates the risk of collection by attempting to obtain the partners share of capital expenditures in advance of a project and by monitoring receivables regularly. The ability of the Company to implement its capital program when the financial wherewithal of a partner is challenged can be more difficult, although the Company attempts to mitigate the risk by cultivating multiple business relationships and obtaining new partners when needed and where possible. Commodity price fluctuations can pose a risk to the Company, and management monitors these on an ongoing basis. External factors beyond the Company's control may affect the marketability of the natural gas and natural gas liquids produced. The Company has not to date implemented any hedging instruments. The Company has selected the appropriate personnel to monitor operations and has automated field information where possible, so that difficulties and operational issues can be assessed and dealt with on a timely basis, and so that production can be maximized as much as possible. Not all operations issues; however, are within the Company's control. Management will address them nonetheless, and attempt to implement solutions, which may be by their nature longer term. Oil and natural gas exploration, development and production operations are subject to all the risks and hazards typically associated with such operations, including hazards such as fire, explosion, blowouts, and spills, each of which could result in damage to wells, production facilities, other property and the environment or in personal injury. In accordance with industry practice, the Company insures against most of these risks (although not all such risks are insurable). The Company maintains liability insurance in an amount that it considers consistent with industry practice, although the nature of these risks is such that liabilities could potentially exceed policy limits. The Company also reduces risk by operating a large percentage of its operations. As such, the Company has control over the quality of work performed and the personnel involved. The Company anticipates making substantial capital expenditures in future for the exploration, development, acquisition and production of oil and natural gas reserves. If the Company's revenues or reserves decline, it may have limited ability to expend the capital necessary to undertake or complete future drilling programs. There can be no assurance that debt or equity financing will be available. The Company mitigates this risk by monitoring expenditures, operations and results of operations in order to manage available capital effectively. Attracting and retaining qualified individuals is crucial to the Company's success. The Company understands the importance of maintaining competitive compensation levels given this increasingly competitive environment in which the Company operates. The inability to attract and retain key employees could have a material adverse effect on the Company. 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. Given the evolving nature of the debate related to climate change and the control of greenhouse gases and resulting requirements, it is not possible to predict either the nature of those requirements or the impact on the Company and its operations and financial condition. The Company's ability to move heavy equipment in the field is dependent on weather conditions. Rain and snow can impact conditions, and many secondary roads and future oil and gas production sites are incapable of supporting the weight of heavy equipment until the roads are thoroughly dry. The duration of difficult conditions has a direct impact on the Company's activity levels and as a result can delay operations. DISCLOSURE CONTROLS AND PROCEDURES The Company has designed disclosure controls and procedures to provide reasonable assurance that material information relating to the Company required to be disclosed is recorded, processed, summarized and reported within the time periods specified by securities regulations and that information required to be disclosed is communicated to management on a timely basis. The Chief Executive Officer and the Chief Financial Officer have evaluated the effectiveness of these disclosure controls and procedures as of the end of the period covered by the annual filings and have concluded, based on such evaluation, that the Company's disclosure controls and procedures as of the end of such period are effective to provide reasonable assurance that material information relating to the Company is made known to them by others within the Company, particularly during the period in which the annual filings are being prepared. INTERNAL CONTROLS OVER FINANCIAL REPORTING The Company's Chief Executive Officer and Chief Financial Officer have designed or caused to be designed under their supervision, internal controls over financial reporting relating to the Company to provide reasonable assurance regarding the reliability of the Company's financial reporting and the preparation of financial statements for external purposes in accordance with Canadian GAAP. The Company's Chief Executive Officer and Chief Financial Officer are required to cause the Company to disclose any change in the Company's internal controls over financial reporting that occurred during the Company's most recent interim period that has materially affected, or is reasonably likely to materially affect, the Company's internal controls over financial reporting. No material changes in the Company's internal controls over financial reporting were identified during the three months ended December 31, 2006, that have materially affected, or are reasonably likely to affect, the Company's internal controls over financial reporting. FUTURE PROSPECTS Management continues to be optimistic about the growth of the Company, despite some challenges encountered in 2006. Cinch has expanded its land base in British Columbia, a new prospect for the Company. With prudent risk management, careful evaluation of results, continued development of the lands as well as expansion into new and existing areas, management believes that the Company will continue to be successful. CONTRACTUAL OBLIGATIONS, COMMITMENTS, AND GUARANTEES The Company has contractual obligations and commitments in the normal course of its operating and financing activities. These obligations and commitments have been considered when assessing the Company's cash requirements in its analysis of future