/C O R R E C T I O N from Source -- Cinch Energy Corp. - President's Message/



    Cinch Energy Corp. releases second quarter 2007 results and current
    operations update

    CALGARY, Aug. 8 /CNW/ - Cinch Energy Corp ("Cinch" or "the Company") is
pleased to report on the Company's activities and financial results for the
second quarter of 2007. Highlights are as follows:

    
    -------------------------------------------------------------------------
                                  Three Months Ended        Six Months Ended
                                             June 30,                June 30,
                                    2007        2006        2007        2006
    -------------------------------------------------------------------------
                              (Unaudited) (Unaudited) (Unaudited) (Unaudited)

    Oil and gas sales, net
     of transportation ($000's)    5,582       4,692      11,698       9,892

    Sales volumes per day
    Natural gas (Mcf/d)            6,157       5,723       6,472       5,685
    Natural gas liquids (Bbl/d)      223         187         222         188
    Equivalence at 6:1 (BOE/d)     1,249       1,141       1,301       1,136

    Sales Price
    Natural gas ($/Mcf)             7.75        6.64        7.90        7.42
    Natural gas liquids ($/Bbl)    61.15       72.30       60.84       66.25
    Equivalence at 6:1 ($/BOE)     49.11       45.19       49.68       48.12

                                       $           $           $           $
    Funds from operations
     (000's)(1)                    2,589       2,406       5,960       4,881
      - per share, basic(1)         0.05        0.05        0.11        0.10
      - per share, diluted(1)       0.05        0.05        0.11        0.10
    Net income (loss) (000's)       (709)        879        (978)        748
      - per share, basic           (0.01)       0.02       (0.02)       0.02
      - per share, diluted         (0.01)       0.02       (0.02)       0.02

    Capital expenditures ($000's)  3,930      13,542      10,158      20,238

    Basic weighted average
     shares and special
     warrants outstanding
     (000's)                      55,570      47,813      53,326      47,813
    Working capital
     (net debt)(2) ($000's)                                    $
      - As at June 30, 2007                              (18,673)
      - As at December 31, 2006                          (23,745)

                                            As at August 3, 2007

    Common shares outstanding                         55,625,132
    Options outstanding                                5,110,500
    - Weighted average exercise price                       1.76
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Funds from operations and funds from operations per share is not a
        generally accepted accounting principle ("GAAP") 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.
    



    President's Message


    PRODUCTION, PRICES, AND COSTS

    For the six months ended June 30, 2007, Cinch's production averaged
1,301 BOE/d versus an average of 1,136 BOE/d in the first six months of 2006
and 1,249 BOE/d in the second quarter of 2007. The increase over 2006 is
attributable to new production adds in the Chime, Kakwa, and the Resthaven
areas. Production in the Bigstone area continued to be curtailed since
March 2007, however additional firm processing capacity has now been made
available by the operator commencing in August, which should alleviate the
restrictions. The Company anticipates that production in the second half of
2007 should increase as new wells are brought on stream in Musreau, Kakwa,
Chime, and Dawson.
    Prices for the first six months of 2007 averaged $49.68 per BOE, which is
up slightly from the 2006 first half average of $48.12 per BOE. The price
received in the second quarter of 2007 decreased slightly from the first
quarter to $49.11 per BOE. Natural gas prices in the third quarter of 2007
have softened considerably as storage remains fairly full in comparison to
prior years, however oil prices and natural gas liquids prices continue to
strengthen under current market conditions. The company does not have any
hedges in place and remains positive about the future natural gas market.
    Operating costs in the first half of 2007 were $6.24 per BOE, as compared
to $7.37 per BOE in the comparable period of 2007, and down slightly from
$6.30 per BOE in the second quarter of 2007. These decreases in operating
costs are primarily due to additional production volumes coming on stream.

    OPERATIONS

    During the second quarter, Cinch operated the drilling of one well at
Chime, Alberta.
    At Chime, the Company drilled and cased subsequent to quarter end the
Chime 9-36 well as a potential gas well. Cinch has a 45% working interest in
this well, and has commenced completion operations in three zones, which is
expected to take approximately three weeks. A number of follow up locations
have been identified and have been surveyed in preparation for future
development drilling, which is dependent upon completion results and also
securing partner participation.
    In the Musreau area, the Company participated in the recompletion
operations of Musreau 14-7. The Musreau 14-7 well, in which Cinch has a 50%
working interest, was completed as a dual zone gas well and is expected to
commence production in early September at a rate of 600 mcf/d.
    At Wilder, British Columbia, Cinch had operated the drilling of the
Wilder 11-36 well and also the completion of the Wilder A06-5 well in the
first quarter. Results from the drilling and completion operations were
evaluated in the second quarter and resulted in uneconomic gas rates and the
Company has now elected to abandoned the Wilder 11-36 well and not proceed
with the drilling option.
    At Kakwa, Cinch has drilled the Kakwa 10-18 infill Dunvegan location in
which it has a 100% working interest, and cased this well as a potential gas
well. This well is expected to commence production in September. The Company
is also participating for its 12.5% working interest in the Kakwa 14-23 well
which has commenced drilling.
    At Kakwa East, the tie in operations of the Kakwa 15-12 oil discovery has
now been delayed until January of 2008, which is anticipated to significantly
reduce the Company's share of tie in costs, as the length of the pipeline will
be reduced and costs will now be shared with offsetting operators. This will
also delay the drilling of two budgeted development wells into the 2008 year.
    At Dawson, B.C., the Doe 1-32 Kiskatinaw test, in which the Company has a
36% working interest, has been cased as a potential gas well. A number of
potential development locations have been identified on this prospect.
    The Company is currently estimating that its capital program will total
approximately $27 million, down from the previous forecast of $30 million.
Industry partners remain uncertain on natural gas prices and costs and
therefore previous projected drilling plans have been delayed until the
economic climate for natural gas improves. The Company has plans for 5 more
wells prior to year end in its core area.
    With the current drilling results, the Company remains confident that its
projected 1900 BOE/d exit rate will be achieved.

    George Ongyerth
    President


    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, anticipated commodity
prices, timing of expenditures and renunciation of flow-through expenditures,
budgeted capital expenditures and the method of funding thereof, partner risk,
expected royalty rates and operating expenses, drilling, completion and tie-in
plans 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,
volatility of commodity prices, imprecision of reserve estimates,
environmental risks, competition from other producers, 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 and changes in the regulatory and taxation
environment. 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.

    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.


    MANAGEMENT'S DISCUSSION AND ANALYSIS
    August 3, 2007

    The following management's discussion and analysis ("MD&A") should be
read in conjunction with the unaudited interim financial statements and
related notes for the three and six month periods ended June 30, 2007 and the
audited financial statements and related management discussion and analysis of
Cinch Energy Corp. ("Cinch" or the "Company") for the year ended December 31,
2006. Additional information relating to Cinch, including Cinc

    PRODUCTION, PRICES, AND COSTS

    For the six months ended June 30, 2007, Cinch's production averaged 1,301
BOE/d versus an average of 1,136 BOE/d in the first six months of 2006 and
1,249 BOE/d in the second quarter of 2007.  The increase over 2006 is
attributable to new production adds in the Chime, Kakwa, and the Resthaven
areas.  Production in the Bigstone area continued to be curtailed since March
2007, however additional firm processing capacity has now been made available
by the operator commencing in August, which should alleviate the restrictions.
 The Company anticipates that production in the second half of 2007 should
increase as new wells are brought on stream in Musreau, Kakwa, Chime, and
Dawson West.

