Cinch Energy Corp.
TSX : CNH

Cinch Energy Corp.

March 08, 2010 08:30 ET

Cinch Energy Corp. Releases 2009 Results and 2010 Outlook

CALGARY, ALBERTA--(Marketwire - March 8, 2010) - Cinch Energy Corp. (TSX:CNH)("Cinch" or the "Company") is pleased to announce its financial and operating results for the year ended December 31, 2009 and guidance for 2010.

2009 ACCOMPLISHMENTS

- Increased proved plus probable reserves by 45% from 7.3 mmboe to 10.6 mmboe

- Proved reserve addition costs of $15.19/boe and P+P addition costs of $13.10/boe

- Production volumes for 2009 averaged 2,374 boe per day, an increase of 17% over 2008

- Reserve life index of over 12 years on a P+P basis

- Operating costs of $3.49/boe, 40% lower than 2008

- Exploration and development success at Dawson, British Columbia

-- Significant Cinch operated Wabamun gas discovery at 6- 30-80-15 W6M

-- Drilling and bringing on stream 8 mmcf/d of gas in the Kiskatinaw zone from the 1-33-80-15 W6M well

-- Proving up numerous horizontal Montney locations in 80-16 W6M

"In spite of low natural gas prices which significantly impacted cash flow and reduced activity levels, Cinch made significant progress in 2009," said Sid Dykstra, CEO. "With our clean balance sheet and inventory of opportunities in North East British Columbia and the Deep Basin area of Alberta, we are well positioned to continue to grow in 2010."

2010 OUTLOOK

After closing the $37 million equity financing in January, Cinch had working capital of $5.0 million and undrawn credit facilities of $43 million. The Company has budgeted for a capital program of $60 million in 2010. Activity to date includes:

- Drilled and cased the first horizontal Montney well on Cinch lands. This well is expected to be completed in the first quarter, and drilling is underway on a second non-operated horizontal Montney well.

- Drilling an 82.5% working interest Cinch operated horizontal Montney well.

- Drilled and cased the Cinch operated 7-25-80-16 W6M well as a potential Wabamun with net pay of 40 meters which offsets last year's discovery at 6- 30-80-15 W6M. This well is currently being completed.

Based on our existing production base and additions from development drilling it is anticipated that our production volumes will average approximately 3,000 boe per day during 2010. Assuming average natural gas prices of $5.50/GJ AECO and US$80/bbl WTI oil prices, these volumes are expected to generate cash flow of approximately $20 million for 2010. This outlook will be reviewed in mid-2010 and, in the event that natural gas prices are higher or lower than expected, the Company will adjust the capital budget accordingly. Additional details about Cinch's 2010 plans and activities in our core areas are shown in the corporate presentation on our website at www.cinchenergy.com.



HIGHLIGHTS

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Three Months Ended Year Ended
December 31, December 31,
2009 2008 2009 2008
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Petroleum and natural gas sales,
net of transportation ($000's) 5,815 9,679 22,141 40,624
Production per day
Natural gas (Mcf/d) 11,235 13,634 12,990 10,670
Natural gas liquids (Bbl/d) 193 229 209 253
Equivalence at 6:1 (BOE/d) 2,065 2,501 2,374 2,031

Sales price
Natural gas ($/Mcf) 4.56 6.91 3.86 8.41
Natural gas liquids ($/Bbl) 61.92 48.35 50.10 84.34
Equivalence at 6:1 ($/BOE) 30.61 42.06 25.55 54.64

$ $ $ $
Funds from operations (000's) (1) 2,096 4,371 9,479 21,456
- per share, basic(1) 0.04 0.08 0.17 0.39
- per share, diluted(1) 0.04 0.08 0.17 0.38

Net income (loss) (000's) (1,537) (1,435) (8,904) 1,167
- per share, basic (0.03) (0.03) (0.16) 0.02
- per share, diluted (0.03) (0.03) (0.16) 0.02

Net capital expenditures ($000's) 518 6,685 6,342 32,014

Basic weighted average shares
outstanding (000's) 58,853 55,632 56,734 55,627

Working capital (net debt)(2)
($000's)
As at December 31, 2009 (29,444)
As at December 31, 2008 (35,308)

As at March 5, 2010

Common shares outstanding, after
$37 million equity financing 81,433,666

Options outstanding 6,569,500
- average exercise price 1.35
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(1) Funds from operations is not a generally accepted accounting principle
("GAAP") measure and represents cash provided by operating activities
on the statement of cash flows less the effect of changes in non-cash
working capital related to operating activities.
(2) Net debt is a non-GAAP measure and represents the sum of the working
capital (deficiency) and the outstanding credit facility balance.


RESERVES

The corporate reserves estimates, effective December 31, 2009, were prepared by the independent engineering firm of GLJ Petroleum Consultants Ltd. ("GLJ") in accordance with National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities ("NI 51-101"). Also presented is some reserve information using "Company Interest" which is defined as the Company's total working interest share before deduction of royalties payable to others and including any royalty interest of Cinch.

- Total proved reserves at December 31, 2009 increased 40% to 7.4 million BOE compared to 5.3 million BOE at December 31, 2008.

- Total proved plus probable reserves at December 31, 2009 increased 45% to 10.6 million BOE compared to 7.3 million BOE at December 31, 2008.

- On a proved plus probable basis, the finding, development and acquisition costs were $13.10 per BOE ($15.19 per BOE on a proved basis)



RESERVES SUMMARY - GROSS RESERVES

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Light and Variance
Medium Natural Gas Natural Total Total (2009
Crude Oil Liquids Gas 2009 2008 vs 2008)
(mbbls) (mbbls) (mmcf) (mboe) (mboe) (mboe)
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Proved
-Developed Producing 22 569 20,245 3,965 4,227 (262)
-Dev. Non-Producing - 43 3,998 709 832 (123)
-Undeveloped - 373 13,905 2,691 174 2,517
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Total Proved 22 985 38,148 7,365 5,233 2,132
Probable 5 393 16,833 3,204 2,044 1,160
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Total Proved Plus Probable 27 1,378 54,981 10,569 7,277 3,292
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Note: May not add due to rounding

NET PRESENT VALUE SUMMARY - FORECASTED PRICES AND COSTS

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Discounted at
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December 31, 2009 Undiscounted 5% 10% 15% 20%
(1)(2)(3) ($M) ($M) ($M) ($M) ($M)
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Proved -Developed Producing 112,909 79,097 62,387 52,456 45,812
-Dev. Non-Producing 19,491 15,846 13,475 11,782 10,498
-Undeveloped 50,019 27,542 14,885 7,080 1,910
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Total Proved 182,419 122,485 90,747 71,318 58,220
Probable 111,873 54,405 33,267 22,856 16,760
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Total Proved Plus Probable 294,292 176,890 124,014 94,174 74,980
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Note: May not add due to rounding

(1) Utilizing GLJ January 1, 2010 price forecast

(2) As required by NI 51-101, undiscounted well abandonment costs of $2.5
million for total proved reserves and $3.1 million for total proved
plus probable reserves are included in the net present value of future
net revenues determination.

(3) Prior to provision of income taxes, interest, debt service charges and
general and administrative expenses. It should not be assumed that the
undiscounted and discounted future net revenues estimated by GLJ
represent the fair market value of the reserves.


FORECASTED PRICES

The January 1, 2010 pricing forecasts presented below have been prepared by GLJ. These prices have been utilized in determining the reserves and cash flow forecasts above.



