Cinch Energy Corp. Releases Third Quarter 2009 Results

November 5, 2009 8:00 AM EST

CALGARY, ALBERTA--(Marketwire - Nov. 5, 2009) - Cinch Energy Corp. (TSX: CNH) ("Cinch" or "Company") is pleased to report on the Company's activities and financial results for the third quarter of 2009. Highlights are as follows:

HIGHLIGHTS

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                                 Three Months Ended       Nine Months Ended
                                       September 30,           September 30,
                                   2009        2008        2009        2008
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                             (Unaudited) (Unaudited) (Unaudited) (Unaudited)
Oil and gas sales,
 net of transportation
 ($000's)                         4,403      10,132      16,326      30,945

Sales volumes per day
Natural gas (Mcf/d)              13,044      10,811      13,582       9,675
Natural gas liquids (bbl/d)         207         247         214         261
Equivalence at 6:1 (BOE/d)        2,381       2,049       2,478       1,874

Sales Price
Natural gas ($/Mcf)                2.87        7.97        3.67        9.11
Natural gas liquids ($/bbl)       50.34       96.87       46.51       94.94
Equivalence at 6:1 ($/BOE)        20.10       53.75       24.13       60.28

                                      $           $           $           $
Funds from operations
 ($000's) (1)                     1,854       5,635       7,383      17,085
 - per share, basic (1)            0.03        0.10        0.13        0.31
 - per share, diluted (1)          0.03        0.10        0.13        0.31

Net income (loss) ($000's)       (2,801)        774      (7,367)      2,602
 - per share, basic               (0.05)       0.01       (0.13)       0.05
 - per share, diluted             (0.05)       0.01       (0.13)       0.05

Capital expenditures ($000's)     2,301      12,212       5,824      25,329

Basic weighted average shares
 outstanding (000's)             56,784      55,628      56,020      55,626

Working capital (net debt)
 ($000's) (2)
 - As at September 30, 2009                             (31,040)
 - As at December 31, 2008                              (35,308)

                                         As at November 4, 2009

Common shares outstanding                            58,843,698
Options outstanding                                   5,881,167
 - Weighted average exercise price                         1.35
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(1) Funds from operations and funds from operations per share are not
    generally accepted accounting principles ("GAAP") and represent 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

Production for the nine months ended September 30, 2009 averaged approximately 2,478 BOE/d, resulting in a 32% production increase over the same period of 2008, which averaged approximately 1,874 BOE/d. The third quarter of 2009 average production was 2,381 BOE/d which is a 235 BOE/d decrease over the second quarter average production of 2,616 BOE/d. The third quarter production decrease was primarily due to flush production declines from the Dawson 6-6 Wabamun well (85% working interest) which commenced production in March, 2009 at approximately 5 mmcf/d and is currently producing at 3.3 mmcf/d. The Company is very pleased with the production performance of this well as it appears to be stabilizing. The Company's third quarter production reflects normal production declines which were not offset by additional production brought on during the quarter due to the Company curtailing its capital expenditures due to low commodity prices.

Commodity prices in the third quarter of 2009 continued their downward trend from the second quarter of 2009, from $21.90 per BOE to $20.10 per BOE. This decrease is due primarily to a decrease in natural gas prices from $3.25 per mcf to $2.87 per mcf. Natural gas liquids prices increased slightly from $49.55 per barrel to $50.34 per barrel. The market uncertainty continues to make it difficult to predict what commodity prices will be in the near future. Most recently, we have witnessed a strengthening in the oil and natural gas liquids pricing and a significant increase in natural gas prices as the market anticipates the coming winter heating season. In addition, the market appears to be anticipating a balancing of the supply and demand equation in the natural gas scene with the severe down turn in natural gas wells being drilled in 2009. The Company does not have any hedges in place and maintains its balance sheet through rigorous control of its capital expenditures. The Company remains optimistic that natural gas prices will continue to recover during the fourth quarter of 2009 and 2010 year.

Operating expenses in the third quarter of 2009 were $3.04 per BOE as compared to $3.23 per BOE in the second quarter of 2009, primarily due to lower total operating expenses. Operating expenses per BOE are expected to average approximately $4.00 per BOE for 2009, which again is a reduction from the second quarter estimate of $4.25 per BOE.

OPERATIONS

During the third quarter of 2009, Cinch participated in the drilling of three new wells.