    Prices for the first six months of 2007 averaged $49.68 per BOE, which is
up slightly from the 2006 first half average of $48.12 per BOE.  The price
received in the second quarter of 2007 decreased slightly from the first
quarter to $49.11 per BOE.  Natural gas prices in the third quarter of 2007
have softened considerably as storage remains fairly full in comparison to
prior years, however oil prices and natural gas liquids prices continue to
strengthen under current market conditions.  The company does not have any
hedges in place and remains positive about the future natural gas market.

    Operating costs in the first half of 2007 were $6.24 per BOE, as compared
to $7.37 per BOE in the comparable period of 2007, and down slightly from
$6.30 per BOE in the second quarter of 2007.  These decreases in operating
costs are primarily due to additional production volumes coming on stream.

    OPERATIONS

    During the second quarter, Cinch operated the drilling of one well at
Chime, Alberta.

    At Chime, the Company drilled and cased subsequent to quarter end the
Chime 9-36 well as a potential gas well.   Cinch has a 45% working interest in
this well, and has commenced completion operations in three zones, which is
expected to take approximately three weeks.  A number of follow up locations
have been identified and have been surveyed in preparation for future
development drilling, which is dependent upon completion results and also
securing partner participation.

    In the Musreau area, the Company participated in the recompletion
operations of Musreau 14-7 The Musreau 14-7 well, in which Cinch has a 50%
working interest, was completed as a dual zone gas well and is expected to
commence production in early September at a rate of 600 mcf/d.


    At Wilder, British Columbia, Cinch had operated the drilling of the
Wilder 11-36 well and also the completion of the Wilder A06-5 well in the
first quarter.  Results from the drilling and completion operations were
evaluated in the second quarter and resulted in uneconomic gas rates and the
Company has now elected to abandoned the Wilder 11-36 well and not proceed
with the drilling option.



    At Kakwa, Cinch has drilled the Kakwa 10-18 infill Dunvegan location in
which it has a 100% working interest, and cased this well as a potential gas
well.  This well is expected to commence production in September.  The Company
is also participating for its 12.5% working interest in the Kakwa 14-23 well
which has commenced drilling.

    At Kakwa East, the tie in operations of the Kakwa 15-12 oil discovery has
now been delayed until January of 2008 which is anticipated to significantly
reduce the Company's share of tie in costs, as the length of the pipeline will
be reduced and costs will now be shared with offsetting operators.  This will
also delay the drilling of two budgeted development wells into the 2008 year.

    At Dawson, B.C., the Doe 1-32 Kiskatinaw test, in which the Company has a
36% working interest, has been cased as a potential gas well.  A number of
potential development locations have been identified on this prospect.

    The Company is currently estimating that its capital program will total
approximately $27 million, down from the previous forecast of $30 million. 
Industry partners remain uncertain on natural gas prices and costs and
therefore previous projected drilling plans have been delayed until the
economic climate for natural gas improves.  The Company has plans for 5 more
wells prior to year end in its core area.

    With the current drilling results, the Company remains confident that its
projected 1900 BOE/d exit rate will be achieved.


    George Ongyerth
    President h's Annual Information Form, is available 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 production for the second quarter of 2007 was approximately
1,249 BOE/d, resulting in an average of 1,301 BOE/d for the first six months
of 2007, an increase of 165 BOE/d over the same period of 2006. The decrease
in production from the first quarter of 2007 is due to additional production
of approximately 70 BOE/d being shut-in due to plant capacity issues. There
were also declines in production from 3 wells that came on production late in
2006, producing at rates of approximately 60 BOE/d lower in the second quarter
of 2007 compared to the first quarter. These reductions were partially offset
by production from a well at Resthaven, which increased by approximately
40 BOE/d over the first quarter as a result of having less down-time in the
quarter.
    Due to an extended spring break up, the Company re-commenced drilling
activities in June with the Cutpick 9-36 well. The Wilder test well, which had
been drilled late in the first quarter, was assessed in the second quarter as
uneconomic.
    The Company incurred $3.9 million of capital expenditures in the three
months ended June 30, 2007, of which $2.0 million was incurred on an
acquisition and the balance on drilling, completion and seismic expenditures,
primarily in June. The acquisition, in the Company's core Chime area,
consolidated additional land interests and additional working interests in two
producing wells, as well as eliminated a gross overriding royalty effective
June 20, 2007.
    In the third quarter of 2007, the Company plans to drill, complete and
tie-in multiple locations primarily in the Chime, Kakwa and Dawson areas,
including the Cutpick 9-36 well.
    The Company's funds from operations and funds from operations per share
for the first six months of 2007 exceeded that of the same period of 2006, as
a result of the higher production and higher prices.

    PRODUCTION

    
    -------------------------------------------------------------------------
                       Three Months Ended June 30,  Six Months Ended June 30,
                           2007     2006   Change     2007     2006   Change
    -------------------------------------------------------------------------
    Sales volumes                               %                          %
    Natural gas (mcf/d)   6,157    5,723        8    6,472    5,685       14
    Liquids (bbl/d)         223      187       19      222      182       18
    Equivalence (BOE/d)   1,249    1,141        9    1,301    1,136       15

    Sales prices              $        $        %        $        $        %
    Natural gas            7.75     6.64       17     7.90     7.42        6
    Liquids               61.15    72.30      (15)   60.84    66.25       (8)
    Equivalence           49.11    45.19        9    49.68    48.12        3
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Sales volumes for the three and six months ended June 30, 2007, increased
over the same periods of 2006 due to six additional wells brought on
production since June 2006, partially offset by declines. The most significant
well, which commenced production subsequent to June 30, 2006, was the
Resthaven 9-25 well, averaging approximately 180 BOE/d and 160 BOE/d for the
three and six months ended June 30, 2007, respectively.
    Natural gas prices were 17% higher and 6% higher for the three and six
months ended June 30, 2007, respectively, compared to the same periods of
2006. Natural gas prices for the three months ended June 30, 2007 were 3%
lower than the first quarter of 2007. Natural gas pricing continued to weaken
subsequent to the quarter end. The Company's natural gas production continues
to be unhedged and is marketed in the Alberta spot market.
    Natural gas liquids pricing was 15% lower and 8% lower for the three and
six months ended June 30, 2007, respectively, compared to the same periods of
2006. Natural gas liquids pricing was 1% higher in the second quarter compared
to the first quarter of 2007. Natural gas liquids represent approximately 18%
of the Company's oil and gas production. The Company has not hedged any of its
liquids production.