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Oil
--------------------------------------
WTI Edmonton Hardisty Natural Gas
Cushing Par Price Heavy 12 Alberta Plant
Oklahoma 40 API degree degree API Gate Price
Year ($US/Bbl) ($Cdn/Bbl) ($Cdn/Bbl) ($Cdn/MMBtu)
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Forecast
2010 80.00 83.26 64.99 5.75
2011 83.00 86.42 65.24 6.58
2012 86.00 89.58 65.33 6.68
2013 89.00 92.74 65.26 6.73
2014 92.00 95.90 67.52 6.84
2015 93.84 97.84 68.90 6.94
2016 95.72 99.81 70.32 7.20
2017 97.64 101.83 71.76 7.72
2018 99.59 103.88 73.22 8.29
2019 101.58 105.98 74.72 8.47
Thereafter +2%/yr +2%/yr +2%/yr +2%/yr
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Natural Gas Liquids
--------------------------------
Edmonton
Edmonton Edmonton Pentanes Inflation Exchange
Propane Butane Plus Rates(a) Rate(b)
Year ($Cdn/Bbl) ($Cdn/Bbl) ($Cdn/Bbl) %/year ($US/$Cdn)
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Forecast
2010 52.46 64.11 84.93 2 0.950
2011 54.45 66.54 88.15 2 0.950
2012 56.43 68.98 91.37 2 0.950
2013 58.42 71.41 94.59 2 0.950
2014 60.42 73.84 97.82 2 0.950
2015 61.64 75.33 99.79 2 0.950
2016 62.88 76.85 101.81 2 0.950
2017 64.15 78.41 103.86 2 0.950
2018 65.45 79.99 105.96 2 0.950
2019 66.77 81.60 108.10 2 0.950
Thereafter +2%/yr +2%/yr +2%/yr 2 0.950
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RECONCILIATION OF CHANGES IN RESERVES

The following table sets out the reconciliation of Cinch's gross reserves as at December 31, 2009 compared to December 31, 2008 based on forecast prices and costs by principal product type:



ASSOCIATED AND NON-
LIGHT AND MEDIUM OIL ASSOCIATED GAS
---------------------------------------------------------
Gross Gross
Proved Proved
Gross Gross Plus Gross Gross Plus
Proved Probable Probable Proved Probable Probable
FACTORS (Mbbl) (Mbbl) (Mbbl) (Mmcf) (Mmcf) (Mmcf)
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December 31, 2008 20 8 28 27,515 10,807 38,323

Discoveries 2,708 1,805 4,513
Extensions 13,353 7,642 20,995
Infill Drilling
Improved Recovery
Technical Revisions 10 (3) 7 (97) (3,385) (3,482)
Acquisitions
Dispositions (332) (100) (432)
Economic Factors (268) 64 (205)
Production (8) (8) (4,731) (4,731)
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December 31, 2009 22 5 27 38,148 16,833 54,981
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Note: May not add due to rounding


NATURAL GAS LIQUIDS
------------------------------
Gross
Proved
Gross Gross Plus
Proved Probable Probable
FACTORS (Mbbl) (Mbbl) (Mbbl)
-------------------------------------------------
December 31, 2008 628 235 863

Discoveries
Extensions 358 221 579
Infill Drilling
Improved Recovery
Technical Revisions 80 (65) 15
Acquisitions
Dispositions (5) (1) (6)
Economic Factors (9) 4 (5)
Production (68) (68)
------------------------------
December 31, 2009 985 393 1,378
------------------------------
Note: May not add due to rounding


Additional reserve disclosure tables, as required under NI 51-101 are contained in Cinch's Annual Information Form, which will be filed on SEDAR.

FINDING AND DEVELOPMENT COSTS (F&D) AND FINDING, DEVELOPMENT AND NET ACQUISITION COSTS (FD&A)

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



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2009 2008 3 year average
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Proved Proved + Proved Proved + Proved Proved +
Probable Probable Probable
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Capital ($'000s)
Exploration and
development (1) 6,342 6,342 32,014 32,014 19,052 19,052
Acquisition capital - - - - 709 709
Change in future
capital 39,144 48,062 2,349 2,200 13,818 15,927
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Total capital
including change
in future
capital 45,486 54,404 34,363 34,214 33,579 35,688
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Reserve additions
(mboe)
Exploration and
development (2) 2,981 4,134 1,617 1,790 1,881 2,327
Acquisition 13 20 - - (25) (36)
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Total reserve
additions
(mboe)(2) 2,994 4,154 1,617 1,790 1,856 2,291
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Costs ($/boe)
F&D 15.26 13.16 21.25 19.11 17.47 15.03
FD&A 15.19 13.10 21.25 19.11 18.09 15.58
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Note: May not add due to rounding

(1) The aggregate of the exploration and development costs incurred in the
most recent financial year and the change during that year in estimated
future development costs generally will not reflect total finding and
development costs related to reserves additions for that year.
(2) Reserve additions for 2008 and 2007 are based on "Company interest"
reserves defined by the total working interest (operating and
non-operating) share before deduction of royalties payable to others
and including royalty interests of Cinch. For 2009, Cinch calculated
F&D and FD&A costs per boe based on reserves determined in accordance
with NI 51-101, which were not materially different from "Company
interest" reserves for such year.


PRODUCTION & RESERVE LIFE INDEX

The Company's reserve life index using annualized fourth quarter 2009 production is 8.5 years for proved BOE reserves compared to 5.7 years in 2008 and 12.2 years for proved plus probable BOE reserves compared to 8.0 years in 2008.



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2009 2008
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Production rate is an: Annualized Q4 Average Annualized Q4 Average
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Production (boe/d) 2,065 2,374 2,501 2,031
Proved reserves (mboe) 7,365 7,365 5,233 5,233
Proved reserve life index
(years) 8.5 8.3 5.7 7.1
Proved plus probable
reserves (mboe) 10,569 10,569 7,277 7,277
Proved plus probable
reserve life index (years) 12.2 11.8 8.0 9.8
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Cinch exited the year at approximately 2,600 BOE per day, with the tie in of the 1-33-80-15 W6M well late in December.

RESERVE REPLACEMENT

The Company's 2009 capital investment program replaced 2009 average production by a factor of 3.4 times on a proved basis and 4.8 times on a proved plus probable basis. Reserve replacement is calculated by dividing the applicable category of reserve additions (after revisions of prior periods) by production.



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2009 2009 2008 2008

Production total is an: Annualized Q4 Average Annualized Q4 Average
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Production (mboe) 753.7 866.5 915.4 743.4
Proved reserve additions
after revisions of prior
periods (mboe) (1) 2,994 2,994 1,617 1,617
Proved replacement ratio 4.0 3.5 1.8 2.2
Proved plus probable
reserve additions after
revision of prior periods
(mboe) (1) 4,154 4,154 1,790 1,790
Proved plus probable
replacement ratio 5.5 4.8 2.0 2.4
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(1) Reserve replacement for 2008 is based on "Company interest" reserves
defined by the total working interest (operating and non-operating)
share before deduction of royalties payable to others and including
royalty interests of Cinch. For 2009, Cinch calculated reserve
replacement based on reserves determined in accordance with NI 51-101,
which were not materially different than "Company interest" reserves
for such year.


RECYCLE RATIO

The recycle ratio is a measure for evaluating the effectiveness of a company's re-investment program. It accomplishes this by comparing the operating netback per barrel of oil equivalent to that year's reserve finding and development costs. Cinch presents the recycle ratio on both an FD&A basis (based on 2009 actual FD&A) and an F&D basis.



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2009 2009 2008 2008
(FD&A) (F&D) (FD&A) (F&D)
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Operating netbacks ($/BOE) 17.04 17.04 35.10 35.10
Proved finding, development and
net acquisition costs after revision
of prior periods and including the
change in future development capital
($/BOE) (1) 15.19 15.26 21.25 21.25
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Proved recycle ratios 1.1 1.1 1.7 1.7
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Proved plus probable finding, development
and acquisition costs after revisions of
prior periods and including the change
in future development capital ($/BOE) (1) 13.10 13.16 19.11 19.11
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Proved plus probable recycle ratios 1.3 1.3 1.8 1.8
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Note: May not add due to rounding

(1) Recycle ratio for 2008 is based on "Company interest" reserves defined
by the total working interest (operating and non-operating) share
before deduction of royalties payable to others and including royalty
interests of Cinch. For 2009, Cinch calculated reserve replacement
based on reserves determined in accordance with NI 51-101, which are
not materially different than "Company interest" reserves for such year.