In British Columbia, the Company has been active on its Dawson property and is currently drilling the Dawson 6-30 Wabamun test (65% working interest) which was spudded on September 1, 2009. This well is now expected to reach total depth of 3600 metres in the middle of November as drilling operations have been slower than projected. A successful result in this well will greatly assist the Company in supporting its future gas processing development plans for the area. In addition, a development Kiskatinaw well was drilled and completed at Dawson 1-33 (36% working interest). This well was flow tested at rates between 7 - 8 mmcf/d over a 24 hour period. It is expected that this well will commence production in mid December at a rate of 7.8 mmcf/d. Preliminary pressure data and geologic data supports that this well is in the same pool as the Company's previous two producing Kiskatinaw wells located at Dawson 1-32 and 12-27. Based on this geologic and pressure data, the Company anticipates booking additional reserves for the Kiskatinaw pool, which will be evaluated by the Company's external reserve engineers as part of its year end reserve process. This latest well qualifies for the new British Columbia royalty incentives and will be eligible for deep gas royalty holiday and will be paying 2% royalties subsequent to the expiration of the deep gas royalty holiday during its first year of production.

Of significance, Cinch has elected to participate in its first horizontal Montney test to be drilled during the fourth quarter of 2009 (26% working interest). This non-operated well will be drilled in section 22-80-16W6. This is a follow up well to a successful vertical test drilled at 13-23-80-16W6, in which Cinch did not participate.

In Alberta, a well at Kakwa 2-14 (25% working interest) was drilled and cased as a potential gas well. Completion operations are expected to commence shortly.

FINANCIAL

In August 2009, Cinch issued 3.2 million flow-through shares at a price of $0.85 per share for gross proceeds of $2.7 million. These funds are being used to fund the drilling of the exploratory Wabamun well at Dawson 6-30. Current net debt is approximately $31 million, which is a reduction of $2.3 million from the net debt of $33.3 million at the end of the second quarter. Cinch's capital expenditures for the fourth quarter are currently projected to be approximately $4.0 million. The Company continues to closely monitor its future capital commitments which are set to match the Company's cash flow projections. With natural gas prices having improved most recently and capital markets also strengthening, the Company has become more optimistic regarding its future capital programs for the remainder of 2009 and 2010.

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 and their impact, timing of expenditures, use of proceeds from flow-through financing and timing of renunciation, budgeted capital expenditures and the method of funding thereof and the nature of the expenditures, expected cash flows for 2009, timing of phases of the IFRS conversion project, timing of drilling of wells, anticipated results from wells drilled, new incentives under the British Columbia royalty regime and the possible effect thereof on the Company and the economics of the wells to be drilled in that province, expected royalty rates, operating expenses and general and administrative expenses 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. Consequently, the Company's actual results may differ materially from those expressed in, or implied by, the forward-looking statements. Forward-looking statements or information is based on a number of factors and assumptions which have been used to develop such statements and information but which may prove to be incorrect. Although the Company believes that the expectations reflected in such forward-looking statements or information are reasonable, undue reliance should not be placed on forward-looking statements because the Company can give no assurance that such expectations will prove to be correct. In addition to other factors and assumptions which may be identified in this document, assumptions have been made regarding, among other things: the ability of the Company to obtain equipment and services in a timely and cost efficient manner; drilling results; the ability of the operator of the projects in which the Company has an interest to operate the field in a safe, efficient and effective manner; field production rates and decline rates; the ability to replace and expand oil and natural gas reserves through development of exploration; future oil and natural gas prices; interest rates; the regulatory framework regarding royalties; and the ability of the Company to successfully market its oil and natural gas products. 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

November 4, 2009

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 nine months ended September 30, 2009 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, 2008. Additional information relating to Cinch, including Cinch'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 are 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

Production for the third quarter of 2009 averaged approximately 2,381 BOE/d, a decrease from the second quarter average production of 2,616 BOE/d. The third quarter production reflects declines on flush production, particularly with respect to the Dawson 6-6 Wabamun well (85% working interest), which produced on average approximately 550 BOE/d (net) during the third quarter of 2009 compared to 670 BOE/d (net) during the second quarter. Third quarter production also reflects declines compared to second quarter production in the Dawson 1-32 well (36% working interest) which declined by an average of approximately 75 BOE/d (net) and the Dawson 12-27 well (38% working interest) which declined by an average of approximately 50 BOE/d (net). Production for the third quarter of 2009 also reflected natural declines, as well as decreases in production resulting from several low-producing, non-operated wells that were shut-in during the quarter.

During the three months ended September 30, 2009, the Company incurred $2.3 million of capital expenditures, the majority of which related to drilling costs for the Dawson 6-30 Wabamun well (65% working interest), as well as the Dawson 1-33 Kiskatinaw well (36% working interest). The Company exited the quarter with net debt of $31.0 million, $26.9 million of which was drawn on its $43.0 million demand bank credit facility.