    REVENUES

    
    Dollars in thousands, except per unit amounts
    -------------------------------------------------------------------------
                       Three Months Ended June 30,  Six Months Ended June 30,
                           2007     2006   Change     2007     2006   Change
    -------------------------------------------------------------------------
                              $        $        %        $        $        %

    Oil and gas sales,
     net of
     transportation       5,582    4,692       19   11,698    9,892       18
    Per BOE               49.11    45.19        9    49.68    48.12        3
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Revenues for the three and six months ended June 30, 2007 were 19% and
18% higher, respectively, than the same periods of 2006 due to higher
production as well as higher natural gas prices partially offset by lower
natural gas liquids prices, as previously discussed. Transportation expenses
increased by approximately $0.28 per BOE in the first six months of 2007
compared to the same period of 2006 as a result of rate increases.
    Revenues for the three months ended June 30, 2007 have decreased from the
first quarter of 2007, as a result of lower production as well as lower
natural gas prices.

    ROYALTIES

    
    Dollars in thousands, except per unit amounts
    -------------------------------------------------------------------------
                       Three Months Ended June 30,  Six Months Ended June 30,
                           2007     2006   Change     2007     2006   Change
    -------------------------------------------------------------------------
                              $        $        %        $        $        %

    Royalties, net of
     ARTC                 1,397      744       88    2,396    2,037       18
    Per BOE               12.30     7.16       72    10.18     9.91        3
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Royalty expense increased in the three and six months ended June 30, 2007
compared to the same periods of 2006 due to the elimination of the Alberta
royalty tax credit effective January 1, 2007. The benefit received for the
three and six months ended June 30, 2006 was $160 thousand and $500 thousand,
respectively, which directly offset crown royalty expense in 2006. The royalty
expense is also higher in 2007 because oil and gas sales are higher and
because of the expiration of royalty holidays.
    Royalty expense for the second quarter of 2007 increased over the first
quarter of 2007 due to the exhaustion of royalty holidays on two of the
Company's more significant producing wells. The royalty rate for the remainder
of 2007 (royalties as a percentage of oil and gas sales), is not expected to
change substantially from the royalty rate experienced in the second quarter.
Royalty rates can vary from expectations, however, 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 June 30,  Six Months Ended June 30,
                           2007     2006   Change     2007     2006   Change
    -------------------------------------------------------------------------
                              $        $        %        $        $        %

    Operating               716      750       (5)   1,469    1,515       (3)
    Per BOE                6.30     7.22      (13)    6.24     7.37      (15)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Total operating expenses for the three and six months ended June 30, 2007
were slightly lower than operating expenses for the same periods of 2006.
Operating expenses per BOE decreased compared to the same periods of 2006 due
to slightly lower operating expenses over higher production.
    Total operating expenses for the second quarter of 2007 were slightly
lower than the first quarter of 2007, with decreases in gas gathering and
processing fees due to lower production, as well as decreased compressor
maintenance and repairs and contractor services, partially offset by increased
EUB administrative charges, property taxes and chemical treating costs.
Operating expenses per BOE are slightly higher than those experienced in the
first quarter of 2007 at $6.18/BOE due to lower production levels in the
second quarter.
    Operating expenses are not expected to exceed $6.50 per BOE in 2007. 
Anticipated costs per BOE can change, however, depending on the Company's
actual production levels.

    GENERAL AND ADMINISTRATIVE EXPENSES

    
    Dollars in thousands, except per unit amounts
    -------------------------------------------------------------------------
                       Three Months Ended June 30,  Six Months Ended June 30,
                           2007     2006   Change     2007     2006   Change
    -------------------------------------------------------------------------
                              $        $        %        $        $        %

    General and
     administrative         950      995       (5)   2,021    1,857        9
    Per BOE                8.36     9.59      (13)    8.58     9.03       (5)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Total general and administrative expenses decreased for the three months
ended June 30, 2007 compared to the same period of 2006 due to decreased
contractor and consultant fees, as well as lower expenses relating to
corporate governance. Overhead recoveries were also higher due to a change in
the mix of operated versus non-operated activities. The decreases are
partially offset by a slight increase in salaries and related compensation
($30 thousand). The Company does not capitalize indirect general and
administrative expenses. General and administrative expenses per BOE were
lower in the second quarter of 2007 compared to the prior year due to lower
general and administrative expenses over higher production in 2007.
    Total general and administrative expenses for the six months ended
June 30, 2007 increased over the same period of 2006 due to increased salaries
and related compensation. This amount includes an increase in non-cash stock
based compensation expense of $110 thousand, attributable to a greater number
of stock options outstanding (5,110,500 options at June 30, 2007 compared to
3,364,000 options at June 30, 2006). Overhead recoveries were also
$32 thousand lower in 2007 due to reduced operated activity from 2006.
    Total general and administrative expenses decreased approximately
$121 thousand in the second quarter of 2007 compared to the first quarter of
2007 mostly due to increased overhead recoveries ($45k), as well as lower
stock based compensation expense. General and administrative expenses per BOE
were lower in the second quarter of 2007 compared to the first quarter at
$8.79/BOE due to lower expenses partially offset by lower production in the
second quarter.

    INTEREST EXPENSE

    
    Dollars in thousands, except per unit amounts
    -------------------------------------------------------------------------
                       Three Months Ended June 30,  Six Months Ended June 30,
                           2007     2006   Change     2007     2006   Change
    -------------------------------------------------------------------------
                              $        $        %        $        $        %

    Interest expense        196      133       47      426      138      209
    Per BOE                1.73     1.28       35     1.81     0.67      170
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Interest expense increased in the three and six months ended June 30,
2007 compared to the same periods of 2006 due to higher draws on the Company's
bank credit facility in 2007, exiting the quarter with an outstanding credit
facility balance of $14.2 million. In 2006, the Company did not draw on its
operating line until April 2006 and exited the quarter with an amount
outstanding under its credit facility of $6.4 million.

    ACCRETION OF ASSET RETIREMENT OBLIGATIONS EXPENSE

    
    Dollars in thousands, except per unit amounts
    -------------------------------------------------------------------------
                       Three Months Ended June 30,  Six Months Ended June 30,
                           2007     2006   Change     2007     2006   Change
    -------------------------------------------------------------------------
                              $        $        %        $        $        %

    Accretion expense        44       19      132       85       28      204
    Per BOE                0.39     0.18      117     0.36     0.14      157
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Accretion expense increased in the three and six months ended June 30,
2007 compared to the same periods of 2006 due to an increase in the number of
wells with asset retirement obligations as a result of drilling operations and
due to an increase in the Company's estimate of the risk-free interest rate on
which the liability is accreted.

    DEPLETION AND DEPRECIATION EXPENSE

    
    Dollars in thousands, except per unit amounts
    -------------------------------------------------------------------------
                       Three Months Ended June 30,  Six Months Ended June 30,
                           2007     2006   Change     2007     2006   Change
    -------------------------------------------------------------------------
                              $        $        %        $        $        %

    Depletion and
     depreciation         3,189    2,490       28    6,495    4,996       30
    Per BOE               28.05    23.98       17    27.58    24.31       13
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Total depletion and depreciation expense as well as depletion per BOE for
the three and six months ended June 30, 2007 increased compared to the same
periods of 2006 due to a larger capital asset balance being depleted,
partially offset by reserve additions since June 30, 2006. The Company has
internally assessed reserve additions to June 30, 2007 and, given the capital
expended, this has resulted in a higher depletion rate in the six months ended
June 30, 2007 at $27.58 versus the fourth quarter of 2006 at $26.71. The
variance is largely attributable to the $2.6 million Wilder exploration test
in British Columbia, which was unsuccessful and resulted in no reserve
additions.