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, budgeted capital expenditures and the method of funding thereof and the nature of the expenditures, expected production increases and the timing thereof, expected decline rates of new wells, expected decrease in cash flows for 2009, timing of phases of IFRS conversion project, exemptions expected to be relied upon and certain impacts on the Company's financial statements, anticipated use of proceeds from financings, timing of drilling, completion and tie-in of wells, 2010 production estimate and 2010 cash flow, expected royalty rates and the effect thereon of changes in commodity prices and their volatility, expected operating costs 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. The cash flow estimate for 2010 included herein may represent future oriented financial information and a financial outlook in accordance with applicable securities laws. Management approved such cash flow estimate as at March 5, 2010 and such information is provided to provide investors with information with respect of the expected cash flow of the Company based on the assumptions set out which will also provide information as to the ability of the Company to fund its capital expenditures and other expenses and may not be appropriate for other purposes.

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

March 5, 2010

The following management's discussion and analysis ("MD&A") should be read in conjunction with Cinch Energy Corp.'s ("Cinch" or the "Company") audited financial statements for the years ended December 31, 2009 and 2008. This commentary is based on the information available as at, and is dated, March 5, 2010. Additional information relating to Cinch, including the Company's Annual Information Form when filed, 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 a more meaningful indicator of the Company's performance than cash provided by operating activities or net income as determined in accordance with Canadian generally accepted accounting principles ("GAAP"). 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 MD&A contains the term "net debt" which is the sum of the working capital (deficiency) and the outstanding credit facility balance and is used to track total expected indebtedness. This number may not be comparable to that reported by other companies.

OPERATIONAL UPDATE

Cinch had a successful year including a significant natural gas discovery in the Wabamun zone at Dawson. However, due to low commodity prices in 2009, cash flows from operations were reduced and, as a result, the Company had a more conservative capital budget. Despite this decrease in spending, Cinch was still able to make significant progress at its Dawson property in the Wabamun, Kiskatinaw and Montney formations.

During the first quarter of 2009, the Company completed the Dawson 11-26 well (32.5% working interest) in the Montney zone. The well was flow tested over a three and a half-day period at a stable rate of approximately two mmcf per day (gross). The Dawson 10-15 well (26% working interest) was also completed in the Montney zone with a natural gas rate after a five-day flow period of approximately 600 mcf per day (gross).

During the third quarter of 2009, the Company drilled the Dawson 6-30 Wabamun well (65% working interest), as well as the Dawson 1-33 Kiskatinaw well (36% working interest). The Dawson 1-33 Kiskatinaw well was tied in and came on production in December 2009 at a rate of 7.9 mmcf per day (gross). The Company plans to tie in the Dawson 6-30 Wabamun well at a restricted rate of five mmcf per day (gross) by the end of the first quarter of 2010. In December, the Company began drilling the Dawson 7-25 Wabamun well (65% working interest), as well as the Dawson 12-22 Montney horizontal well (26% working interest).

Production for the year was slightly lower than anticipated averaging 2,374 BOE per day. The lower production can be attributed to delays in bringing the Dawson 1-33 well on production. Production is expected to increase in the latter half of 2010 as the Company is planning an active capital program for 2010.

In January 2010, the Company completed a bought deal financing of 22,493,300 common shares at $1.65 per share for gross proceeds of $37,113,945. This will allow for increased financial flexibility when planning for the 2010 capital program. The Company anticipates spending a total of $60 million in 2010 in Alberta and British Columbia. The 2010 budget will be funded from cash flows and the availability of funds from the Company's credit facility.



PRODUCTION

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Three Months Ended December 31, Year Ended December 31,
2009 2008 Change 2009 2008 Change
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% %
Natural gas (Mcf/d) 11,235 13,634 (18) 12,990 10,670 22
Liquids (Bbl/d) 193 229 (16) 209 253 (17)
Equivalence (BOE/d) 2,065 2,501 (17) 2,374 2,031 17
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Production for 2009 averaged 2,374 BOE per day, a 17% increase over the 2008 average production of 2,031 BOE per day. Production increased year over year primarily due to seven new wells brought on production 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 second half of 2009, the wells together contributed over 700 BOE per day (net) to 2009 average production and they continue to produce at a combined rate of over 550 BOE per day (net).

The Company's average production for the fourth quarter of 2009 was 17% lower than the comparable period in 2008. The average production for the fourth quarter of 2008 included flush production from two wells that came on production in October 2008 at a combined initial production rate of approximately 550 BOE per day (net).

The Company's average production for the fourth quarter of 2009 was 2,065 BOE per day, a decrease of 13% over the third quarter average production of 2,381 BOE per day. Average production for the fourth quarter of 2009 was lower than the preceding third quarter primarily due to a plant turnaround during October 2009, which affected the Kakwa, Chime and Musreau areas, as well as natural declines.



PRICES

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Three Months Ended December 31, Year Ended December 31,
2009 2008 Change 2009 2008 Change
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% %
Natural gas ($/Mcf) 4.56 6.91 (34) 3.86 8.41 (54)
Liquids($/Bbl) 61.92 48.35 28 50.10 84.34 (41)
Equivalence ($/BOE) 30.61 42.06 (27) 25.55 54.64 (53)
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Natural gas prices were 34% lower in the fourth quarter of 2009 compared to the same quarter of 2008 and 54% lower year over year. The decrease in average realized prices is consistent with the decline in natural gas prices that began in late 2008 and continued through most 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 28% higher in the fourth quarter of 2009 compared to the same quarter of 2008 but 41% lower year over year. The decrease in average realized prices from the previous year is consistent with the decline in oil and natural gas liquids prices. The Company has not hedged any of its liquids production.

Natural gas and natural gas liquids pricing increased 59% and 23%, respectively, from the third quarter of 2009 as prices began to recover during the fourth quarter of 2009 in response to improvements in, and a stabilization of, the economic climate as well as an improved outlook for commodity prices.



REVENUE

Dollars in thousands, except per unit amounts
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Three Months Ended December 31, Year Ended December 31,
2009 2008 Change 2009 2008 Change
----------------------------------------------------------------------------
$ $ % $ $ %
Petroleum and
natural gas sales,
net of transportation 5,815 9,679 (40) 22,141 40,624 (45)
Per BOE 30.61 42.06 (27) 25.55 54.64 (53)
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Revenue for the year ended December 31, 2009 was 45% lower than the prior year, and 53% lower on a BOE basis. This decrease is consistent with the significant decrease in commodity prices, which was partially offset by increased production.

Revenue for the three months ended December 31, 2009 was 40% lower than the same period of 2008, as a result of a decrease in both production and commodity prices.

Revenue for the fourth quarter of 2009 was 32% higher than the previous quarter which was consistent with increased commodity prices during the fourth quarter, partially offset by decreased production.

Transportation expenses were approximately $0.19 per BOE lower for the year ended December 31, 2009 compared to 2008. This decrease is the result of an increased proportion of the Company's production coming from British Columbia, which is subject to lower transportation fees.



ROYALTIES

Dollars in thousands, except per unit amounts
----------------------------------------------------------------------------
Three Months Ended December 31, Year Ended December 31,
2009 2008 Change 2009 2008 Change
----------------------------------------------------------------------------
$ $ % $ $ %
Royalties 1,311 2,542 (48) 4,347 10,324 (58)
Per BOE 6.90 11.05 (38) 5.02 13.89 (64)
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Royalty expense decreased during the three months and year ended December 31, 2009 compared to the same periods of 2008 due to lower revenue, as well as a result of some of the new producing wells being eligible for royalty holidays. The royalty rate (crown royalties and gross overriding royalties as a percentage of oil and gas sales) for the year ended 2009 was approximately 20%, or 5% lower than the previous year. The decreased royalty rate in 2009 reflects the impact of the New Royalty Framework ("NRF"), which became effective on January 1, 2009 in Alberta. Under this new program, the low natural gas prices experienced throughout 2009 have resulted in a lower corporate royalty rate. As natural gas prices increase, the corporate royalty rate is expected to increase.