liquidity. Dollars in thousands ------------------------------------------------------------------------- Payments greater less than 1-3 4-5 than Total 1 year years years 5 years ------------------------------------------------------------------------- Long term portion of capital lease obligation 277 - 277 - - Operating lease 508 174 334 - - ------------------------------------------------------------------------- 785 174 611 - - ------------------------------------------------------------------------- ------------------------------------------------------------------------- CHANGES IN ACCOUNTING POLICIES No new accounting policies were adopted in the year ended December 31, 2006. RECENT ACCOUNTING PRONOUNCEMENTS The Canadian Institute of Chartered Accountants (CICA) has issued a number of accounting pronouncements, some of which may impact the Company's reported results and financial position in future periods. Comprehensive Income, Financial Instruments and Hedges The CICA issued new standards in early 2005 for Comprehensive Income (CICA 1530), Financial Instruments (CICA 3855) and Hedges (CICA 3865), which will be effective for the reporting year-end 2007. The new standards will bring Canadian rules in line with current rules in the US. The standards will introduce the concept of "Comprehensive Income" to Canadian GAAP and will require that an enterprise (a) classify items of comprehensive income by their nature in a financial statement and (b) display the accumulated balance of comprehensive income separately from retained earnings and additional paid-in capital in the equity section of a statement of financial position. Derivative contracts will be carried on the balance sheet at their mark-to-market value, with the change in value flowing to either net income or comprehensive income. Gains and losses on instruments that are identified as hedges will flow initially to comprehensive income and be brought into net income at the time the underlying hedged item is settled. Any instruments that do not qualify for hedge accounting will be marked-to-market with the adjustment (tax effected) flowing through the income statement. The Company does not anticipate these standards will have a significant impact on the Company's financial statements. CRITICAL ACCOUNTING ESTIMATES There are a number of critical estimates underlying the accounting policies the Company applies in preparing its financial statements. Reserves The estimate of reserves is used in forecasting what will ultimately be recoverable from the properties and their economic viability and in calculating the Company's depletion and potential impairment of asset carrying costs. The process of estimating reserves is complex and requires significant interpretation and judgment. It is affected by economic conditions, production, operating and development activities, and is performed using available geological, geophysical, engineering and economic data. Reserves at year end are evaluated by an independent engineering firm and quarterly updates to those reserves are estimated by the Company. Revenue Estimates Payment and actual amounts for petroleum and natural gas sales can be received months after production. The Company estimates a portion of its petroleum and natural gas production, sales and related costs, based upon information received from field offices, internal calculations, historical and industry experience. Cost Estimates Costs for services performed but not yet billed are estimated based on quotes provided and historical and industry experience. Asset Retirement Obligations The liability recorded for asset retirement obligations, an estimate of restoring assets and locations back to environmental and regulatory standards upon future retirement or abandonment, include estimates of restoration costs to be incurred in the future and an estimated future inflation rate. Costs estimated are based upon internal and third party calculations and historical experience and future inflation rates are estimated using historical experience and available economic data. Income taxes The Company records future tax liabilities to account for the expected future tax consequences of events that have been recorded in its financial statements. These amounts are estimates; the actual tax consequences may differ from the estimates due to changing tax rates and regimes, as well as changing estimates of cash flows and capital expenditures in current and future periods. All tax filings are subject to audit and potential reassessment after the lapse of considerable time. Accordingly, the actual income tax liability may differ significantly from that estimated and recorded. TREND ANALYSIS Throughout 2006, the Company has been focused on drilling and completing wells, as well as tieing-in production. In the first quarter of 2006, drilling activities were delayed due to lack of rig availability. The Company alleviated the problem in the second quarter by entering into a one year contract on a drilling rig, which has facilitated the execution of the Company's 2006 third and fourth quarter drilling programs. Given the softness in the oil and gas market experienced in 2006 and into 2007, the Company does not anticipate challenges in obtaining a rig in 2007 and does not anticipate extending its drilling contract. The Company has made strides on building a stable production base and continues to work on achieving growth, exiting the year at approximately 1600 BOE/d. Consistent with other exploration companies, there will be periods of higher production growth, periods with flush production on new wells which is then anticipated to decline and stabilize in future periods, with some periods experiencing less growth than others. The Company's production for the year ended December 31, 2006 decreased compared to the same period of 2005 primarily as a result of the Kakwa 16-13 well which came on production in late 2004 at higher rates with production subsequently declining toward the end of 2005 and stabilizing in 2006. These declines are typical with deep, tight gas wells until decline rates stabilize. Declines in production were partially offset by production additions from 10 new producing wells in 2006. Natural gas prices increased in the fourth quarter of 2006 compared to the second and third quarters resulting in increased revenues in the fourth quarter of 2006. The natural gas prices were still significantly lower than the prices experienced in the fourth quarter of 2005 resulting