    TAXES

    
    Dollars in thousands, except per unit amounts
    -------------------------------------------------------------------------
                       Three Months Ended June 30,  Six Months Ended June 30,
                           2007     2006   Change     2007     2006   Change
    -------------------------------------------------------------------------
                              $        $        %        $        $        %

    Current                   -      (20)    (100)       -        -        -
    Future income tax
     recoveries            (192)  (1,239)     (85)    (183)  (1,320)     (86)
    Per BOE               (1.69)  (12.13)     (86)   (0.78)   (6.42)     (88)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    There was no large corporations tax paid in the three months ended
June 30, 2007, consistent with the elimination of the large corporations tax
effective January 1, 2006, which became law on June 22, 2006. The second
quarter of 2006 reflected a reversal of large corporations taxes previously
recorded after the legislation eliminating the tax became law.
    A future income tax recovery was recorded in the second quarter of 2007
because the Company experienced a net loss. Stock compensation expense
recorded in the quarter is not included in calculating the future tax recovery
as this expense is non-taxable. The second quarter of 2006 was also impacted
by stock compensation expense, and by the partial non-deductibility of crown
charges, elimination of Alberta Royalty Tax Credit and the resource allowance
deduction. All of the latter three items are no longer a consideration in
federal tax calculations for 2007 and future years, as a result of amendments
to the Income Tax Act. Also, in the second quarter of 2006, the future tax
liability previously recognized by the Company was recalculated to reflect
lower tax rates as legislated by the federal government on June 22, 2006 and
the difference between the original estimate of the future tax liability and
the adjusted estimate at lower tax rates resulted in a large future tax
recovery being recorded in the quarter.

    Tax pools at June 30:

    
    In thousands
    -------------------------------------------------------------------------
                                                           2007         2006
                                                              $            $
    -------------------------------------------------------------------------
    COGPE                                                13,773       12,220
    CDE                                                  21,101       19,006
    CEE                                                  25,471       12,185
    UCC                                                  19,840       19,842
    -------------------------------------------------------------------------
                                                         80,185       63,253
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    The Company's tax pools increased by 26% since June 30, 2006 as a result
of capital expenditures which were higher than the tax pools needed to
eliminate taxable income. On February 21, 2007, the Company completed an
equity financing for gross proceeds of $10 million, issuing 7,812,500 common
shares on a flow through basis at $1.28 per share. The Company will renounce
$10 million of Canadian exploration expenditures to the flow through investors
effective December 31, 2007. The Company anticipates no difficulties in
meeting this obligation.

    NET INCOME (LOSS) AND FUNDS FROM OPERATIONS

    
    In thousands, except per share figures
    -------------------------------------------------------------------------
                       Three Months Ended June 30,  Six Months Ended June 30,
                           2007     2006   Change     2007     2006   Change
    -------------------------------------------------------------------------
                              $        $        %        $        $        %

    Net income (loss)      (709)     879     (181)    (978)     748     (231)
      per basic share     (0.01)    0.02     (150)   (0.02)    0.02     (200)
      per diluted share   (0.01)    0.02     (150)   (0.02)    0.02     (200)
    Funds from
     operations           2,589    2,406        8    5,960    4,881       22
      per basic share      0.06     0.05       20     0.11     0.10        8
      per diluted share    0.06     0.05       20     0.11     0.10       11
    Weighted average
     shares & special
     warrants
     outstanding         55,570   47,813       12   53,326   47,813       12
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    For the three and six months ended June 30, 2007, the Company incurred a
net loss, attributable to higher royalties, as well as higher depletion and
depreciation and interest expense partially offset by higher revenues and
lower operating expenses.
    The Company's funds from operations increased by 8% and 22% over the
three and six months ended June 30, 2006, respectively. Funds from operations
in 2007 are higher primarily due to increased revenues from higher production
levels.