Royalties of $1.3 million recorded during the fourth quarter of 2009 were higher than royalties of $720 thousand recorded during the third quarter of 2009, due to increased revenue in the fourth quarter. As natural gas prices increase, the corporate royalty rate also increases resulting in a higher royalty expense.



OPERATING EXPENSES

Dollars in thousands, except per unit amounts
----------------------------------------------------------------------------
Three Months Ended December 31, Year Ended December 31,
2009 2008 Change 2009 2008 Change
----------------------------------------------------------------------------
$ $ % $ $ %
Operating 531 1,225 (57) 3,020 4,336 (30)
Per BOE 2.80 5.32 (47) 3.49 5.83 (40)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Operating expenses decreased 30% for the year ended December 31, 2009 compared to the prior year primarily due to a gas processing credit received from the Alberta Government under the NRF, as well as lower compressor and equipment maintenance, and decreased gas processing fees. On a per BOE basis, operating expenses were 40% lower compared to 2008 mostly attributable to lower operating costs year over year, as well as increased production and increased operational efficiencies in 2009.

Operating expenses in the fourth quarter of 2009 decreased 57% from the same quarter of 2008 due to the factors discussed above. On a per BOE basis, operating expenses for the fourth quarter were 47% lower compared to the fourth quarter of 2008, primarily due to a gas processing credit received in 2009.

Total operating expenses for the fourth quarter of 2009 were 20% lower compared to the third quarter, mostly due to lower variable costs attributable to lower production volumes in the fourth quarter.

The Company forecasted operating expenses to average $4.00 per BOE for the year. The lower operating expenses per BOE from the prior year and from previous projections are a result of adjustments to the gas processing credit received in 2009, as well as the low operating costs associated with Kiskatinaw production, which requires minimal processing. Kiskatinaw production was higher in 2009 compared to the prior year, as well as higher than forecasted, which resulted in lower operating costs per BOE.

For 2010, the Company is forecasting operating costs of approximately $4.55 per BOE as the production from Kiskatinaw wells, which has lower operating costs, declines and as new production may require processing through third party facilities. 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
----------------------------------------------------------------------------
Three Months Ended December 31, Year Ended December 31,
2009 2008 Change 2009 2008 Change
----------------------------------------------------------------------------
$ $ % $ $ %
General and
administrative 1,768 1,330 33 4,705 4,013 17
Per BOE 9.31 5.78 61 5.43 5.40 1
----------------------------------------------------------------------------
----------------------------------------------------------------------------


General and administrative expenses for the year ended December 31, 2009 were $700 thousand higher than the prior year, and $800 thousand higher than the previous quarter, primarily due to costs associated with the retirement of Cinch's Chief Executive Officer on November 12, 2009, as well as salary increases for the year. The general and administrative costs per BOE were consistent with the prior year, as the increased costs were offset by increased production; however, they were greater than the Company's previous forecast of $4.50 per BOE due to the costs associated with the retirement of Cinch's Chief Executive Officer, as discussed above and costs associated with the Company's short term incentive program.

Total general and administrative expenses for the three months ended December 31, 2009, increased 33% compared to the same period of 2008, primarily due to the costs associated with the retirement of Cinch's Chief Executive Officer, as discussed above. On a per BOE basis, general and administrative expenses increased 61% from the same quarter of the previous year primarily due to the above noted retirement costs and that, coupled with the lower production, resulted in a significant increase in general and administrative costs per BOE.

General and administrative expenses for 2010 are expected to be approximately $5.50 per BOE, due to a slight increase in forecasted general and administrative expenses, partially offset by higher anticipated production.

As at March 5, 2010, the Company has 6,569,500 options outstanding, amounting to approximately 8% of the 81,433,666 outstanding common shares. The Company does not capitalize any indirect general and administrative expenses.



INTEREST EXPENSE

Dollars in thousands, except per unit amounts
----------------------------------------------------------------------------
Three Months Ended December 31, Year Ended December 31,
2009 2008 Change 2009 2008 Change
----------------------------------------------------------------------------
$ $ % $ $ %
Interest expense 256 327 (22) 1,077 1,160 (7)
Per BOE 1.35 1.42 (5) 1.24 1.56 (21)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Interest expense was 7% lower during the year ended December 31, 2009 compared to 2008 due to lower average interest rates during 2009, which more than offset the higher average credit facility balance in 2009.

Interest expense during the three months ended December 31, 2009 decreased 13% from the previous quarter and 22% compared to the same period of 2008 primarily due to lower draws on the Company's bank credit facility.

In April 2009, the Company increased its revolving demand bank credit facility from $40 million to $43 million. The facility bears interest at the lender's prime rate plus 1.70%. The credit facility is subject to review in April 2010.

The Company exited the year with an outstanding credit facility balance of $26.5 million on its $43 million credit facility (December 31, 2008 - $28.4 million). With the closing of the $37.1 million equity financing in January 2010, the Company's credit facility balance has been reduced to nil and the Company has positive working capital.



ACCRETION OF ASSET RETIREMENT OBLIGATIONS EXPENSE

Dollars in thousands, except per unit amounts
----------------------------------------------------------------------------
Three Months Ended December 31, Year Ended December 31,
2009 2008 Change 2009 2008 Change
----------------------------------------------------------------------------
$ $ % $ $ %
Accretion expense 59 52 13 225 193 17
Per BOE 0.31 0.22 41 0.26 0.26 -
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Accretion expense increased during the three months and year ended December 31, 2009 compared to the same periods of 2008 due to an increase in the number of wells with asset retirement obligations. The accretion expense in the fourth quarter of 2009 was consistent with the previous quarter.



DEPLETION AND DEPRECIATION EXPENSE

Dollars in thousands, except per unit amounts
----------------------------------------------------------------------------
Three Months Ended December 31, Year Ended December 31,
2009 2008 Change 2009 2008 Change
----------------------------------------------------------------------------
$ $ % $ $ %
Depletion and
depreciation 4,021 5,667 (29) 20,892 18,544 13
Per BOE 21.16 24.63 (14) 24.11 24.94 (3)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Total depletion and depreciation expense for the year ended December 31, 2009 increased 13% compared to 2008 due to higher production volumes, partially offset by reserve additions for 2009. On a per BOE basis, the expense for the year was consistent with the previous year.

The depletion and depreciation expense for the fourth quarter of 2009 decreased 29% compared to the fourth quarter of 2008 primarily due to 2009 reserve additions, as well as lower production volumes in the fourth quarter of 2009, partially offset by a larger depletion base. On a per BOE basis, the expense for the fourth quarter of 2009 was lower than the same period of 2008 primarily due to the reserve additions.

The decrease in the expense from the previous quarter is mostly attributable to the reserve additions for 2009.



TAXES

Dollars in thousands, except per unit amounts
----------------------------------------------------------------------------
Three Months Ended December 31, Year Ended December 31,
2009 2008 Change 2009 2008 Change
----------------------------------------------------------------------------
$ $ % $ $ %
Current - 4 (100) - 4 (100)
Future income
taxes expense
(recovery) (582) (10) - (3,170) 1,022 (410)
Per BOE (3.06) (0.03) - (3.66) 1.38 (365)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


A future income tax recovery was recorded in the three months and year ended December 31, 2009 consistent with the net loss experienced during those periods.