in lower revenues despite the higher production in the fourth quarter of 2006. Natural gas liquids pricing continued to decrease in the fourth quarter of 2006 compared to the second and third quarters as well as compared to the same quarter of 2005. The increased production in the fourth quarter of 2006 helped offset the impact of the decreased liquids prices. The Company is largely impacted by price variations in the short term. Management believes in the long term strength of the natural gas market, despite short term fluctuations and volatility. SELECTED ANNUAL AND QUARTERLY INFORMATION (000's, except per share data) Q1 Q2 Q3 Q4 Annual ------------------------------------------------------------------------- 2006 $ $ $ $ $ ------------------------------------------------------------------------- Petroleum and natural gas sales, net of transportation and before royalties 5,200 4,692 4,487 5,733 20,112 Funds from operations 2,475 2,406 2,115 2,970 9,966 Per share - basic 0.05 0.05 0.05 0.06 0.21 - diluted 0.05 0.05 0.04 0.06 0.20 Net income (131) 879 (576) (488) (317) Per share - basic (0.00) 0.02 (0.01) (0.01) (0.01) - diluted (0.00) 0.02 (0.01) (0.01) (0.01) Capital expenditures 6,696 13,542 7,403 9,324 36,966 Acquisition - - - - - Total assets 113,356 121,861 125,894 136,983 136,983 Working capital (net debt)(1) (820) (11,942) (17,307) (23,745) (23,745) ------------------------------------------------------------------------- Production (BOE/d) 1,130 1,141 1,135 1,320 1,182 ------------------------------------------------------------------------- 2005 $ $ $ $ $ ------------------------------------------------------------------------- Petroleum and natural gas sales, net of transportation and before royalties 6,062 5,821 7,207 8,323 27,413 Funds from operations 3,198 3,037 3,908 4,899 15,042 Per share - basic 0.10 0.09 0.09 0.10 0.38 - diluted 0.09 0.08 0.09 0.10 0.36 Net income 612 537 851 1,364 3,364 Per share - basic 0.02 0.01 0.02 0.03 0.08 - diluted 0.02 0.01 0.02 0.03 0.08 Capital expenditures 6,381 8,116 9,566 11,982 36,045 Acquisition - - 1,220 (15) 1,205 Total assets 80,706 89,047 112,178 113,620 113,620 Working capital (net debt)(1) (16,621) (3,670) 10,629 3,490 3,490 ------------------------------------------------------------------------- Production (BOE/d) 1,421 1,264 1,262 1,245 1,297 ------------------------------------------------------------------------- 2004 $ $ $ $ $ ------------------------------------------------------------------------- Petroleum and natural gas sales, net of transportation and before royalties 733 873 2,577 4,033 8,215 Funds from operations 190 329 1,314 1,924 3,757 Per share - basic 0.02 0.03 0.06 0.06 0.19 - diluted 0.02 0.03 0.06 0.05 0.17 Net income (loss) (231) 11 131 189 99 Per share - basic (0.02) (0.00) 0.01 0.01 0.00 - diluted (0.02) (0.00) 0.01 0.01 0.00 Capital expenditures 1,726 1,492 1,446 11,385 16,049 Acquisition - - 48,625 79 48,704 Total assets 13,548 54,995 66,060 77,560 77,560 Working capital (net debt)(1) 990 109 (6,011) (14,759) (14,759) ------------------------------------------------------------------------- Production (BOE/d) 204 216 691 981 525 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Note: numbers may not cross-add due to rounding (1) Working capital (net debt) excludes the long term financial liabilities which consists of the long term portion of the capital lease obligation (December 31, 2006 - $276,806, December 31, 2005 - $420,988, December 31, 2004 - $620,764). Financial Statements CINCH ENERGY CORP. Balance Sheets As at December 31, 2006 2005 $ $ ------------------------------------------------------------------------- ASSETS (note 6) Current Cash and cash equivalents (note 3) - 5,654,594 Accounts receivable (note 4) 9,107,635 6,510,076 Prepaid expenses and deposits 957,338 752,551 ------------------------------------------------------------------------- 10,064,973 12,917,221 Property, plant and equipment (note 5) 112,301,421 86,085,917 Goodwill 14,616,996 14,616,996 ------------------------------------------------------------------------- ------------------------------------------------------------------------- 136,983,390 113,620,134 ------------------------------------------------------------------------- ------------------------------------------------------------------------- LIABILITIES AND SHAREHOLDERS' EQUITY Current Accounts payable and accrued liabilities 16,229,842 9,216,805 Credit facility (note 6) 17,304,333 - Current portion of capital lease obligation (note 7) 275,789 210,007 ------------------------------------------------------------------------- 33,809,964 9,426,812 Capital lease obligation (note 7) 276,806 420,988 Asset retirement obligations (note 8) 2,934,899 2,725,627 Future income taxes (note 9) 9,410,600 7,646,760 ------------------------------------------------------------------------- 46,432,269 20,220,187 ------------------------------------------------------------------------- Commitments (note 11) Shareholders' equity Share capital (note 10) 89,618,546 93,044,644 Contributed surplus (note 10) 2,144,649 1,250,842 Deficit (1,212,074) (895,539) ------------------------------------------------------------------------- 90,551,121 93,399,947 ------------------------------------------------------------------------- 136,983,390 113,620,134 ------------------------------------------------------------------------- ------------------------------------------------------------------------- See accompanying notes On behalf of the Board: Director Director CINCH ENERGY CORP. STATEMENTS OF OPERATIONS AND DEFICIT For the years ended December 31, 2006 2005 $ $ ------------------------------------------------------------------------- Revenue Oil and gas sales 20,900,612 28,282,556 Transportation (788,794) (869,753) Royalties, net of Alberta Royalty Tax Credit (4,110,930) (7,212,766) Other income 145,124 155,697 ------------------------------------------------------------------------- 16,146,012 20,355,734 ------------------------------------------------------------------------- Expenses Operating 3,064,713 2,721,887 General and administrative (note 10) 3,547,742 2,748,928 Interest on credit facility 433,677 276,577 Interest on capital lease (note 7) 27,339 22,274 Accretion of asset retirement obligations (note 8) 62,659 157,849 Depletion and depreciation 10,896,817 9,256,752 ------------------------------------------------------------------------- 18,032,947 15,184,267 ------------------------------------------------------------------------- Income