    LIQUIDITY AND CAPITAL RE

SOURCES In thousands ------------------------------------------------------------------------- June 30, December 31, 2007 2006 Change ------------------------------------------------------------------------- $ $ % Working capital (deficiency) 4,496 6,441 (30) Credit facility 14,177 17,304 (18) ------------------------------------------------------------------------- Net debt 18,673 23,745 (21) Long-term capital lease obligation 139 277 (50) Shareholders' equity 99,700 90,551 10 ------------------------------------------------------------------------- ------------------------------------------------------------------------- At June 30, 2007, the Company had net debt of $18.7 million, comprised of a working capital deficiency of $4.5 million and an amount outstanding on its credit facility of $14.2 million. The $5.1 million reduction in net debt from December 31, 2006 can be attributed to proceeds of $9.4 million, net of issue costs, received from a flow through financing completed on February 21, 2007 and funds from operations for the six months ended June 30, 2007 of $5.9 million, partially offset by capital expenditures incurred in the first half of 2007 of $10.2 million. Management currently intends to fund the remainder of its 2007 capital program with a combination of funds generated from operations and its bank credit facility. Management monitors and updates its forecast to incorporate changes in capital, actual results and in commodity market pricing, and despite the weakness in natural gas pricing, has forecast that it has sufficient access to capital to carry out the planned 2007 program. The Company has reduced its previous capital forecast of $30 million to $27 million in consideration of the lower natural gas prices. At June 30, 2007, the Company had draws of $14.2 million on its $33.0 million demand bank credit facility, which was renewed during the second quarter with no changes in the facility terms. The increase in shareholders' equity at June 30, 2007 from December 31, 2006 is due to the financing completed in February 2007, as previously discussed. CAPITAL EXPENDITURES Additions to property, plant and equipment In thousands ------------------------------------------------------------------------- Six months ended June 30, 2007 2006 ------------------------------------------------------------------------- $ $ Land and rentals 1,964 5,315 Seismic 267 608 Drilling, completing and equipping 6,847 10,336 Pipelines and facilities 992 3,852 Other assets 88 127 ------------------------------------------------------------------------- Total 10,158 20,238 ------------------------------------------------------------------------- ------------------------------------------------------------------------- The capital additions for the six months ended June 30, 2007 include approximately $2.0 million for an acquisition which consolidated additional land interests and eliminated a gross overriding royalty effective June 20, 2007. The remainder of the capital expenditures were incurred primarily on drilling and completing locations in the Kakwa East, Wilder, Musreau and Chime areas. As previously mentioned, a total of $2.6 million was expended on the Wilder test, a new prospect in British Columbia, however this did not prove successful. Additional reserves were added through drilling and completion operations at the Musreau and Kakwa East areas. The Chime (Cutpick 9-36-60-06W6) location was in progress at the end of the quarter. Subsequent to quarter end, the Company cased the Cutpick 9-36 well, in which it has a 45% working interest, and the well is currently being evaluated for a multiple zone completion. Currently, the Company has three wells at various stages of drilling and completion. 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. 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 operational 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. 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. On February 16, 2007, the Alberta Government announced that a review of the province's royalty and tax regime pertaining to oil and gas resources, including oil sands, conventional oil and gas and coalbed methane, will be conducted by a panel of experts, with the assistance of individual Albertans and key stakeholders. The review panel is to produce a final report that will be presented to the Minister of Finance by August 31, 2007. 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. On March 8, 2007, the Alberta Government introduced Bill 3, the Climate Change and Emissions Management Amendment Act, which intends to reduce greenhouse gas emission intensity from large industries. On April 26, 2007, the Federal Government released its Action Plan to Reduce Greenhouse Gases and Air Pollution (the "Action Plan"), also known as ecoACTION which includes the Regulatory Framework for Air Emissions. This Action Plan covers not only large industry, but regulates the fuel efficiency of vehicles and the strengthening of energy standards for a number of energy-using products. Given the evolving nature of the debate related to climate change and the control of greenhouse gases and resulting requirements, it is not currently possible to predict either the nature of those requirements or the impact on the Company and its operations and financial condition. 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. 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 for the Company in order to provide reasonable assurance regarding the reliability of the Company's financial statements 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 June 30, 2007, that have materially affected, or are reasonably likely to affect, the Company's design of the internal controls over financial reporting. 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 (less (greater than) than) Total 1 year 1-3 years 4-5 years 5 years ------------------------------------------------------------------------- Capital lease obligation 415 276 139 - - Operating lease 421 174 247 - - ------------------------------------------------------------------------- 836 450 386 - - ------------------------------------------------------------------------- ------------------------------------------------------------------------- On February 21, 2007, the Company issued 7,812,500 flow through common shares for gross proceeds of $10 million. The Company will renounce $10 million of Canadian exploration expenditures to the flow through investors effective December 31, 2007 and is required to incur such expenditures on or before December 31, 2008. Management does not anticipate any difficulties in meeting this obligation. CHANGES IN ACCOUNTING POLICIES Effective January 1, 2007, the Company adopted the CICA Handbook Section 3855 "Financial Instruments - Recognition and Measurement", Section 3861 "Financial Instruments - Disclosure and Presentation", Section 3865 "Hedges", Section 1506 "Accounting Changes", Section 1530 "Comprehensive Income" and Section 3251 "Equity". The adoption of the new standards did not have a significant impact on the Company's financial statements due to the nature of the financial instruments recorded on the balance sheet as well as the nature of the contracts to which the Company is a party. The Company does not currently have any hedges in place and therefore the adoption of Section 3865 "Hedges" did not have any impact on the Company's financial statements. For more information on these policies, see note 2 of the Company's financial statements for the three and six months ended June 30, 2007. On December 1, 2006, the CICA issued three new accounting standards: Handbook Section 1535, Capital Disclosures, Handbook Section 3862, Financial Instruments - Disclosures, and Handbook Section 3863, Financial Instruments - Presentation. These new standards are effective January 1, 2008. Section 1535 specifies the disclosure of (i) an entity's objectives, policies and processes for managing capital; (ii) quantitative data about what the entity regards as capital; (iii) whether the entity has complied with any capital requirements; and (iv) if it has not complied, the consequences of such non-compliance. The new Sections 3862 and 3863 replace Handbook Section 3861, Financial Instruments - Disclosure and Presentation, revising and enhancing its disclosure requirements, and carrying forward unchanged its presentation requirements. These new sections place increased emphasis on disclosures about the nature and extent of risks arising from financial instruments and how the entity manages those risks. We are currently assessing the impact of these new standards on our 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 In 2007, the Company continues to focus on drilling and completion operations, and anticipates tieing-in production in the second half of 2007. Some of the challenges encountered in 2006 such as rig availability have been alleviated with the softening of the oil and gas market experienced in the latter part of 2006 and early 2007. The Company has not experienced problems obtaining rigs in 2007 and does not anticipate challenges in obtaining rigs for the remainder of 2007. The Company is largely affected by commodity price variations. The volatility in oil and gas prices that we have experienced in the past few years directly impacts the revenues and cash flows generated by the Company. In late 2005, the market experienced high commodity prices resulting in increased activity and strong equity valuations. In 2006, we started seeing a softening of the natural gas market and large decreases in prices when compared to the previous year. The decrease in commodity prices impacts the Company by reducing cash flows available for exploration and challenges the economics of potential capital projects, depending on individual views of what constitutes short term versus long term price variations. The volatility we have seen in the market also makes the long term price versus short term price assessment more challenging. Although in 2007, we have seen a decline in some service and operating costs due to the reduced activity when