Tax Pools at December 31, 2009:

Dollars in thousands
----------------------------------------------------------------------------
2009 2008
$ $
----------------------------------------------------------------------------
COGPE 11,470 15,687
CDE 21,947 25,216
CEE 36,910 29,256
UCC 15,117 18,053
----------------------------------------------------------------------------
85,444 88,212
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The Company's tax pools decreased in 2009 due to asset dispositions of $4.6 million, net, in the fourth quarter of 2009.



NET INCOME (LOSS) AND FUNDS FROM OPERATIONS

In thousands, except per share figures
----------------------------------------------------------------------------
Three Months Ended December 31, Year Ended December 31,
2009 2008 Change 2009 2008 Change
----------------------------------------------------------------------------
$ $ % $ $ %
Net income (loss) (1,537) (1,435) (7) (8,904) 1,167 (863)
per basic share (0.03) (0.03) - (0.16) 0.02 (900)
per diluted share (0.03) (0.03) - (0.16) 0.02 (900)
----------------------------------------------------------------------------
Funds from operations 2,096 4,371 (52) 9,479 21,456 (56)
per basic share 0.04 0.08 (50) 0.17 0.39 (56)
per diluted share 0.04 0.08 (50) 0.17 0.38 (55)
----------------------------------------------------------------------------
Weighted average
shares outstanding 58,853 55,632 6 56,734 55,627 2
----------------------------------------------------------------------------
----------------------------------------------------------------------------


For the year ended December 31, 2009, the Company recorded a net loss of $8.9 million, compared to net income of $1.2 million for the year ended December 31, 2008, primarily attributable to lower realized commodity prices, partially offset by lower royalties and increased average production.

For the three months ended December 31, 2009, the Company incurred a net loss of $1.5 million primarily due to lower revenues and higher general and administrative expenses, partially offset by lower royalties and lower operating expenses compared to the same period of 2008.

The fourth quarter of 2009 was favorably impacted by an increase in realized commodity prices and, despite the decrease in the Company's production, revenue earned was higher compared to the third quarter of 2009. As a result, the Company's net loss for the fourth quarter of 2009 was lower than the previous quarter.

The Company's funds from operations for the three months and year ended December 31, 2009, decreased by 52% and 56%, respectively, over the same periods of 2008. Funds from operations in 2009 were lower due to decreased revenue primarily attributable to lower realized commodity prices, partially offset by increased production year over year. The substantial decline in commodity prices during the fourth quarter of 2008 and continuing throughout most of 2009 significantly impacted the Company's cash flows.



LIQUIDITY AND CAPITAL RESOURCES

Dollars in thousands
----------------------------------------------------------------------------
As at December 31,
2009 2008 Change
----------------------------------------------------------------------------
$ $ %
Working capital deficiency,
excluding credit facility (2,925) (6,950) (58)
Credit facility (26,519) (28,358) (6)
----------------------------------------------------------------------------
Net debt (29,444) (35,308) (17)
Shareholders' equity (78,658) (84,394) (7)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


At December 31, 2009, the Company had net debt of $29.4 million, comprised of a working capital deficiency of $2.9 million and an amount outstanding on its credit facility of $26.5 million. The $5.9 million decrease in net debt from December 31, 2008 can be attributed to funds from operations for the year ended December 31, 2009 of $9.5 million and $2.7 million in proceeds from a flow-through financing, partially offset by net capital expenditures of $6.3 million.

The fourth quarter funds from operations were $2.1 million, which is a $0.2 million increase from the third quarter funds from operations of $1.9 million. The increase in funds from operations, combined with net proceeds of $4.6 million received from asset dispositions in the fourth quarter, less capital expenditures of $5.1 million, resulted in the Company exiting 2009 with net debt of $29.4 million, a $1.6 million decrease from the third quarter net debt of $31.0 million.

On January 28, 2010, the Company issued, through a bought-deal financing, a total of 22,493,300 common shares at $1.65 per share for gross proceeds of $37,113,945. Net proceeds from the offering, which were used to temporarily reduce outstanding indebtedness, will be used primarily to fund the Company's 2010 capital program. As at March 5, 2010, there were no amounts outstanding under the Company's $43 million credit facility.

In April 2010, the revolving demand bank credit facility of $43 million is scheduled for review. The new borrowing base will be dependent on Company reserves and the price deck used along with other assumptions utilized by the bank in the course of their review.

The decrease in shareholder's equity of $5.7 million from December 31, 2008 to December 31, 2009 is primarily attributed to the net loss realized in 2009, partially offset by an increase in share capital resulting from the flow-through shares issued in August 2009.



CAPITAL EXPENDITURES

Additions to Property, Plant and Equipment

Dollars in thousands
----------------------------------------------------------------------------
Year Ended December 31,
2009 2008
----------------------------------------------------------------------------
$ $
Land and rentals 469 3,872
Seismic (133) 1,736
Drilling, completing and equipping 8,630 21,964
Pipelines and facilities 2,061 4,285
Other assets (56) 157
----------------------------------------------------------------------------
10,971 32,014
Property dispositions (net of acquisitions) (4,629) -
----------------------------------------------------------------------------
Total 6,342 32,014
----------------------------------------------------------------------------
----------------------------------------------------------------------------


During 2009, Cinch focused its exploration program in the Dawson area of British Columbia. The Company started the year with a capital budget of $15 million, which was later reduced to $10 million as a result of lower projected cash flows. Capital expenditures for the year ended December 31, 2009 included approximately $8.6 million of drilling and completion activities and $2.0 million relating to pipelines and facilities.

During the fourth quarter of 2009, the Company also entered into an asset swap with a joint venture partner, resulting in net dispositions of approximately $4.6 million. The transaction involved the disposition of assets in the Kakwa area and the acquisition of land rights in the Dawson area.

In 2010, the Company is planning an extensive capital program, both in the Dawson area of British Columbia and in the Chime and Kakwa areas of Alberta, with a capital budget of approximately $60 million based on estimated average commodity prices of CAD$5.50 per gigajoule based on AECO for natural gas and US$80 per barrel based on WTI for natural gas liquids. The Company plans to fund its 2010 capital program from cash flows as well as funds available through the Company's credit facility and will adjust the program accordingly depending on commodity prices and cash flows generated.

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. Cinch attempts to reduce risk in accomplishing these goals through the combination of hiring experienced and knowledgeable personnel and careful evaluation of drilling opportunities.

The wells the Company drills tend to be deep and are subject to higher drilling costs than those in more shallow areas. Furthermore, most wells require fracture treatment before they are capable of production, which also increases 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 by drilling deep so that the multi-zone potential of the area can be accessed and potentially developed. 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.

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 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 always the operator and therefore not all operational issues are within its control. Management will address them nonetheless, and attempt to implement solutions, which may be longer term by their nature.

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'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.

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.

Royalties

Cinch's production is generated from properties within the provinces of Alberta and British Columbia. As a result, a significant portion of Cinch's production is subject to Crown royalties, which are affected directly by the Alberta and British Columbia government royalty programs. Crown royalty rates are subject to change and a change may have a significant impact on Cinch's cash flow.

The Alberta Government revised its royalty program in 2009 and issued several amendments to the program throughout the year which have been favorable to Cinch, however, there is a risk that future amendments to the program could have a non-favorable impact on the Company.

Global Financial Situation

Recent market events and conditions, including disruptions in the international credit markets and other financial systems and the deterioration of global economic conditions, have caused significant volatility to financial markets. These conditions have continued through 2009 and are expected to continue into 2010. Notwithstanding various actions by governments, concerns about the general condition of the capital markets, financial instruments, banks, investment banks, insurers and other financial institutions continue. These factors have negatively impacted company valuations and will impact the performance of the global economy going forward.

During 2009, Cinch experienced a significant decrease in cash flows from the previous year due to the substantial decrease in realized commodity prices. 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 Company's recent financing in January 2010 enhances its 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 may be 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.
On January 28, 2010, the Company completed an equity financing, raising net proceeds of $35 million. As a result, the Company expects to have sufficient funds for its 2010 capital program.

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 the 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 new 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.