before income taxes (1,886,935) 5,171,467 Income Taxes (note 9) Current - 97,650 Future (1,570,400) 1,709,900 ------------------------------------------------------------------------- (1,570,400) 1,807,550 ------------------------------------------------------------------------- Net income (loss) for the year (316,535) 3,363,917 Deficit, beginning of year (895,539) (4,259,456) ------------------------------------------------------------------------- Deficit, end of year (1,212,074) (895,539) ------------------------------------------------------------------------- ------------------------------------------------------------------------- Net income (loss) for the year per share (note 10) Basic and diluted (0.01) 0.08 ------------------------------------------------------------------------- ------------------------------------------------------------------------- See accompanying notes CINCH ENERGY CORP. STATEMENTS OF CASH FLOWS For the years ended December 31, 2006 2005 $ $ ------------------------------------------------------------------------- Operating activities Net income (loss) for the year (316,535) 3,363,917 Add non-cash items: Depletion and depreciation 10,896,817 9,256,752 Accretion of asset retirement obligations 62,659 157,849 Non-cash compensation expense (note 10) 893,807 553,866 Future income taxes (1,570,400) 1,709,900 ------------------------------------------------------------------------- 9,966,348 15,042,284 Net change in non-cash working capital 680,757 (722,225) ------------------------------------------------------------------------- Cash provided by operating activities 10,647,105 14,320,059 ------------------------------------------------------------------------- Investing activities Additions to property, plant and equipment (36,965,708) (36,045,324) Acquisition, net of cash acquired (note 5) - (1,204,754) Net change in non-cash working capital 3,616,069 (1,937,990) ------------------------------------------------------------------------- Cash used by investing activities (33,349,639) (39,188,068) ------------------------------------------------------------------------- Financing activities Increase (decrease) in credit facility 17,304,333 (9,963,616) Issue of common shares, net of issue costs (91,858) 40,723,117 Payments on capital lease (78,400) (196,690) Net change in non-cash working capital (86,135) (40,208) ------------------------------------------------------------------------- Cash provided by financing activities 17,047,940 30,522,603 ------------------------------------------------------------------------- Increase (decrease) in cash (5,654,594) 5,654,594 Cash and cash equivalents, beginning of year 5,654,594 - ------------------------------------------------------------------------- Cash and cash equivalents, end of year - 5,654,594 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Supplemental information: Cash taxes paid - 89,858 Cash interest paid 411,271 298,851 ------------------------------------------------------------------------- ------------------------------------------------------------------------- See accompanying notes CINCH ENERGY CORP. NOTES TO FINANCIAL STATEMENTS December 31, 2006 and 2005 1. DESCRIPTION OF BUSINESS Cinch Energy Corp. (the "Company") was incorporated under the laws of the Province of Alberta and commenced operations on December 1, 2001. The Company's activities are comprised of the exploration for and development of oil and natural gas properties, primarily in Western Canada. 2. SIGNIFICANT ACCOUNTING POLICIES These financial statements, which have been prepared in accordance with Canadian generally accepted accounting principles, have in management's opinion, been properly prepared within reasonable limits of materiality and within the framework of the accounting policies summarized below. Cash and cash equivalents Term deposits with initial maturities less than three months are considered to be cash equivalents and are recorded at cost, which approximates market value. Property, Plant and Equipment Petroleum and natural gas properties The Company follows the full cost method of accounting for its petroleum and natural gas activities, whereby all costs associated with the exploration for and development of petroleum and natural gas reserves, whether productive or unproductive, are capitalized in a single Canadian cost center and charged to income as set out below. Such costs can include lease acquisition, drilling, geological and geophysical, and equipment costs, and overhead expenses directly related to exploration and development activities. Proceeds from disposal of properties will normally be applied as a reduction of the cost of the remaining assets, except when such a disposal would alter the depletion rate by more than 20 percent, in which case a gain or loss will be recorded. Ceiling test The net carrying value of the Company's petroleum and natural gas properties is limited to an ultimate recoverable amount. The Company tests impairment against undiscounted future net revenue from proved reserves using expected future prices and costs as well as the income tax legislation in effect at the period end. Impairment is recognized when the carrying value of the assets is greater than the undiscounted future net revenues, in which case the assets are written down to the fair value of proved plus probable reserves plus the cost of unproved properties, net of impairment allowances. Fair value is determined based on discounted future net cash flows calculated using expected future prices and costs as well as the income tax legislation in effect at the period end. The discount rate used is a risk free interest rate. Depletion Depletion of petroleum and natural gas properties and related production equipment is provided on accumulated costs using the unit of production method based on estimated proven petroleum and natural gas reserves, before royalties, as determined by independent engineers. For purposes of the depletion calculation, proven petroleum and natural gas reserves are converted to a common unit of measure on the basis that six thousand cubic feet of natural gas is equivalent to one barrel of petroleum. The depletion cost base includes total capitalized costs, less costs of unproven properties, plus for the estimated future development costs associated with proven undeveloped reserves. The carrying value of undeveloped properties is reviewed periodically. The excess of carrying value