PRODUCTION

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                                Three Months Ended        Nine Months Ended
                                      September 30,            September 30,
                             2009     2008  Change    2009     2008  Change
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Sales volumes                                    %                        %
Natural gas (Mcf/d)        13,044   10,811      21  13,582    9,675      40
Liquids (bbl/d)               207      247     (16)    214      261     (18)
Equivalence (BOE/d)         2,381    2,049      16   2,478    1,874      32

Sales prices                    $        $       %       $        $       %
Natural gas ($/Mcf)          2.87     7.97     (64)   3.67     9.11     (60)
Liquids ($/bbl)             50.34    96.87     (48)  46.51    94.94     (51)
Equivalence ($/BOE)         20.10    53.75     (63)  24.13    60.28     (60)
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Sales volumes for the three and nine months ended September 30, 2009, increased 16% and 32%, respectively, over the same periods of 2008 due to seven additional wells brought on during the latter half of 2008 and the first part of 2009. The most significant were the Dawson 12-27 (38% working interest) and the Dawson 6-6 (85% working interest) wells, which came on production in late October, 2008 and late March, 2009, respectively. Despite declines in production from these wells during the third quarter of 2009, the wells continue to produce at a combined rate of over 700 BOE/d (net).

Natural gas prices were 64% and 60% lower for the three and nine months ended September 30, 2009, respectively, compared to the same periods in 2008. Natural gas prices for the third quarter of 2009 were 12% lower than the second quarter of 2009. The Company's natural gas production continues to be unhedged and is marketed in the Alberta spot market.

Natural gas liquids pricing was 48% and 51% lower for the three and nine months ended September 30, 2009, respectively, compared to the same periods in 2008. Natural gas liquids pricing for the third quarter of 2009 was slightly higher than the $49.55/bbl reported during the second quarter of 2009. Natural gas liquids represent approximately 9% of the Company's oil and natural gas production. The Company has not hedged any of its liquids production.

REVENUES

Dollars in thousands, except per unit amounts
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                                Three Months Ended        Nine Months Ended
                                      September 30,            September 30,
                             2009     2008  Change    2009     2008  Change
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                                $        $       %       $        $       %
Oil and gas sales,
 net of transportation      4,403   10,132     (57) 16,326   30,945     (47)
Per BOE                     20.10    53.75     (63)  24.13    60.28     (60)
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Revenues for the three and nine months ended September 30, 2009 were 57% and 47% lower, respectively, than the same periods of 2008 due to significantly lower commodity prices, partially offset by higher production, as previously discussed. Transportation expense decreased by approximately $0.17 per BOE for the first nine months of 2009 compared to the same period of 2008 primarily due to lower transportation fees in British Columbia, which had minimal production during the first half of 2008.

Revenues for the three months ended September 30, 2009, have decreased 16% from the second quarter of 2009 as a result of lower natural gas prices and lower production during the third quarter of 2009.

ROYALTIES

Dollars in thousands, except per unit amounts
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                                Three Months Ended        Nine Months Ended
                                      September 30,            September 30,
                             2009     2008  Change    2009     2008  Change
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                                $        $       %       $        $       %
Royalties                     720    2,434     (70)  3,036    7,782     (61)
Per BOE                      3.29    12.91     (75)   4.49    15.16     (70)
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Royalty expense decreased during the three and nine months ended September 30, 2009 compared to the same periods of 2008 primarily due to lower revenues, as well as royalty holidays received on some producing wells. The New Royalty Framework ("NRF"), which became effective on January 1, 2009 in Alberta has also impacted royalty expense in 2009 whereby the low natural gas prices experienced during the first nine months of 2009 have resulted in a lower corporate royalty rate. As the natural gas prices increase, the corporate royalty rate is expected to increase.

Royalty expense for the third quarter of 2009 was marginally higher than the $706 thousand of royalty expense recorded during the second quarter of 2009 primarily due to the expiration of the royalty holiday on the Dawson 6-6 well in the second quarter. The increase in royalty expense was partially offset by lower revenues received during the third quarter of 2009. The royalty rate (royalties as a percentage of oil and gas sales) for the third quarter of 2009 was approximately 16.3%, compared to the preceding quarter's rate of approximately 13.5%. The higher rate reflects royalties paid on the Dawson 6-6 well, which was no longer eligible for royalty holiday in the third quarter of 2009. Partially offsetting this rate increase was the continued decline in natural gas prices resulting in a lower overall corporate royalty rate in Alberta. The royalty rate is comprised of both crown royalties and gross overriding royalties.

The royalty rate for the remainder of 2009 is anticipated to be higher than the rate experienced year to date due to higher anticipated commodity prices in the fourth quarter of 2009. Anticipated royalty rates can change, 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
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                                Three Months Ended        Nine Months Ended
                                      September 30,            September 30,
                             2009     2008  Change    2009     2008  Change
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                                $        $       %       $        $       %
Operating                     666    1,130     (41)  2,489    3,111     (20)
Per BOE                      3.04     5.99     (49)   3.68     6.06     (39)
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Total operating expenses for the three and nine months ended September 30, 2009 decreased by 41% and 20%, respectively, compared to the same periods in 2008 primarily due to a gas processing credit received from the Alberta Government under the NRF, as well as lower compressor and equipment maintenance costs and lower methanol and chemical treating costs in 2009. These decreases in operating expenses were partially offset by higher property taxes during 2009.