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. Such officers have evaluated, or caused to be evaluated under their supervision, the effectiveness of the Company's disclosure controls and procedures at the financial year end of the Company and have concluded that the Company's disclosure controls and procedures are effective at the financial year end of the Company for the foregoing purposes.

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 control over financial reporting. Such officers have evaluated, or caused to be evaluated under their supervision, the effectiveness of the Company's internal control over financial reporting at the financial year end of the Company and have concluded that such internal control over financial reporting is effective, at the financial year end of the Company, 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 herein any change in the Company's internal control over financial reporting that occurred during the period beginning on October 1, 2009 and ended on December 31, 2009 that has materially affected, or is reasonably likely to materially affect, the Company's internal control over financial reporting. No material changes in the Company's internal control over financial reporting were identified during such period that have materially affected, or are reasonably likely to materially affect, the Company's internal control 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. These commitments relate entirely to the Company's office lease.



Dollars in thousands
----------------------------------------------------------------------------
Payments
less than 1-3 4-5 greater than
Total 1 year years years 5 years
$ $ $ $ $
----------------------------------------------------------------------------
Operating lease 1,205 236 483 486 -
----------------------------------------------------------------------------
1,205 236 483 486 -
----------------------------------------------------------------------------
----------------------------------------------------------------------------


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 were used to fund the drilling of the Dawson 6-30 Wabamun well. In February 2010, the Company renounced $2,730,115 of Canadian exploration expenditures to the flow-through investors effective December 31, 2009. As at December 31, 2009, the Company had incurred all required expenditures and therefore had no further obligations.

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 EIC Abstract 173 did not impact the Company's financial position.

RECENT ACCOUNTING PRONOUNCEMENTS

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

International Financial Reporting Standards ("IFRS")

On February 13, 2008, the Canadian Accounting Standards Board ("AcSB") confirmed the use of 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. 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 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.

During 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 also assessed the impact the changeover will have on current policies and procedures, information technology and accounting systems, as well as internal controls. The Company has substantially completed the design and planning phase and has commenced the solution development phase.

The solution development phase involves the selection and documentation of IFRS accounting policies and procedures, as well as the development of accounting systems to enable the Company to track and report the financial information required to prepare financial statements under IFRS. The Company has selected some of its IFRS accounting policies, however, these may change as the Company progresses through the solution development phase. The Company's accounting system provider has recently released an IFRS module to facilitate Cinch's IFRS reporting.

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. Under this exemption, companies are required to measure decommissioning, restoration and similar liabilities as at the date of transition in accordance with IAS 37, and recognize directly in retained earnings any difference between that amount and the carrying amount of those liabilities at the date of transition to IFRS determined under Canadian GAAP. 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 also anticipates utilizing the following exemptions:

- IFRS 3 Business Combinations will not be applied to acquisitions of subsidiaries or of interests in associates and joint ventures that occurred before January 1, 2010, the Company's transition date.

- IFRS 2 Share-based Payment will not be applied to equity instruments granted after November 7, 2002 that vested before January 1, 2010.

- The Company will apply the transitional provision in IFRIC 4 Determining whether an Arrangement contains a Lease and will assess all arrangements as at the date of transition.

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 its peers, and will update its plans as necessary.

Business Combinations

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, and historical and industry experience.

Cost Estimates

Costs for services performed but not 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

The Company's financial position, results of operations and cash flows are significantly impacted by commodity price variations. Decreases in commodity prices impact the Company by reducing cash flows available for exploration and challenges the economics of potential capital projects.

During the first half of 2008, commodity prices were significantly increased from previous years, with natural gas prices at levels that had not been seen since late 2005, and natural gas liquids and oil prices reaching all time highs. In the latter half of 2008, global commodity prices declined resulting in a decrease in revenues, as well as a decrease in cash flows available to fund the Company's capital program. The softening market continued throughout most of 2009, until the fourth quarter, when commodity prices began to stabilize with the first signs of economic recovery. Despite the improved market confidence in the fourth quarter, commodity prices, particularly the price of natural gas, continue to remain well below levels experienced in early 2008. As a result, the revenue and cash flows generated by the Company in 2009 were significantly lower than the previous year.

The Company has made great strides in building a stable production base, and continues to work on achieving growth. In 2008, the Company had a very active capital program, which resulted in a significant increase in production, from 1,579 BOE per day in the first quarter to an exit rate of 2,501 BOE per day. In the fourth quarter of 2008, two new Dawson wells came on production, which significantly increased production. In 2009, the Company had a more conservative capital budget, which resulted in a decrease in production in the final quarter of 2009 compared to the fourth quarter of 2008. Even with its conservative budget, the Company was able to increase its 2009 production by 17% over 2008.

The Company's capital program is dependent on cash flows generated by operations and access to capital markets. In 2008, Cinch generated $21 million of cash flows and therefore was able to fund a significant capital budget. Cinch's 2009 capital budget was significantly lower than the previous year due to the decrease in cash flows. In 2010, the Company is planning an active capital program in the Dawson, Chime and Kakwa areas, which will further increase production.



SELECTED ANNUAL AND QUARTERLY INFORMATION
(000's, except per share and production data)

Q1 Q2 Q3 Q4 Annual
----------------------------------------------------------------------------
2009 $ $ $ $ $
----------------------------------------------------------------------------
Petroleum and natural gas sales,
net of transportation and
before royalties 6,709 5,214 4,403 5,815 22,141
Funds from operations 2,960 2,569 1,854 2,096 9,479
Per share - basic 0.05 0.05 0.03 0.04 0.17
- diluted 0.05 0.05 0.03 0.04 0.17
Net income (loss) (2,014) (2,553) (2,801) (1,537) (8,904)
Per share - basic (0.04) (0.05) (0.05) (0.03) (0.16)
- diluted (0.04) (0.05) (0.05) (0.03) (0.16)
Capital expenditures 3,673 (150) 2,301 518 6,342
Total assets 136,450 130,128 126,715 124,872 124,872
Working capital (net debt) (36,021) (33,302) (31,040) (29,444) (29,444)
----------------------------------------------------------------------------
Production (BOE/d) 2,438 2,616 2,381 2,065 2,374
----------------------------------------------------------------------------
2008 $ $ $ $ $
----------------------------------------------------------------------------
Petroleum and natural gas sales,
net of transportation and
before royalties 8,137 12,676 10,132 9,679 40,624
Funds from operations 4,130 7,320 5,635 4,371 21,456
Per share - basic 0.07 0.13 0.10 0.08 0.39
- diluted 0.07 0.13 0.10 0.08 0.38
Net income (loss) 17 1,810 774 (1,435) 1,167
Per share - basic 0.00 0.03 0.01 (0.03) 0.02
- diluted 0.00 0.03 0.01 (0.03) 0.02
Capital expenditures 8,532 4,584 12,212 6,685 32,014
Total assets 130,566 132,156 142,147 141,330 141,330
Working capital (net debt) (29,160) (26,424) (32,994) (35,308) (35,308)
----------------------------------------------------------------------------
Production (BOE/d) 1,579 1,991 2,049 2,501 2,031
----------------------------------------------------------------------------
2007 $ $ $ $ $
----------------------------------------------------------------------------
Petroleum and natural gas sales,
net of transportation and
before royalties 6,116 5,582 4,405 6,588 22,691
Funds from operations 3,371 2,589 1,605 3,217 10,782
Per share - basic 0.06 0.05 0.03 0.06 0.20
- diluted 0.06 0.05 0.03 0.06 0.20
Net income (loss) (268) (709) (15,184) 466 (15,695)
Per share - basic (0.01) (0.01) (0.27) 0.01 (0.29)
- diluted (0.01) (0.01) (0.27) 0.01 (0.29)
Capital expenditures 6,228 3,930 7,851 2,917 20,926
Total assets 136,520 134,834 125,730 125,682 125,682
Working capital (net debt) (17,264) (18,673) (24,987) (24,758) (24,758)
----------------------------------------------------------------------------
Production (BOE/d) 1,354 1,249 1,208 1,549 1,340
----------------------------------------------------------------------------
Note: numbers may not cross-add due to rounding


Financial Statements

Cinch Energy Corp.