of undeveloped properties over their fair value is added to costs subject to depletion. Office furniture and equipment Office furniture and equipment is carried at cost and depreciated on a straight-line basis over the assets' estimated useful lives at a rate of 25% per annum. Goodwill Goodwill represents the excess purchase price over the fair value of identifiable assets and liabilities acquired in business combinations. Goodwill is subject to ongoing annual impairment reviews, or more frequent as economic events dictate, based on the fair value of the Company's assets. The fair value of the Company's assets is determined and compared to the book value of those assets. If the fair value of the assets is less than the book value, then a second test is performed to determine the amount of the impairment. The amount of the impairment is determined by deducting the fair value of the Company's individual assets and liabilities from the fair value of the total assets to determine the implied fair value of goodwill and comparing that amount to the book value of the Company's goodwill. Any excess of the book value over the implied value of goodwill is the impairment amount. Leases Leases are classified as either capital or operating in nature. Capital leases are those which transfer substantially all the benefits and risks of ownership to the lessee. Assets acquired under capital leases are depleted along with the petroleum and natural gas properties. Obligations recorded under capital leases are reduced by the principal portion of lease payments as incurred and the imputed interest portion of capital lease payments is charged to expense and amortized straight-line over the life of the lease. Operating lease payments are charged to expense. Asset Retirement Obligations The Company recognizes the fair value of a liability for an asset retirement obligation and a corresponding increase in the carrying value of the related long-lived asset in the period in which they are constructed or acquired. The fair value of the obligation is management's best estimate of the cost to retire the asset based on current legislation and industry practice. The increase in the carrying value of the asset is amortized on a unit of production basis consistent with the method used to record depletion on the Company's petroleum and natural gas properties. The liability is subsequently adjusted for the passage of time, which is recognized as accretion expense in the statement of operations and deficit. The liability is periodically adjusted for revisions in either the timing or the amount of the original estimated cash flows associated with the obligation. Any difference between the related costs incurred and the recorded liability is recorded as a gain or loss in the statements of operations in the period in which the settlement occurs. Measurement Uncertainty The amounts recorded for depletion and depreciation of petroleum and natural gas properties and other assets, the provision for asset retirement obligations, and the ceiling test calculation are based on estimates of proven or proven and probable reserves, production rates, petroleum and natural gas prices, future costs and other relevant assumptions. By their nature, these estimates are subject to measurement uncertainty and the effect on the financial statements of changes in such estimates in future periods could be significant. Joint Operations Substantially all of the Company's exploration and development activities are conducted jointly with others and accordingly the financial statements reflect only the Company's proportionate interest in such activities. Flow Through Shares The Company finances a portion of its exploration and development activities through the issuance of flow through shares. Under the terms of a flow through share issue, the tax attributes of the related expenditures are renounced to subscribers. To recognize the foregone tax benefits to the Company, share capital is reduced and future income taxes are increased by the tax effect of the tax benefits renounced to subscribers at the time the renouncement is filed with the tax authorities, provided there is reasonable assurance that the expenditures will be made. Income Taxes The Company follows the liability method of accounting for income taxes. Under this method, the Company records future income taxes for the difference between the financial statement carrying value and the income tax basis of an asset or liability. Future income tax assets and liabilities are measured using substantively enacted income tax rates and laws that are expected to apply in the periods in which differences are anticipated to reverse. The effect on future tax assets and liabilities of a change in tax rates is recognized in net loss in the period in which the change is substantively enacted. Revenue Recognition Revenues from the sale of petroleum and natural gas and related products are recognized when title passes. Stock Based Compensation The Company has a stock based compensation plan, which is described in note 10. The Company has adopted the fair value based method of accounting for stock options. Stock option expense is recorded as a general and administrative expense for all options granted on or after January 1, 2003, with a corresponding increase recorded to contributed surplus. The fair value of options granted is estimated at the date of grant using the Black-Scholes valuation model. Consideration paid by employees or directors on the exercise of stock options is credited to share capital. At the time of exercise, the related amounts previously credited to contributed surplus are also transferred to share capital. Per Share Information Per share information is calculated using the treasury stock method. Under this method, the diluted weighted average number of common shares is calculated assuming that the proceeds from the exercise of outstanding and in the money options is used to purchase common shares at the estimated average market price. 3. CASH AND CASH EQUIVALENTS As at December 31, 2006, the Company had drawn on its $33 million credit facility (see note 6) and, accordingly, had no cash and cash equivalents (December 31, 2005 - cash and cash equivalents included term deposits with maturities of 90 days or less of $4,980,000, which earned interest at 2.78%). 