Operating expenses per BOE for the three and nine months ended September 30, 2009, decreased 49% and 39%, respectively, compared to the same periods of 2008 primarily due to a gas processing credit received in 2009, as well as increased production during 2009.

Total operating expenses for the third quarter of 2009 were lower than the second quarter of 2009 due to lower methanol and chemical treating costs and fluid analysis costs, partially offset by higher compressor and equipment maintenance costs and a decrease in the gas processing credit received during the third quarter. Operating expenses for the third quarter of 2009 were $3.04 per BOE, compared to the second quarter at $3.23 per BOE, primarily due to lower total operating expenses.

Operating expenses for 2009 are not expected to exceed $4.00 per BOE. This is a decrease from the prior guidance of $4.25 per BOE, which can mostly be attributed to increased operational efficiencies. Operating expenses per BOE are expected to increase during the fourth quarter of 2009 primarily due to lower expected production during this period, as well as anticipated increases in methanol charges and maintenance costs. Anticipated costs per BOE can change however, depending on the Company's actual production levels and future changes to the gas processing credits the Company currently receives.

GENERAL AND ADMINISTRATIVE EXPENSES

Dollars in thousands, except per unit amounts
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                                Three Months Ended        Nine Months Ended
                                      September 30,            September 30,
                             2009     2008  Change    2009     2008  Change
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                                $        $       %       $        $       %
General and administrative    967      834      16   2,937    2,683       9
Per BOE                      4.42     4.42       -    4.34     5.23     (17)
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Total general and administrative expenses increased for the three and nine months ended September 30, 2009 compared to the same periods of 2008 due to increased salaries and wages, contractor costs, legal fees, and higher bank charges relating to the Company's credit facility. The increased contractor costs were a direct result of the work performed on the implementation of International Financial Reporting Standards ("IFRS"), as discussed in the recent accounting pronouncements section below. The Company does not capitalize indirect general and administrative expenses.

General and administrative expenses per BOE for the third quarter of 2009 were consistent with the same period of 2008 notwithstanding the increase in total general and administrative expenses due to the higher production volumes in 2009. General and administrative expenses per BOE for the nine months ended September 30, 2009 were lower than the same period of 2008 due to increased production volumes in 2009.

Total general and administrative expenses in the third quarter of 2009 were consistent with the preceding second quarter. General and administrative expenses per BOE were 7% higher in the third quarter of 2009 at $4.42/BOE compared to the second quarter due to decreased production during the third quarter.

General and administrative expenses for 2009 are not expected to exceed $4.50 per BOE. Anticipated costs per BOE can change, however, depending on the Company's actual production levels.

INTEREST EXPENSE

Dollars in thousands, except per unit amounts
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                                Three Months Ended        Nine Months Ended
                                      September 30,            September 30,
                             2009     2008  Change    2009     2008  Change
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                                $        $       %       $        $       %
Interest expense              295      263      12     821      833      (1)
Per BOE                      1.35     1.39      (3)   1.21     1.62     (25)
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Interest expense increased during the three months ended September 30, 2009 compared to the same period in 2008 due to higher draws on the Company's bank credit facility during the third quarter of 2009. Interest expense decreased during the nine months ended September 30, 2009 compared to the same period of 2008, as a result of lower interest rates partially offset by a higher average balance drawn on the Company's bank credit facility throughout the first nine months of 2009. The Company exited the quarter with an outstanding credit facility balance of $26.9 million on its $43.0 million credit facility.

ACCRETION OF ASSET RETIREMENT OBLIGATIONS EXPENSE

Dollars in thousands, except per unit amounts
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                                Three Months Ended        Nine Months Ended
                                      September 30,            September 30,
                             2009     2008  Change    2009     2008  Change
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                                $        $       %       $        $       %
Accretion expense              57       48      19     166      141      18
Per BOE                      0.26     0.26       -    0.25     0.28     (11)
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Accretion expense increased during the three and nine months ended September 30, 2009 compared to the same periods in 2008 due to an increased number of wells with asset retirement obligations.