December 31, 2009 and 2008

AUDITORS' REPORT

To the Shareholders of Cinch Energy Corp.

We have audited the balance sheets of Cinch Energy Corp. as at December 31, 2009 and 2008 and the statements of operations and deficit and cash flows for the years then ended. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with Canadian generally accepted auditing standards. Those standards require that we plan and perform an audit to obtain reasonable assurance whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.

In our opinion, these financial statements present fairly, in all material respects, the financial position of the Company as at December 31, 2009 and 2008 and the results of its operations and its cash flows for the years then ended in accordance with Canadian generally accepted accounting principles.

Ernst & Young, Chartered Accountants

Calgary, Canada

March 5, 2010



CINCH ENERGY CORP.
BALANCE SHEETS

As at December 31, 2009 2008
$ $
----------------------------------------------------------------------------

ASSETS (note 6)

Current
Accounts receivable (notes 4 and 13) 3,872,925 5,902,432
Prepaid expenses and deposits 1,236,359 1,088,325
----------------------------------------------------------------------------
5,109,284 6,990,757

Property, plant and equipment (note 5) 119,762,409 134,339,477
----------------------------------------------------------------------------

124,871,693 141,330,234
----------------------------------------------------------------------------
----------------------------------------------------------------------------

LIABILITIES AND SHAREHOLDERS' EQUITY

Current
Accounts payable and accrued liabilities (note
13) 8,034,501 13,940,693
Credit facility (notes 6 and 13) 26,519,080 28,358,033
----------------------------------------------------------------------------
34,553,581 42,298,726

Asset retirement obligations (note 8) 4,035,866 3,838,337

Future income taxes (note 9) 7,623,800 10,798,800
----------------------------------------------------------------------------

46,213,247 56,935,863
----------------------------------------------------------------------------
Commitments (note 12)

Shareholders' equity
Share capital (note 11) 99,299,173 96,560,099
Contributed surplus (note 11) 4,003,427 3,574,439
Deficit (24,644,154) (15,740,167)
----------------------------------------------------------------------------

78,658,446 84,394,371
----------------------------------------------------------------------------

124,871,693 141,330,234
----------------------------------------------------------------------------
----------------------------------------------------------------------------

See accompanying notes

On behalf of the Board:


John W. Elick William D. Robertson
Director Director


CINCH ENERGY CORP.

STATEMENTS OF OPERATIONS AND DEFICIT

For the years ended December 31, 2009 2008
$ $
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Revenue
Oil and gas sales 23,645,561 42,056,496
Transportation (1,504,934) (1,432,877)
Royalties (4,347,143) (10,323,932)
Other income 51,370 139,423
----------------------------------------------------------------------------

17,844,854 30,439,110
----------------------------------------------------------------------------

Expenses
Operating 3,020,202 4,336,167
General and administrative (note 11) 4,704,827 4,013,491
Interest on credit facility 1,077,222 1,130,547
Interest on capital lease (note 7) - 29,943
Accretion of asset retirement obligations
(note 8) 224,523 192,794
Depletion and depreciation 20,891,667 18,543,520
----------------------------------------------------------------------------

29,918,441 28,246,462
----------------------------------------------------------------------------

Income (loss) before income taxes (12,073,587) 2,192,648

Taxes (note 9)
Current income tax expense - 3,921
Future income tax expense (recovery) (3,169,600) 1,022,000
----------------------------------------------------------------------------

(3,169,600) 1,025,921
----------------------------------------------------------------------------

Net income (loss) and comprehensive income
(loss) for the year (8,903,987) 1,166,727

Deficit, beginning of year (15,740,167) (16,906,894)
----------------------------------------------------------------------------

Deficit, end of year (24,644,154) (15,740,167)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Net income (loss) and comprehensive income
(loss) for the year per share (note 11)

Basic and diluted (0.16) 0.02
----------------------------------------------------------------------------
----------------------------------------------------------------------------

See accompanying notes

CINCH ENERGY CORP.

STATEMENTS OF CASH FLOWS

For the years ended December 31, 2009 2008
$ $
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Operating activities
Net income (loss) for the year (8,903,987) 1,166,727
Add (deduct) non-cash items:
Depletion and depreciation 20,891,667 18,543,520
Accretion of asset retirement obligations 224,523 192,794
Non-cash compensation expense (note 11) 436,821 531,006
Future income tax expense (recovery) (3,169,600) 1,022,000
----------------------------------------------------------------------------
9,479,424 21,456,047
Net change in non-cash working capital (1,975,818) 1,040,114
----------------------------------------------------------------------------
Cash provided by operating activities 7,503,606 22,496,161
----------------------------------------------------------------------------

Investing activities
Additions to property, plant and equipment (10,971,263) (32,013,808)
Dispositions (net of acquisitions) of property,
plant and equipment 4,629,670 -
Net change in non-cash working capital (2,048,901) 2,025,622
----------------------------------------------------------------------------

Cash used in investing activities (8,390,494) (29,988,186)
----------------------------------------------------------------------------

Financing activities
(Decrease) increase in credit facility (1,838,953) 7,768,671
Issue of common shares, net of issue costs 2,725,841 7,466
Payments on capital lease - (284,112)
----------------------------------------------------------------------------

Cash provided by financing activities 886,888 7,492,025
----------------------------------------------------------------------------

Change in cash - -

Cash, beginning of year - -
----------------------------------------------------------------------------

Cash, end of year - -
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Supplemental information:
Cash taxes paid - 3,921
Cash interest paid 1,077,222 1,160,490
----------------------------------------------------------------------------
----------------------------------------------------------------------------

See accompanying notes


CINCH ENERGY CORP.

NOTES TO FINANCIAL STATEMENTS

December 31, 2009 and 2008

1. DESCRIPTION OF BUSINESS

Cinch Energy Corp. (the "Company") was incorporated under the laws of the Province of Alberta and commenced operations on December 1, 2001. The Company's activities are comprised of the exploration for and development of oil and natural gas properties, primarily in Western Canada.

2. SIGNIFICANT ACCOUNTING POLICIES

These financial statements, which have been prepared in accordance with Canadian generally accepted accounting principles, have, in management's opinion, been properly prepared within reasonable limits of materiality and within the framework of the accounting policies summarized below.

Property, plant and equipment

Petroleum and natural gas properties

The Company follows the full cost method of accounting for its petroleum and natural gas activities, whereby all costs associated with the exploration for and development of petroleum and natural gas reserves, whether productive or non-productive, are capitalized in a single Canadian cost center and charged to income as set out below. Such costs can include lease acquisition, drilling, geological and geophysical, and equipment costs, and overhead expenses directly related to exploration and development activities. Proceeds from disposal of properties will normally be applied as a reduction of the cost of the remaining assets, except when such a disposal would alter the depletion rate by more than 20 percent, in which case a gain or loss will be recorded.

Ceiling test

The net carrying value of the Company's petroleum and natural gas properties is limited to an ultimate recoverable amount. The Company tests for impairment by comparing the carrying value of petroleum and natural gas properties to the undiscounted future net revenue from proved reserves using expected future prices and costs. Impairment is recognized when the carrying value of the assets is greater than the undiscounted future net revenue, in which case the assets are written down to the fair value of proved plus probable reserves plus the cost of unproved properties, net of impairment allowances. Fair value is determined based on discounted future net cash flows calculated using expected future prices and costs as well as the income tax legislation in effect at the period end. The discount rate used is a risk free interest rate.