4. ACCOUNTS RECEIVABLE A substantial portion of the Company's accounts receivable is with oil and gas marketing entities. The Company generally extends unsecured credit to these companies, and therefore, the collection of accounts receivable may be affected by changes in economic or other conditions and may accordingly impact the Company's overall credit risk. Management believes the risk is mitigated by the size, reputation and diversified nature of the companies to which they extend credit. The Company has not previously experienced any material credit losses on the collection of receivables. Of the Company's significant individual accounts receivable at December 31, 2006, approximately 91% was owed from 6 customers (December 31, 2005 - 65% was owed from 7 customers). 5. PROPERTY, PLANT AND EQUIPMENT Property, plant and equipment December 31, 2006 ------------------------------------------------------------------------- Accumulated Net book Cost depreciation value $ $ $ ------------------------------------------------------------------------- Petroleum and natural gas properties 141,281,753 (29,905,549) 111,376,204 Equipment under capital lease 1,020,307 (188,179) 832,128 Office furniture and equipment 240,570 (147,481) 93,089 ------------------------------------------------------------------------- 142,542,630 (30,241,209) 112,301,421 ------------------------------------------------------------------------- ------------------------------------------------------------------------- December 31, 2005 ------------------------------------------------------------------------- Accumulated Net book Cost depreciation value $ $ $ ------------------------------------------------------------------------- Petroleum and natural gas properties 104,375,911 (19,153,951) 85,221,960 Equipment under capital lease 839,303 (95,777) 743,526 Office furniture and equipment 215,095 (94,664) 120,431 ------------------------------------------------------------------------- 105,430,309 (19,344,392) 86,085,917 ------------------------------------------------------------------------- ------------------------------------------------------------------------- For the years ended December 31, 2006 and 2005, no indirect general and administrative expenditures were capitalized. As at December 31, 2006, $10,900,069 of costs related to undeveloped lands were excluded from costs subject to depletion (December 31, 2005- $11,885,839). As at December 31, 2006, the depletion calculation included future development costs of $3,264,000 (December 31, 2005 - $3,241,000). Acquisition a) Effective August 4, 2005, the Company acquired all of the issued and outstanding common shares of and wound up 1008742 Alberta Ltd. into Cinch Energy Corp. The certificate of dissolution was received December 21, 2005. The total cash consideration of the purchase was $1.205 million which was allocated to petroleum and natural gas properties, future taxes and working capital. The acquisition was accounted for using the purchase method and therefore revenues and expenses from the acquired assets were included in the statements of operations and deficit from August 4, 2005. The purchase price was allocated as follows: ------------------------------------------------------------------------- $ Non-cash working capital 38,852 Land 1,421,639 Property, plant and equipment 93,648 Asset retirement obligation (6,678) Future taxes (342,707) ------------------------------------------------------------------------- Total purchase price 1,204,754 ------------------------------------------------------------------------- ------------------------------------------------------------------------- The Company has performed an impairment test as of December 31, 2006 using the estimated average price for each of the next five years as determined by the Company's independent reserve engineers adjusted for differentials specific to the Company's reserves as follows: Natural Gas Natural Gas Liquids Cdn $/mmbtu Cdn $/bbl ------------------------------------------------------------------------- 2007 7.00 71.75 2008 7.25 69.25 2009 7.55 67.00 2010 7.60 65.75 2011 7.65 65.75 ------------------------------------------------------------------------- Each benchmark price increased on average approximately 2% from 2012 and thereafter ------------------------------------------------------------------------- ------------------------------------------------------------------------- There was no impairment at December 31, 2006. 6. CREDIT FACILITY As at December 31, 2006, the Company had a demand, bank credit facility through ATB Financial of $33,000,000 (December 31, 2005 - $26,500,000). The facility bears interest at the lender's prime rate. The effective interest rate at December 31, 2006 was 6.09% (December 31, 2005 - 4.02%). As at December 31, 2006, there was $17,300,000 drawn on the credit facility (December 31, 2005 - nil). As collateral for the facility, the Company has provided a general security agreement with the lender constituting a first ranking security interest in all personal property and a first ranking floating charge on all real property of the Company subject only to a subordination agreement to another bank for the amount of, and as security for, a capital lease (see note 7). 7. CAPITAL LEASE OBLIGATION The Company is committed to annual minimum payments under a capital lease agreement which commenced in December, 2004, as follows: Years ending December 31, $ ------------------------------------------------------------------------- 2007 304,855 2008 304,855 ------------------------------------------------------------------------- Total minimum lease payments 609,710 Less amounts representing interest at 5.12% (57,115) ------------------------------------------------------------------------- Present value of minimum lease payments 552,595 Less current portion (275,789) ------------------------------------------------------------------------- Long term portion of capital lease obligation at December 31, 2006 276,806 ------------------------------------------------------------------------- ------------------------------------------------------------------------- For the year ended December 31, 2006, there was $27,339 (2005 - 22,274) recorded in interest expense relating to capital leases. A first charge on the Company's assets has been provided as security for the capital lease obligation. 