DEPLETION AND DEPRECIATION EXPENSE

Dollars in thousands, except per unit amounts
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                                Three Months Ended        Nine Months Ended
                                      September 30,            September 30,
                             2009     2008  Change    2009     2008  Change
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                                $        $       %       $        $       %
Depletion and depreciation  5,460    4,385      25  16,871   12,876      31
Per BOE                     24.93    23.26       7   24.94    25.08      (1)
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Total depletion and depreciation expense for the three and nine months ended September 30, 2009 increased compared to the same periods of 2008 due to increased production, as well as a larger capital asset base being depleted. Depletion per BOE for the three months ended September 30, 2009 increased compared to the same period of 2008 primarily due to a reduction in the reserve base used to calculate depletion. Depletion per BOE for the nine months ended September 30, 2009 is consistent with the depletion per BOE for the comparable period in 2008.

The depletion and depreciation expense decreased $481 thousand during the third quarter of 2009 compared to the preceding second quarter primarily due to lower production.

TAXES

Dollars in thousands, except per unit amounts
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                                Three Months Ended        Nine Months Ended
                                      September 30,            September 30,
                             2009     2008  Change    2009     2008  Change
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                                $        $       %       $        $       %
Future income
 tax expense (recovery)      (953)     308    (409) (2,588)   1,032    (351)
Per BOE                     (4.35)    1.64    (365)  (3.83)    2.01    (291)
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A future income tax recovery was recorded for the three and nine months ended September 30, 2009 which is consistent with the net loss experienced during the quarter and on a year to date basis.

Tax pools at September 30:

In thousands
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                                                       2009            2008
                                                          $               $
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COGPE                                                14,737          15,781
CDE                                                  22,551          27,394
CEE                                                  33,093          24,397
UCC                                                  16,564          17,942
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                                                     86,945          85,514
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The Company's tax pools have increased since September 30, 2008 as a result of capital expenditures which were higher than the tax pools needed to eliminate taxable income.

NET INCOME (LOSS) AND FUNDS FROM OPERATIONS

In thousands, except per share amounts
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                                Three Months Ended        Nine Months Ended
                                      September 30,            September 30,
                             2009     2008  Change    2009     2008  Change
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                                $        $       %       $        $       %
Net income (loss)          (2,801)     774    (462) (7,367)   2,602    (383)
 per basic share            (0.05)    0.01    (600)  (0.13)    0.05    (360)
 per diluted share          (0.05)    0.01    (600)  (0.13)    0.05    (360)
Funds from operations       1,854    5,635     (67)  7,383   17,085     (57)
 per basic share             0.03     0.10     (70)   0.13     0.31     (58)
 per diluted share           0.03     0.10     (70)   0.13     0.31     (58)
Weighted average
 shares outstanding        56,784   55,628       2  56,020   55,626       1
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For the three and nine months ended September 30, 2009, the Company incurred a net loss primarily attributable to lower commodity prices.

The Company's funds from operations for the three and nine months ended September 30, 2009 decreased by 67% and 57%, respectively, over the same periods of 2008. Funds from operations in 2009 were significantly impacted by lower commodity prices.

LIQUIDITY AND CAPITAL RESOURCES

In thousands
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                         September 30, 2009   December 31, 2008      Change
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                                          $                   $           %
Working capital
 (deficiency), excluding
 credit facility                     (4,140)             (6,950)        (40)
Credit facility                     (26,900)            (28,358)         (5)
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Net debt                            (31,040)            (35,308)        (12)
Shareholders' equity                (80,043)            (84,394)         (5)
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As at September 30, 2009, the Company had net debt of $31.0 million comprised of a working capital deficiency of $4.1 million and $26.9 million outstanding on its credit facility. The $4.3 million decrease in net debt from December 31, 2008 can be attributed to funds from operations for the nine months ended September 30, 2009 of $7.4 million and proceeds from a flow-through financing of $2.7 million, partially offset by capital expenditures of $5.8 million.

On August 26, 2009, pursuant to a private placement, Cinch issued 3,211,900 flow-through common shares at a price of $0.85 per share for gross proceeds of $2,730,115. The proceeds will be used to fund the drilling of the Dawson 6-30 Wabamun well. As a result of the financing, the Company has a commitment to spend $2.7 million on qualifying Canadian exploration expenditures on or before December 31, 2010. The expenditures are expected to be renounced to investors with an effective date of renunciation of December 31, 2009. As at September 30, 2009, $1,278,000 of qualifying exploration expenditures have been incurred. The Company fully anticipates meeting the remaining obligation.

As at September 30, 2009, there were 58,843,698 common shares and 5,881,167 stock options outstanding.

Management currently intends to fund the remainder of its 2009 capital program from a combination of cash flows generated from operations and proceeds from the private placement. The Company's 2009 capital budget continues to remain at approximately $10 million, with approximately $4 million to be spent in the fourth quarter of 2009.