compared to late 2005 and early 2006, they have not decreased at the same rate as commodity prices from the highs in the last half of 2005. To date in 2007, the natural gas market has softened from the beginning of the year and we continue to see the impact on revenues and cash flows generated, as well as a decrease in industry capital activity. The softening market, anticipated to continue at least in the near term, has impacted the Company's capital spending as well, which is approximately half of what it was for the same period in 2006, as partner willingness to participate in projects is reduced or delayed and as access to capital becomes more challenging. The Company continually monitors capital spending and assesses the risk of each individual project to ensure that funds are prioritized appropriately. For the third quarter of 2007, natural gas prices are expected to continue to remain weak, which could make access to capital through internal and external sources increasingly challenging. The natural gas prices in the fourth quarter are expected to strengthen as winter demands increase. The Company does anticipate the natural gas liquids pricing to remain strong for the remainder of 2007, which will partially offset the impact of lower natural gas prices. Overall, management does believe in the long term strength of the natural gas market, despite what we consider to be short term fluctuations and volatility. SELECTED ANNUAL AND QUARTERLY INFORMATION (000's, except per share data) Q1 Q2 Q3 Q4 Annual ------------------------------------------------------------------------- 2007 $ $ $ $ $ ------------------------------------------------------------------------- Oil and gas sales, net of transportation and before royalties 6,116 5,582 Funds from operations 3,371 2,589 Per share - basic 0.07 0.05 - diluted 0.06 0.05 Net income (loss) (268) (709) Per share - basic (0.01) (0.01) - diluted (0.01) (0.01) Capital expenditures 6,228 3,930 Total assets 136,520 134,834 Working capital (net debt)(1) (17,264) (18,673) ------------------------------------------------------------------------- Production (BOE/d) 1,354 1,249 ------------------------------------------------------------------------- 2006 $ $ $ $ $ ------------------------------------------------------------------------- Oil and 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 (loss) (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 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 $ $ $ $ $ ------------------------------------------------------------------------- Oil and 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 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 ------------------------------------------------------------------------- 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 (June 30, 2007 - $138,911, December 31, 2006 - $276,806, December 31, 2005 - $420,988, December 31, 2004 - $620,764). Financial Statements Cinch Energy Corp. June 30, 2007 (unaudited) CINCH ENERGY CORP. BALANCE SHEETS (unaudited) As at June 30, December 31, 2007 2006 $ $ ------------------------------------------------------------------------- ASSETS (notes 4 and 5) Current Accounts receivable 3,193,732 9,107,635 Prepaid expenses and deposits 779,983 957,338 ------------------------------------------------------------------------- 3,973,715 10,064,973 Property, plant and equipment (note 3) 116,243,671 112,301,421 Goodwill 14,616,996 14,616,996 ------------------------------------------------------------------------- 134,834,382 136,983,390 ------------------------------------------------------------------------- ------------------------------------------------------------------------- LIABILITIES AND SHAREHOLDERS' EQUITY Current Accounts payable and accrued liabilities 8,194,310 16,229,842 Credit facility (note 4) 14,177,058 17,304,333 Current portion of capital lease obligation (note 5) 275,789 275,789 ------------------------------------------------------------------------- 22,647,157 33,809,964 Capital lease obligation (note 5) 138,911 276,806 Asset retirement obligations (note 6) 3,299,020 2,934,899 Future income taxes (note 7) 9,049,300 9,410,600 ------------------------------------------------------------------------- 35,134,388 46,432,269 ------------------------------------------------------------------------- Commitments (notes 8 and 9) Shareholders' equity Share capital (note 8) 99,204,634 89,618,546 Contributed surplus (note 8) 2,684,946 2,144,649 Deficit (2,189,586) (1,212,074) ------------------------------------------------------------------------- 99,699,994 90,551,121 ------------------------------------------------------------------------- 134,834,382 136,983,390 ------------------------------------------------------------------------- ------------------------------------------------------------------------- See accompanying notes CINCH ENERGY CORP. STATEMENTS OF OPERATIONS, COMPREHENSIVE INCOME (LOSS) AND DEFICIT (unaudited) Three months ended Six months ended June 30, June 30, 2007 2006 2007 2006 ------------------------------------------------------------------------- $ $ $ $ Revenue Oil and gas sales 5,840,095 4,881,952 12,195,966 10,268,036 Transportation (258,326) (190,431) (497,847) (376,052) Royalties (1,397,479) (743,594) (2,396,354) (2,037,152) Other income 8,983 58,574 33,310 107,496 ------------------------------------------------------------------------- 4,193,273 4,006,501 9,335,075 7,962,328 ------------------------------------------------------------------------- Expenses Operating 715,679 749,842 1,468,743 1,515,066 General and administrative (note 8) 950,230 995,249 2,020,745 1,856,721 Interest on credit facility 188,952 125,509 411,476 125,552 Interest on capital lease (note 5) 7,267 7,266 14,533 12,806 Accretion of asset retirement obligations (note 6) 43,816 18,873 85,284 28,076 Depletion and depreciation 3,188,870 2,490,061 6,494,906 4,995,891 ------------------------------------------------------------------------- 5,094,814 4,386,800 10,495,687 8,534,112 ------------------------------------------------------------------------- Loss before income taxes (901,541) (380,299) (1,160,612) (571,784) ------------------------------------------------------------------------- Taxes (note 7) Current - (20,280) - - Future income tax recovery (192,200) (1,238,800) (183,100) (1,319,900) ------------------------------------------------------------------------- (192,200) (1,259,080) (183,100) (1,319,900) ------------------------------------------------------------------------- Net income (loss) and comprehensive income (loss) for the period (note 2) (709,341) 878,781 (977,512) 748,116 Deficit, beginning of period (1,480,245) (1,026,204) (1,212,074) (895,539) ------------------------------------------------------------------------- Deficit, end of period (2,189,586) (147,423) (2,189,586) (147,423) ------------------------------------------------------------------------- ------------------------------------------------------------------------- Net income (loss) and comprehensive income (loss) for the period per share (note 8) Basic and diluted (0.01) 0.02 (0.02) 0.02 ------------------------------------------------------------------------- ------------------------------------------------------------------------- See accompanying notes CINCH ENERGY CORP. STATEMENTS OF CASH FLOWS (unaudited) Three months ended Six months ended June 30, June 30, 2007 2006 2007 2006 ------------------------------------------------------------------------- $ $ $ $ Operating activities Net income (loss) for the period (709,341) 878,781 (977,512) 748,116 Add non-cash items: Depletion and depreciation 3,188,870 2,490,061 6,494,906 4,995,891 Accretion of asset retirement obligations 43,816 18,873 85,284 28,076 Non-cash compensation expense (note 8) 258,136 257,120 540,297 428,606 Future income tax recovery (192,200) (1,238,800) (183,100) (1,319,900) ------------------------------------------------------------------------- 2,589,281 2,406,035 5,959,875 4,880,789 Net change in non-cash working capital 811,220 (2,351,128) 954,214 (2,032,914) ------------------------------------------------------------------------- Cash provided by operating activities 3,400,501 54,907 6,914,089 2,847,875 ------------------------------------------------------------------------- Investing activities Additions to property, plant and equipment (3,930,092) (13,541,975) (10,158,319) (20,238,167) Net change in non-cash working capital (716,282) 5,705,326 (2,984,083) 5,306,873 ------------------------------------------------------------------------- Cash used in investing activities (4,646,374) (7,836,649) (13,142,402) (14,931,294) ------------------------------------------------------------------------- Financing activities Increase (decrease) in credit facility 1,393,406 6,379,432 (3,127,275) 6,379,432 Issue of common shares, net of issue costs - (32,092) 9,407,888 (68,391) Proceeds from (payments on) capital lease (68,947) 112,056 (137,894) 59,494 Net change in non-cash working capital (78,586) 29,073 85,594 58,290 ------------------------------------------------------------------------- Cash provided by (used in) financing activities 1,245,873 6,488,469 6,228,313 6,428,825 ------------------------------------------------------------------------- Decrease in cash - (1,293,273) - (5,654,594) Cash and cash equivalents, beginning of period - 1,293,273 - 5,654,594 ------------------------------------------------------------------------- Cash and cash equivalents, end of period - - - - ------------------------------------------------------------------------- ------------------------------------------------------------------------- Supplemental information: Cash taxes paid - (40,676) - - Cash interest paid 190,194 132,775 382,435 138,358 ------------------------------------------------------------------------- ------------------------------------------------------------------------- See accompanying notes CINCH ENERGY CORP. NOTES TO FINANCIAL STATEMENTS June 30, 2007 and 2006 (Unaudited) 1. SIGNIFICANT ACCOUNTING POLICIES The unaudited interim financial statements of Cinch Energy Corp. have been prepared in accordance with Canadian generally accepted accounting principles, following the same accounting policies and methods of computation as the financial statements of the Company for the year ended December 31, 2006 except as disclosed in note 2 below. These unaudited financial statements do not include all disclosures required in the annual financial statements and should be read in conjunction with the Company's annual audited financial statements and notes thereto for the year ended December 31, 2006. 