8. ASSET RETIREMENT OBLIGATIONS The total future asset retirement obligations result from the Company's net ownership interest in wells and facilities. Management estimates the total undiscounted amount of future cash flows required to reclaim and abandon wells and facilities as at December 31, 2006 is approximately $5,300,000 to be incurred over the next 43 years (December 31, 2005 - $4,260,000). The Company used a credit adjusted, risk-free rate ranging from 5% to 7.5% and an inflation rate of 2% to arrive at the recorded liability of $2,934,899 at December 31, 2006 (December 31, 2005 - $2,725,627). The December 31, 2006 balance reflects adjustments recorded in 2006 to the estimated abandonment dates of some of the wells. The estimated dates were revised and extended to better reflect the economic life of the wells, effectively reducing the present value of the liability when compared to December 31, 2005, offset by the additions for the year ended December 31, 2006. The Company's asset retirement obligations changed as follows: December 31, December 31, 2006 2005 $ $ ------------------------------------------------------------------------- Asset retirement obligations, beginning of year 2,725,627 1,633,234 Adjustment to abandonment dates (304,622) 6,678 Liabilities incurred 451,235 927,866 Accretion expense 62,659 157,849 ------------------------------------------------------------------------- Asset retirement obligations, end of year 2,934,899 2,725,627 ------------------------------------------------------------------------- ------------------------------------------------------------------------- 9. FUTURE INCOME TAXES Income tax recovery differs from the amount that would be computed by applying the Federal and Provincial statutory income tax rates to loss before income taxes. The reasons for the differences are as follows: December 31, December 31, 2006 2005 $ $ ------------------------------------------------------------------------- Statutory income tax rate 34.49% 37.62% Anticipated income tax expense (recovery) (650,804) 1,945,506 Increase/(decrease) resulting from: Resource allowance (450,826) (1,406,352) Non-deductible crown royalties, net of ARTC 274,700 1,160,585 Non-deductible items - 5,512 Stock based compensation expense 308,274 208,364 Rate adjustment (1,051,744) (203,715) ------------------------------------------------------------------------- Future income tax expense (recovery) (1,570,400) 1,709,900 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Large corporations tax - 97,650 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1,570,400) 1,807,550 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Future income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts for income tax purposes. The components of the Company's future income tax assets and liabilities are as follows: December 31, December 31, 2006 2005 $ $ ------------------------------------------------------------------------- Net book value of capital assets in excess of tax pools (11,051,577) (9,663,114) Share issue costs 649,182 1,047,675 Asset retirement obligations 886,339 916,356 Other 105,446 52,323 ------------------------------------------------------------------------- Future income taxes (9,410,610) (7,646,760) ------------------------------------------------------------------------- ------------------------------------------------------------------------- 10. SHARE CAPITAL Authorized - Unlimited number of common voting shares without par value December 31, 2006 December 31, 2005 ------------------------------------------------------------------------- Issued Number $ Number $ ------------------------------------------------------------------------- Common shares Balance, beginning of year 47,757,632 93,010,709 33,104,316 51,568,073 Issued for cash on warrant exercise (i) - - 8,022,529 19,053,506 Issued for cash on flow through private placement (ii) - - 2,352,941 9,999,999 Issued for cash on private placement (ii) - - 3,676,472 12,500,005 Exercise and conversion of special warrants (iii) - - 257,600 238,759 Issued for cash on options exercise (iv) - - 100,334 188,126 Issued for cash on brokers' warrant exercise (v) - - 243,440 243,440 Reclassification on exercise of options (iv) - - - 56,473 Tax effect of flow through common share renunciation (ii) - (3,362,000) - - Issue costs, net of future taxes - (64,098) - (837,672) ------------------------------------------------------------------------- Balance, end of year 47,757,632 89,584,611 47,757,632 93,010,709 ------------------------------------------------------------------------- Special warrants Balance at beginning and end of year 55,000 33,935 55,000 33,935 ------------------------------------------------------------------------- Share capital, end of year 47,812,632 89,618,546 47,812,632 93,044,644 ------------------------------------------------------------------------- ------------------------------------------------------------------------- ------------------------------------------------------------------------- ------------------------------------------------------------------------- Contributed surplus Balance, beginning of year 1,250,842 753,449 Non cash compensation expense (iv) 893,807 553,866 Reclassification to share capital on exercise of options (iv) - (56,473) ------------------------------------------------------------------------- Contributed surplus, end of year 2,144,649 1,250,842 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Common Shares (i) Warrant exercise In 2005, a total of 8,022,529 common shares were issued pursuant to the exercise of warrants at an exercise price of $2.375, for gross proceeds of $19,053,506. (ii) Private Placement On September 8, 2005, the Company issued under private placement a total of 2,352,941 flow through common shares at $4.25 per share for proceeds of $9,999,999 and 3,676,472 common shares at $3.40 per share for proceeds of $12,500,005 before total issues costs of $1,203,880. The expenditures were renounced, in their entirety, in February, 2006 and the tax benefits thereon, in the amount of $3,362,000 was recorded on that date. (iii) Exercise of special warrants During the year ended December 31, 2005, special warrant holders exercised 257,600 special warrants in exchange for a total of 257,600 common shares for no additional cash consideration. (iv) Exercise of options During the year ended December 31, 2005, a total of 100,334 common shares were issued on exercise of stock options at an average exercise price of $1.875. As a result, stock compensation expense of $56,473 previously recognized for these options was reclassified from contributed surplus to common shares. The non-cash compensation expense is comprised of the stock