CAPITAL EXPENDITURES
Additions to property, plant and equipment

In thousands
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                                             Nine months ended September 30,
                                                      2009             2008
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                                                         $                $
Land and rentals                                       429            3,503
Seismic                                               (135)           1,698
Drilling, completing and equipping                   3,884           17,142
Pipelines and facilities                             1,709            2,694
Other assets                                           (63)             292
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Total                                                5,824           25,329
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Management's primary strategy is to expend capital on exploration and development drilling and to earn land by drilling. The Company may, however, also purchase land or make acquisitions where considered strategic.

Capital expenditures for the nine months ended September 30, 2009 include approximately $365 thousand relating to land acquisitions in the Dawson area. The balance of the capital expenditures was incurred on drilling, completion and tie-in operations, primarily in the Dawson area.

The Company's 2009 capital program is currently budgeted at approximately $10 million (subject to adjustments based on cash flows generated), consistent with forecasted cash flows for 2009. The majority of the capital expenditures are projected for the Dawson area located in British Columbia.

BUSINESS RISKS AND RISK MANAGEMENT

General

The long-term commercial success of the Company depends on its ability to find, acquire, develop and commercially produce oil and natural gas reserves. The Company 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 in order to maintain liquidity.

Commodity price fluctuations 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. To date, the Company has not implemented any hedging instruments.

The Company has selected the appropriate personnel to monitor operations and has automated field information where possible, so that operational issues can be assessed and dealt with on a timely basis. The Company, however, is not the operator in all cases and therefore not all operational issues are within its 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.

Attracting and retaining qualified individuals is crucial to the Company's success. The Company understands the importance of maintaining competitive compensation levels given the 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 affect 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 can have an impact on the Company's activity levels and potentially delay operations.

The Government of Alberta implemented its new royalty framework effective January 1, 2009. The Company will continue to monitor the impact of the new royalty framework on its operations and reassess operational plans as necessary. Currently, the majority of the Company's 2009 capital budget is projected for the Dawson area located in British Columbia.

On March 3, 2009, the Government of Alberta announced a three-point incentive program to stimulate new and continued economic activity in Alberta which included a drilling royalty credit for new conventional oil and natural gas wells and a new well royalty incentive program. Under the drilling royalty credit program a $200 per meter royalty credit will be available on new conventional oil and natural gas wells drilled between April 1, 2009 and March 31, 2011, subject to certain maximum amounts. The maximum credits available will be determined by the Company's production level in 2008 and its drilling activity between April 1, 2009 and March 31, 2011. Based on the Company's 2008 production, it will be entitled to a maximum credit of 50% of royalties payable in the period April 1, 2009 and March 31, 2011.

The new well incentive program will apply to wells beginning production of conventional oil and natural gas between April 1, 2009 and March 31, 2011 and provides for a maximum 5% royalty rate for the first 12 months of production, up to a maximum of 50,000 barrels of oil or 500 Mmcf of natural gas. At this time, the Company has not allocated any of its 2009 capital spending back into Alberta based on this new incentive program. The Company will continue to monitor any changes and will update its plans as required.

On August 6, 2009, the Government of British Columbia announced an oil and gas stimulus package designed to attract investment in and create economic benefits for British Columbia. The stimulus package includes four royalty initiatives related primarily to natural gas drilling and infrastructure development. Natural gas wells spudded within the 10-month period from September 1, 2009 to June 30, 2010 and brought on production by December 31, 2010 qualify for a 2% royalty rate for the first 12 months of production, beginning from the first month of production for the well (the "Royalty Relief Program"). British Columbia's existing Deep Royalty Credit Program was permanently amended for wells spudded after August 31, 2009 by increasing the royalty deduction on deep drilling for natural gas by 15% and extending the program to include horizontal wells drilled to depths of between 1,900 and 2,300 metres. Wells spud between September 1, 2009 and June 30, 2010 may qualify for both the Royalty Relief Program and the Deep Royalty Credit Program but will only receive the benefits of one program at a time. Finally, an additional $50 million was allocated to be distributed through British Columbia's existing Infrastructure Royalty Credit Program to stimulate investment in oilfield-related road and pipeline construction. The new incentives are dependent on numerous factors such as flow rates and natural gas prices and could potentially be significant to the Company. After taking into consideration these incentives, the Company determined that it was prudent to delay the spudding of the Dawson 6-30 Wabamun well (85% working interest) until after the effective date of September 1, 2009 given the potential impact of these new incentives on the economic returns to be generated by this well.

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.

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. The Company optimizes its operations with respect to compressor fuel usage and natural gas flaring so that a reduction in emissions is realized.