2. CHANGES IN ACCOUNTING POLICIES Effective January 1, 2007, the Company adopted six new accounting standards issued by the Canadian Institute of Chartered Accountants ("CICA"): Handbook Section 3855 "Financial Instruments - Recognition and Measurement", Section 3861 "Financial Instruments - Disclosure and Presentation", Section 3865 "Hedges", Section 1506 "Accounting Changes", Section 1530 "Comprehensive Income" and Section 3251 "Equity". Impact upon adoption of Sections 3855, 3861, 3865, 1506, 1530 and 3251 The adoption of the new standards did not have a significant impact on the Company's financial statements due to the nature of the financial instruments recorded on the balance sheet and the contracts to which the Company is a party. Financial instruments - recognition and measurement Section 3855 establishes standards for recognizing and measuring financial assets, financial liabilities, and non-financial derivatives. It requires that financial assets and financial liabilities, including derivatives, be recognized on the balance sheet when the Company becomes a party to the contractual provisions of the financial instrument or non-financial derivative contract. Under this standard, all financial instruments are required to be measured at fair value upon initial recognition except for certain related party transactions. Measurement in subsequent periods depends on whether the financial instrument has been classified as held-for-trading, available-for sale, held-to-maturity, loans or receivables, or other financial liabilities. Financial assets and financial liabilities held-for-trading are measured at fair value with changes in those fair values recognized in net earnings. Financial assets held-to-maturity, loans and receivables, and other financial liabilities are measured at amortized cost using the effective interest method of amortization. Investments in equity instruments classified as available-for-sale that do not have a quoted market price in an active market are measured at cost. Derivative instruments are recorded on the balance sheet at fair value, including those derivatives that are embedded in financial or non-financial contracts that are not closely related to the host contracts. Changes in the fair values of derivative instruments are recognized in net earnings, with the exception of derivatives designated as effective cash flow hedges and hedges of the foreign currency exposure of a net investment in a self-sustaining foreign operation, which are recognized in other comprehensive income. In addition, Section 3855 requires that an entity must select an accounting policy of either expensing debt issue costs as incurred or applying them against the carrying value of the related asset or liability. The financial instruments recognized on Cinch's balance sheet are deemed to approximate their estimated fair values, therefore no further adjustments were required upon adoption of the new sections. There were no financial assets on the balance sheet which were designated as held-for-trading, held-to-maturity or available-for-sale. All financial assets were classified as loans or receivables and are accounted for on an amortized cost basis. All financial liabilities were classified as other liabilities. Hedges Section 3865 provides alternative treatments to Section 3855 for entities which choose to designate qualifying transactions as hedges for accounting purposes. It replaces and expands on Accounting Guideline 13 "Hedging Relationships", and the hedging guidance in Section 1650 "Foreign Currency Translation" by specifying how hedge accounting is applied and what disclosures are necessary when it is applied. The Company does not currently have any hedges in place and therefore the adoption of Section 3865 "Hedges" did not have any impact on the Company's financial statements. Accounting changes Section 1506 provides expanded disclosures for changes in accounting policies, accounting estimates and corrections of errors. Under the new standard, accounting changes should be applied retrospectively unless otherwise permitted or where impracticable to determine. As well, voluntary changes in an accounting policy are to be made only when required by a primary source of GAAP or the change results in more relevant and reliable information. As discussed in this note, the Company adopted several new accounting policies effective January 1, 2007. Comprehensive income (loss) and accumulated other comprehensive income (loss) Section 1530 introduces comprehensive income, which consists of net earnings and other comprehensive income ("OCI"). OCI represents changes in shareholders' equity during a period arising from transactions and changes in prices, markets, interest rates, and exchange rates. OCI includes unrealized gains and losses on financial assets classified as available-for-sale, unrealized translation gains and losses arising from self-sustaining foreign operations net of hedging activities and changes in the fair value of the effective portion of cash flow hedging instruments. The Company has not entered into any transactions which require any amounts to be recorded to other comprehensive income (loss) or accumulated other comprehensive income (loss). Future accounting changes On December 1, 2006, the CICA issued three new accounting standards: Handbook Section 1535, Capital Disclosures, Handbook Section 3862, Financial Instruments - Disclosures, and Handbook Section 3863, Financial Instruments - Presentation. These new standards are effective January 1, 2008. Section 1535 specifies the disclosure of (i) an entity's objectives, policies and processes for managing capital; (ii) quantitative data about what the entity regards as capital; (iii) whether the entity has complied with any capital requirements; and (iv) if it has not complied, the consequences of such non-compliance. The new Sections 3862 and 3863 replace Handbook Section 3861, Financial Instruments - Disclosure and Presentation, revising and enhancing its disclosure requirements, and carrying forward unchanged its presentation requirements. These new sections place increased emphasis on disclosures about the nature and extent of risks arising from financial instruments and how the entity manages those risks. We are currently assessing the impact of these new standards on our financial statements. 3. PROPERTY, PLANT AND EQUIPMENT Property, plant and equipment June 30, 2007 ------------------------------------------------------------------------- Accumulated depletion and Net book Cost depreciation value $ $ $ ------------------------------------------------------------------------- Petroleum and natural gas properties 151,653,629 (36,317,784) 115,335,845 Equipment under capital lease 1,020,307 (238,944) 781,363 Office furniture and equipment 305,850 (179,387) 126,463 ------------------------------------------------------------------------- 152,979,786 (36,736,115) 116,243,671 ------------------------------------------------------------------------- ------------------------------------------------------------------------- December 31, 2006 ------------------------------------------------------------------------- Accumulated depletion and 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 ------------------------------------------------------------------------- ------------------------------------------------------------------------- For the three and six month period ended June 30, 2007 and for the year ended December 31, 2006, no indirect general and administrative expenditures were capitalized. As at June 30, 2007, $11,493,322 of costs related to undeveloped lands were excluded from costs subject to depletion (December 31, 2006 - $10,900,069). For the three months ended June 30, 2007, the depletion calculation included future development costs of $1,861,500 (December 31, 2006 - $3,264,000). Effective April 1, 2007, the Company acquired additional working interests in producing gas wells, as well as provided payment for the elimination of a gross overriding royalty. The total cash consideration of the acquisition was $2.15 million, all of which was allocated to petroleum and natural gas properties. An additional asset retirement obligation of $11,792 was recorded on this acquisition. The additional revenues and expenses incurred relating to the acquired assets have been accounted for in the Company's income statement as of June 20, 2007, which was the closing date of the transaction. 4. CREDIT FACILITY As at June 30, 2007, the Company had a demand, bank credit facility of $33,000,000 (December 31, 2006 - $33,000,000). The facility bears interest at the lender's prime rate. The effective interest rate at June 30, 2007 was 5.7% (June 30, 2006 - 5.9%). The interest rate realized in the first half of 2007 is lower than the prime rate due to drawings on guaranteed notes, which bear a lower interest rate. As at June 30, 2007, there was $14,177,058 drawn on the credit facility (December 31, 2006 - $17,304,333). As collateral for the facility, the Company has provided a general security agreement with the lender constituting a first ranking security interest in all Company 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 5). 