option benefit for all outstanding options. (v) Brokers' warrant exercise During the year ended December 31, 2005, a total 243,440 common shares were issued pursuant to the exercise of brokers' warrants at an exercise price of $1.00. There are no brokers' warrants outstanding. Per share amounts Per share amounts have been calculated using the weighted average number of common shares and special warrants outstanding during the year of 47,812,632 (2005 - 40,046,588). As at December 31, 2006, the options are anti-dilutive and therefore the diluted per share amount is not presented based on the diluted weighted average number of common shares outstanding of 49,187,756. (December 31, 2005 - the diluted weighted average number of common shares outstanding was 41,921,643 and the diluted per share amounts were calculated assuming the exercise of outstanding, in-the- money options, and future compensation costs to be incurred on outstanding options). For the year ended December 31, 2006, per share calculations are anti-dilutive and are not presented based on outstanding, out-of-the-money options (December 31, 2005 - 125,000 options). Stock option plan The Company has a stock option plan authorizing the grant of options to purchase shares to designated participants, being directors, officers, employees or consultants. Under the terms of the plan, the Company may grant options to purchase shares equal to a maximum of ten percent of the total issued and outstanding shares and special warrants of the Company. The aggregate number of options that may be granted to any one individual must not exceed five percent of the total issued and outstanding shares and special warrants. Options are granted at exercise prices equal to the estimated fair value of the shares at the date of grant and may not exceed a ten year term. The vesting for options granted occurs over a three year period, with one third of the number granted vesting on each of the first, second, and third anniversary dates of the grant unless otherwise specified by the Board of Directors at the time of grant. The following is a continuity of stock options for which shares have been reserved: 2006 2005 Weighted Weighted Average Average Number of Exercise Number of Exercise Options Price Options Price ------------------------------------------------------------------------- $ $ Stock options outstanding, beginning of year 2,328,000 2.17 1,635,000 1.88 Granted 2,141,000 1.75 1,065,000 2.55 Exercised - - (100,334) 1.88 Cancelled/Expired (397,666) 2.11 (271,666) 2.00 ------------------------------------------------------------------------- Stock options outstanding, end of year 4,071,334 1.96 2,328,000 2.17 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Stock options outstanding at the end of the year are comprised of the following: December 31, 2006 December 31, 2005 ------------------------------------------------------------------------- Number of Number of Exercise Number of exercisable Exercise Number of exercisable Price Options options Price Options options ------------------------------------------------------------------------- $ $ 1.24-1.50 895,000 - 1.24-1.50 - - 1.51-2.00 1,338,000 888,998 1.51-2.00 1,308,000 610,666 2.01-2.50 1,125,000 81,666 2.01-2.50 265,000 20,000 2.51-3.00 588,334 184,999 2.51-3.00 630,000 - 3.01-3.50 125,000 41,667 3.01-3.50 125,000 - ------------------------------------------------------------------------- 1.96 4,071,334 1,197,330 2.17 2,328,000 630,666 ------------------------------------------------------------------------- ------------------------------------------------------------------------- The options outstanding at December 31, 2006 have a weighted average remaining contractual life of 3.6 years (December 31, 2005 - 3.7 years). The fair value of stock options granted to employees, directors and consultants during the year ended December 31, 2006 and 2005, was estimated on the date of grant using the Black Scholes option pricing model with the following weighted average assumptions: dividend yield of zero percent (2005 - zero percent), expected volatility of 47.95 percent (2005 - 34.62 percent), risk-free interest rate of 3.95 percent (2005 - 3.43 percent), and an expected life of four years (2005 - four years). Outstanding options granted during the year ended December 31, 2006 had an estimated weighted average fair value of $0.73 per option (December 31, 2005 - $0.83 per option), for a total estimated value of $1,556,600 (2005 - $827,890). For the year ending December 31, 2006, a total of $893,807 (2005 - $553,866) has been recognized as stock compensation expense in general and administrative expenses with an offsetting credit to contributed surplus. 11. COMMITMENTS The Company has entered into an operating lease for office premises expiring on November 20, 2009, which requires minimum monthly payments of $14,520 for the remainder of the lease. The Company has entered into a capital lease obligation, as more fully described in note 7. 12. FINANCIAL INSTRUMENTS Fair value of financial instruments Financial instruments recognized on the balance sheet consist of cash and cash equivalents, accounts receivable, deposits, accounts payable, credit facility and capital lease obligation. As at December 31, 2006 and 2005, there were no significant differences between the carrying amounts of these financial instruments reported on the balance sheet and their estimated fair values. It is management's opinion that the Company is not exposed to significant credit risk. Interest rate risk The Company is exposed to interest rate risk relating to increases in interest rates on its variable rate credit facility. Commodity price risk management As at December 31, 2006, the Company had no fixed price contracts associated with future production. 13. BASIS OF PRESENTATION Certain of the comparative figures have been reclassified to conform to the presentation adopted in the current year. 14. SUBSEQUENT EVENT On February 21, 2007, the Company issued 7,812,500 common shares on a flow through basis at a price of $1.28 per share for gross proceeds of $10,000,000.

For further information:

For further information: John W. Elick, Chief Executive Officer, Tel:
(403) 693-0090, elickj@cinchenergy.com; George Ongyerth, President, Tel: (403)
693-0090, ongyerthg@cinchenergy.com; Or visit our website at
www.cinchenergy.com

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CINCH ENERGY CORP.

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