Global Financial Crisis

Market events and conditions over the past year, including disruptions in the international credit markets and other financial systems and the deterioration of global economic conditions, caused significant volatility and weakening in commodity prices. These conditions became evident in the latter part of 2008 and are continuing in 2009, causing a loss of confidence in the broader U.S. and global credit and financial markets. This resulted in the collapse of and government intervention in, major banks, financial institutions and insurers and creating a climate of greater volatility, less liquidity, widening of credit spreads, lack of price transparency, increased credit losses and tighter credit conditions. Notwithstanding various actions by governments, concerns about the general condition of the capital markets, financial instruments, banks, investment banks, insurers and other financial institutions caused the broader credit markets to further deteriorate and stock markets to decline substantially. During the latter part of the third quarter of 2009 and continuing into the fourth quarter, commodity prices have begun to show some improvement, demonstrating that the economy is potentially starting to recover. As a result of these early signs of economic strengthening, company valuations have recently started to improve.

Petroleum prices are still expected to remain volatile for the near future as a result of market uncertainties over the supply and demand of these commodities due to the current state of the world economies. The decrease in commodity prices over the past twelve months has directly impacted the Company's cash flows and forecasted spending for 2009. In April 2009, the Company secured an increased revolving demand bank credit facility of $43 million (previously $40 million) which will enhance the Company's ability to manage through these uncertain times.

Substantial Capital Requirements

The Company anticipates making substantial capital expenditures for the acquisition, exploration, development and production of oil and natural gas reserves in the future. As the Company's revenues may decline as a result of decreased commodity pricing, it has been, and may be further required to reduce capital expenditures. In addition, uncertain levels of near term industry activity coupled with the present global credit crisis exposes the Company to additional risk. There can be no assurance that debt or equity financing, or cash generated by operations will be available or sufficient to meet these requirements or for other corporate purposes or, if debt or equity financing is available, that it will be on terms acceptable to the Company. The inability of the Company to access sufficient capital for its operations could have a material adverse effect on the Company's business, financial condition, results of operations and prospects.

Third Party Credit Risk

The Company may be exposed to third party credit risk through its contractual arrangements with its current or future joint venture partners, marketers of its petroleum and natural gas production and other parties. The financial capability of the Company's partners can pose increased risks to the Company, particularly during periods when access to capital is limited and prices are depressed. The Company mitigates the risk of collection by attempting to obtain its partners' share of capital expenditures in advance of a project and by monitoring receivables regularly. The Company also attempts to mitigate risks by cultivating multiple business relationships and obtaining partners when needed and where possible.

In the event that joint venture partners fail to meet their contractual obligations to the Company, such failures may have a material adverse effect on the Company's business, financial condition, results of operations and prospects. In addition, poor credit conditions in the industry and of joint venture partners may impact a joint venture partner's willingness to participate in the Company's ongoing capital program, potentially delaying the program and the results of such program until the Company finds a suitable alternative partner.

CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

The Company's Chief Executive Officer and Chief Financial Officer have designed, or caused to be designed under their supervision, disclosure controls and procedures to provide reasonable assurance that: (i) material information relating to the Company is made known to the Company's Chief Executive Officer and Chief Financial Officer by others, particularly during the period in which the annual filings are being prepared; and (ii) information required to be disclosed by the Company in its annual filings, interim filings or other reports filed or submitted by it under securities legislation is recorded, processed, summarized and reported within the time period specified in securities legislation.

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 to provide reasonable assurance regarding the reliability of the Company's financial reporting and preparation of financial statements for external purposes in accordance with Canadian GAAP.

The Company is required to disclose any change in the Company's internal controls over financial reporting that occurred during the period beginning on July 1, 2009 and ending on September 30, 2009 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 such period that have materially affected, or are reasonably likely to materially affect, the Company's internal controls over financial reporting.

It should be noted that a control system, including the Company's disclosure and internal controls and procedures, no matter how well conceived, can provide only reasonable, but not absolute, assurance that the objectives of the control system will be met and it should not be expected that the disclosure and internal controls and procedures will prevent all errors or fraud.

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
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Operating lease        1,259        231        480        506            42
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                       1,259        231        480        506            42
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CHANGES IN ACCOUNTING POLICIES

Effective January 1, 2009, the Company adopted the recommendations of the Emerging Issues Committee of the CICA, Abstract 173, "Credit Risk and the Fair Value of Financial Assets and Financial Liabilities". The adoption of abstract 173 did not impact the Company's financial position. For more information on these policies, see note 2 of the Company's financial statements for the three and nine months ended September 30, 2009.

RECENT ACCOUNTING PRONOUNCEMENTS

The Canadian Institute of Chartered Accountants ("CICA") has issued a number of accounting pronouncements, some of which may impact the Company's reported results and financial position in future periods.