5. CAPITAL LEASE OBLIGATION The Company is committed to annual minimum payments under a capital lease agreement as follows: Years ending December 31, $ ------------------------------------------------------------------------- 2007 152,427 2008 304,855 ------------------------------------------------------------------------- Total minimum lease payments 457,282 Less amounts representing interest at 5.12% (42,582) ------------------------------------------------------------------------- Present value of minimum lease payments 414,700 Less current portion (275,789) ------------------------------------------------------------------------- Capital lease obligation at June 30, 2007 138,911 ------------------------------------------------------------------------- ------------------------------------------------------------------------- During the three and six month periods ended June 30, 2007, there was $7,267 and $14,533, respectively, (2006 - $7,266 and $12,806, respectively) recorded in interest expense relating to capital leases. There is a first charge on the Company's assets as security for the capital lease obligation. 6. 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 June 30, 2007 is approximately $5,690,000 to be incurred over the next 43 years (December 31, 2006 - $5,300,000). 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 $3,299,020 at June 30, 2007 (December 31, 2006 - $2,934,899). The Company's asset retirement obligations changed as follows: $ ------------------------------------------------------------------------- Asset retirement obligations, as at December 31, 2006 2,934,899 Liabilities incurred 278,837 Accretion expense 85,284 ------------------------------------------------------------------------- Asset retirement obligations, as at June 30, 2007 3,299,020 ------------------------------------------------------------------------- ------------------------------------------------------------------------- 7. 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: Three months ended Six months ended June 30, June 30, 2007 2006 2007 2006 ------------------------------------------------------------------------- Statutory income tax rate 32.12% 34.49% 32.12% 34.49% $ $ $ $ Anticipated income tax recovery (289,575) (129,002) (372,789) (197,209) Increase/(decrease) resulting from: Resource allowance - (96,093) - (216,860) Non-deductible crown royalties, net of ARTC - (3,149) - 39,551 Rate adjustment 15,830 (1,099,270) 17,514 (1,095,179) Stock based compensation expense 82,913 86,743 173,543 147,826 Other (1,368) 1,971 (1,368) 1,971 ------------------------------------------------------------------------- Future income tax recovery (192,200) (1,238,800) (183,100) (1,319,900) ------------------------------------------------------------------------- Large corporations tax (recovery) - (20,280) - - ------------------------------------------------------------------------- ------------------------------------------------------------------------- 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: June 30, December 31, 2007 2006 $ $ ------------------------------------------------------------------------- Net book value of capital assets in excess of tax pools (10,821,660) (11,051,577) Share issue costs 666,811 649,182 Asset retirement obligations 996,304 886,339 Other 109,245 105,456 ------------------------------------------------------------------------- Future income tax liability (9,049,300) (9,410,600) ------------------------------------------------------------------------- ------------------------------------------------------------------------- 8. SHARE CAPITAL Authorized - Unlimited number of common voting shares without par value ------------------------------------------------------------------------- Issued Number $ ------------------------------------------------------------------------- Common shares Balance, as at December 31, 2006 47,757,632 89,584,611 Issued for cash on flow through private placement (i) 7,812,500 10,000,000 Exercise of special warrants (ii) 55,000 33,935 Issue costs, net of future income taxes (i) - (413,912) ------------------------------------------------------------------------- Balance, as at June 30, 2007 55,625,132 99,204,634 ------------------------------------------------------------------------- Special warrants Balance at beginning and end of period 55,000 33,935 Exercise of special warrants (ii) (55,000) (33,935) ------------------------------------------------------------------------- Balance, as at June 30, 2007 - - ------------------------------------------------------------------------- Share capital, as at June 30, 2007 55,625,132 99,204,634 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Contributed surplus Balance, as at December 31, 2006 2,144,649 Non cash compensation expense (iii) 540,297 ------------------------------------------------------------------------- Contributed surplus, as at June 30, 2007 2,684,946 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Common Shares (i) Private Placement On February 21, 2007, the Company issued under private placement a total of 7,812,500 flow through common shares at $1.28 per share for proceeds of $10,000,000 before total issue costs of $592,112. The Company will renounce $10 million of Canadian exploration expenditures to the flow through investors effective December 31, 2007 and is required to incur such expenditures on or before December 31, 2008. The Company anticipates no difficulties in meeting this obligation. (ii) Exercise of special warrants During the six months ended June 30, 2007, special warrant holders exercised 55,000 special warrants in exchange for a total of 55,000 common shares for no additional cash consideration. As at June 30, 2007, there are no special warrants outstanding. (iii) Exercise of options Non-cash compensation expense is comprised of the stock option benefit for all outstanding options amortized over the vesting period of the options. Per share amounts Basic per share amounts have been calculated using the weighted average number of common shares and special warrants outstanding during the three and six months ended June 30, 2007 of 55,570,132 and 53,325,657, respectively. (June 30, 2006 - 47,812,632 and 47,812,632, respectively). As at June 30, 2007, all of the stock options are anti-dilutive and therefore not included in the determination of dilutive per share amounts. Per share amounts that are anti-dilutive are based on 3,178,000 outstanding, out-of-the-money options and 4,063,000 outstanding, out-of-the-money options for the three and six months ended June 30, 2007, respectively. 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: June 30, 2007 June 30, 2006 Weighted Weighted Average Average Number of Exercise Number of Exercise Options Price Options Price ------------------------------------------------------------------------- $ $ Stock options outstanding, beginning of period 4,071,334 1.96 2,328,000 2.17 Granted 1,072,500 1.01 1,036,000 2.24 Cancelled (33,334) 2.05 - - ------------------------------------------------------------------------- Stock options outstanding, end of period 5,110,500 1.76 3,364,000 2.19 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Stock options outstanding at the end of the period are comprised of the following: June 30, 2007 ------------------------------------------------------------------------- Exercisable options ------------------- Weighted Exercise Number of Number of average Price Options Options price ------------------------------------------------------------------------- $ $ 1.00-1.50 1,957,500 - - 1.51-2.00 1,338,000 895,665 1.86 2.01-2.50 1,110,000 451,663 2.22 2.51-3.00 580,000 351,997 2.53 3.01-3.50 125,000 41,667 3.30 ------------------------------------------------------------------------- 1.76 5,110,500 1,740,992 2.12 ------------------------------------------------------------------------- ------------------------------------------------------------------------- June 30, 2006 ------------------------------------------------------------------------- Exercisable options ------------------- Weighted Exercise Number of Number of average Price Options Options price ------------------------------------------------------------------------- $ $ 1.00-1.50 - - - 1.51-2.00 1,328,000 710,000 1.87 2.01-2.50 1,231,000 101,666 2.22 2.51-3.00 680,000 185,332 2.52 3.01-3.50 125,000 - - ------------------------------------------------------------------------- 2.19 3,364,000 996,998 2.03 ------------------------------------------------------------------------- ------------------------------------------------------------------------- The options outstanding at June 30, 2007 have a weighted average remaining contractual life of 3.4 years (June 30, 2006 - 3.7 years). The fair value of stock options granted to employees, directors and consultants during the six month periods ended June 30, 2006 and 2007, was estimated on the date of grant using the Black Scholes option pricing model with the following weighted average assumptions: dividend yield of zero% (2006 - zero%), expected volatility of 50% (2006 - 46%), risk-free interest rate of 3.93% (2006 - 4.05%), and an expected life of four years (2006 - four years). Outstanding options granted during the six month period ended June 30, 2007 had an estimated weighted average fair value of $0.44 per option (2006 - $0.91 per option), for a total estimated value of $466,425 (2006 - $944,950). For the three and six month periods ended June 30, 2007, a total of $258,136 and $540,297, respectively, (2006 - $257,120 and $428,606, respectively,) has been recognized as stock compensation expense in general and administrative expenses with an offsetting credit to contributed surplus. 9. COMMITMENTS The Company has entered into an operating lease for office premises expiring on November 30, 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 5. 10. FINANCIAL INSTRUMENTS Fair value of financial instruments Financial instruments recognized on the balance sheet consist of accounts receivable, deposits, accounts payable, credit facility and capital lease obligations. As at June 30, 2007, there was no significant difference 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 June 30, 2007, the Company had no fixed price contracts associated with future production. 11. BASIS OF PRESENTATION Certain of the comparative figures have been reclassified to conform to the presentation adopted in the current period.

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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