On February 13, 2008, the Canadian Accounting Standards Board ("AcSB") confirmed the use of International Financial Reporting Standards ("IFRS") for publicly accountable profit-oriented enterprises beginning on January 1, 2011 with appropriate comparative data from the prior year. IFRS will replace GAAP for those enterprises, including listed companies and other profit-oriented enterprises that are responsible to large or diverse groups of stakeholders. Under IFRS, the primary audience is capital markets and as a result, there is significantly more disclosure required, specifically for quarterly reporting. While IFRS uses a conceptual framework similar to GAAP, there are significant differences in accounting policies that must be addressed. The impact of these new standards on our financial statements is not reasonably determinable or estimable at this time.

The Company commenced its IFRS conversion project in 2008. This project consists of four phases: diagnostic; design and planning; solution development; and integration. The Company has completed the diagnostic phase, which involved a high-level review of the major differences between current GAAP and IFRS. The Company has determined that the areas of accounting differences with the highest potential impact to the Company are accounting for the exploration and evaluation of oil and gas resources, as well as accounting for property, plant and equipment, asset impairment testing, and income taxes.

For the first nine months of 2009, the Company continued the design and planning phase of the project, which involves documenting the high impact areas identified and evaluating the different accounting policy options available under IFRS. During this phase, the Company will also assess the impact that a conversion to IFRS will have on the Company's current policies and procedures, information technology and accounting systems, as well as internal controls. The Company is in the process of completing the design and planning phase and anticipates commencing the solution development phase in the last quarter of the year.

In July 2009, the International Accounting Standards Board ("IASB") issued an amendment to IFRS 1 "First Time Adoption of International Reporting Standards." The amendment allows full cost accounting companies to elect, at the time of adoption, to measure exploration and evaluation assets at the amount determined under the entity's previous GAAP. The amendment will also permit full cost accounting companies to measure, at the time of adoption, oil and gas assets in the development or production phases, by using the total value determined under the entity's previous GAAP and allocating values at the unit of account level based on the Company's reserve volumes or reserve values as of the date of conversion. This exemption will relieve the Company from retrospective application of IFRS for its oil and gas assets. The Company currently anticipates utilizing this exemption.

The Company will continue to monitor the development of guidance on how to apply IFRS to oil and gas exploration and development activities, as well as the IFRS adoption efforts of our peers, and will update our plans as necessary.

In December 2008, the CICA issued Handbook Section 1582 "Business Combinations," which will replace CICA Handbook Section 1581 of the same name. Under this guidance, equity consideration of the purchase price used in a business combination is based on the fair value of shares exchanged at their market price at the date of the exchange. Currently, the equity consideration of the purchase price used is based on the market price of the shares for a reasonable period before and after the date the acquisition is agreed upon and announced. This new standard generally requires all acquisition costs to be expensed, which currently are capitalized as part of the purchase price. Contingent liabilities are to be recognized at fair value at the acquisition date and re-measured at fair value through earnings each period until settled. Currently, only contingent liabilities that are resolved and payable are included in the cost to acquire the business. In addition, negative goodwill is required to be recognized immediately in earnings, unlike the current requirement to eliminate it by deducting it from non-current assets in the purchase price allocation. CICA Handbook Section 1582 is effective January 1, 2011. This standard has no current impact on the Company's financial statements.

CRITICAL ACCOUNTING ESTIMATES

There are a number of critical estimates underlying the accounting policies the Company applies in preparing its financial statements.

Reserves

The estimate of reserves is used in forecasting what will ultimately be recoverable from the properties and their economic viability and in calculating the Company's depletion and potential impairment of asset carrying costs. The process of estimating reserves is complex and requires significant interpretation and judgment. It is affected by economic conditions, production, operating and development activities, and is performed using available geological, geophysical, engineering and economic data.

Reserves at year end are evaluated by an independent engineering firm and quarterly updates to those reserves are estimated by the Company.

Revenue Estimates

Payment and actual amounts for petroleum and natural gas sales can be received months after production. The Company estimates a portion of its petroleum and natural gas production, sales and related costs, based upon information received from field offices, internal calculations, historical and industry experience.

Cost Estimates

Costs for services performed but not yet billed are estimated based on quotes provided and historical and industry experience.

Asset Retirement Obligations

The liability recorded for asset retirement obligations, an estimate of restoring assets and locations back to environmental and regulatory standards upon future retirement or abandonment, include estimates of restoration costs to be incurred in the future and an estimated future inflation rate. Costs estimated are based upon internal and third party calculations and historical experience, and future inflation rates are estimated using historical experience and available economic data.

Income Taxes

The Company records future tax liabilities to account for the expected future tax consequences of events that have been recorded in its financial statements. These amounts are estimates; the actual tax consequences may differ from the estimates due to changing tax rates and regimes, as well as changing estimates of cash flows and capital expenditures in current and future periods. All tax filings are subject to audit and potential reassessment after the lapse of considerable time. Accordingly, the actual income tax liability may differ signifi

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