Depletion

Depletion of petroleum and natural gas properties and related production equipment is provided on accumulated costs using the unit of production method based on estimated gross proven petroleum and natural gas reserves, before royalties, as determined by independent reservoir engineers. For purposes of the depletion calculation, proven petroleum and natural gas reserves are converted to a common unit of measure on the basis that six thousand cubic feet of natural gas is equivalent to one barrel of petroleum.

The depletion cost base includes total capitalized costs, less the cost of unproven properties, plus the estimated future development costs associated with proven undeveloped reserves.

The carrying value of undeveloped properties is reviewed periodically. The excess of carrying value of undeveloped properties over their fair value is added to costs subject to depletion.

Office furniture and equipment

Office furniture and equipment is carried at cost and depreciated on a straight-line basis over the assets' estimated useful lives at a rate of 25% per annum.

Leases

Leases are classified as either capital or operating in nature. Capital leases are those that transfer substantially all the benefits and risks of ownership to the lessee. Assets acquired under capital leases are depleted along with the petroleum and natural gas properties. Obligations recorded under capital leases are reduced by the principal portion of lease payments as incurred and the imputed interest portion of capital lease payments is charged to expense and amortized straight-line over the life of the lease. Operating lease payments are charged to expense.

Asset retirement obligations

The Company recognizes the fair value of a liability for an asset retirement obligation and a corresponding increase in the carrying value of the related long-lived asset in the period in which they are constructed or acquired. The fair value of the obligation is management's best estimate of the cost to retire the asset based on current legislation and industry practice. The increase in the carrying value of the asset is amortized on a unit of production basis consistent with the method used to record depletion on the Company's petroleum and natural gas properties. The liability is subsequently adjusted for the passage of time, which is recognized as accretion expense in the statements of operations and deficit. The liability is periodically adjusted for revisions in either the timing or the amount of the original estimated cash flows associated with the obligation. Actual costs incurred upon settlement of the obligations are charged against the liability.

Measurement uncertainty

The amounts recorded for depletion of petroleum and natural gas properties, the provision for asset retirement obligations, and the ceiling test calculation are based on estimates of proven or proven and probable reserves, production rates, petroleum and natural gas prices, future costs and other relevant assumptions. By their nature, these estimates are subject to measurement uncertainty and the effect on the financial statements of changes in such estimates in future periods could be significant.

The measurement of future income tax balances is subject to uncertainty relating to the timing of the reversal of temporary differences, which are based on estimates of the recoverability of oil and gas reserves, commodity prices, the timing of future cash flows and changes in legislation and tax rates. By their nature, these estimates are subject to measurement uncertainty and the effect on the financial statements of changes of estimates in future periods could be significant.

Joint operations

Substantially all of the Company's exploration and development activities are conducted jointly with others and, accordingly, the financial statements reflect only the Company's proportionate interest in such activities.

Flow-through shares

The Company occasionally finances a portion of its exploration and development activities through the issuance of flow-through shares. Under the terms of a flow-through share issuance, the tax attributes of the related expenditures are renounced to subscribers. To recognize the foregone tax benefits to the Company, share capital is reduced and future income taxes are increased by the tax effect of the tax benefits renounced to subscribers at the time the renouncement is filed with the tax authorities, provided there is reasonable assurance that the expenditures will be made.

Income taxes

The Company follows the liability method of accounting for income taxes. Under this method, the Company records future income taxes for the difference between the financial statement carrying value and the income tax basis of an asset or liability. Future income tax assets and liabilities are measured using substantively enacted income tax rates and laws that are expected to apply in the periods in which differences are anticipated to reverse. The effect on future income tax assets and liabilities of a change in tax rates is recognized in the statements of operations and deficit in the period in which the change is substantively enacted.

Revenue recognition

Revenue from the sale of petroleum and natural gas and related products is recognized when title passes.

Stock-based compensation

The Company has a stock-based compensation plan, which is described in note 11. The Company has adopted the fair value based method of accounting for stock options. Stock option expense is recorded as a general and administrative expense for all options with a corresponding increase recorded to contributed surplus. The fair value of options granted is estimated at the date of grant using the Black-Scholes valuation model. Consideration paid by option holders on the exercise of stock options is credited to share capital. At the time of exercise, the related amounts previously credited to contributed surplus are also transferred to share capital. In the event that vested options expire without being exercised, previously recognized compensation costs associated with such stock options are not reversed.

Per share information

Per share information is calculated using the treasury stock method. Under this method, the diluted weighted average number of common shares is calculated assuming that the proceeds from the exercise of outstanding and in-the-money options are used to purchase common shares at the estimated average market price for the period.

Financial instruments

The Company's financial instruments consist of accounts receivable, accounts payable and accrued liabilities and bank indebtedness. The Company records its financial instruments at their respective carrying values as there is no significant difference between the carrying values and the estimated fair values of these amounts given their short terms to maturity.

The Company does not use derivative financial instruments to manage its exposure to commodity price fluctuations.

3. CHANGES IN ACCOUNTING POLICIES

Credit risk and fair value of financial assets and financial liabilities

Effective January 1, 2009, the Company adopted the recommendations of the Emerging Issues Committee ("EIC") of the Canadian Institute of Chartered Accountants ("CICA"), Abstract 173, "Credit Risk and the Fair Value of Financial Assets and Financial Liabilities." EIC Abstract 173 establishes standards concerning the measurement of financial assets and financial liabilities. The adoption of EIC Abstract 173 did not affect the Company's financial position.

Effective December 31, 2009, the Company adopted the amendments to CICA Handbook Section 3862, "Financial Instruments - Disclosures." The amendments include enhanced disclosures relating to the fair value of financial instruments. Section 3862 now requires that all financial instruments measured at fair value be categorized into one of three hierarchy levels. The amendments are consistent with recent amendments to financial instrument disclosure standards under International Financial Reporting Standards ("IFRS"). The adoption of these amendments had no impact on the financial statements of the Company since it does not have any financial instruments measured at fair value.

Future accounting changes

On February 13, 2008, the Canadian Accounting Standards Board ("AcSB") confirmed the use of 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. While IFRS uses a conceptual framework similar to GAAP, there are significant differences in accounting policies that must be addressed.

The Company has assessed the effects of the adoption of IFRS by comparing differences between GAAP and IFRS. It has determined that the areas of highest potential impact will be the accounting for exploration and evaluation of oil and gas resources, accounting for property, plant, and equipment, as well as asset impairment testing and income taxes. The Company has evaluated the different accounting policy options available under IFRS and assessed the impact the changeover will have on current policies and procedures, information technology, accounting systems and internal controls and is in the process of determining which IFRS accounting policies are most appropriate for the Company. At this time, the impact of these changes to the Company's financial position and results of operations cannot be reasonably determined or estimated for any of the IFRS conversion impacts identified. The Company will continue to monitor any changes in the adoption of IFRS, as well as continue to assess the impact of these new standards on its financial statements.

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, 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 purchase price used is based on the market price of the shares for a reasonable period before and after the date of 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 income 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 income, unlike the current requirement to eliminate it by deducting it from non-current assets in the purchase price allocation. Section 1582 is effective January 1, 2011.

4. ACCOUNTS RECEIVABLE

A substantial portion of the Company's accounts receivable is with oil and gas marketing entities. The Company generally extends unsecured credit to these companies, and therefore, the collection of accounts receivable may be affected by changes in economic or other conditions and may accordingly impact the Company's overall credit risk. Management believes the risk is mitigated by the size, reputation and diversified nature of the companies to which they extend credit.

The Company has not previously experienced any material credit losses on the collection of receivables. Of the Company's significant individual accounts receivable at December 31, 2009, approximately 95% was owed from six customers (December 31, 2008 - 91% was owed from five customers). These customers are significant companies in the exploration and production industry and are considered to have high credit worthiness.

5. PROPERTY, PLANT AND EQUIPMENT





December 31, 2009
----------------------------------------------------------------------------
Accumulated
depletion and Net
Cost depreciation book value
$ $ $
----------------------------------------------------------------------------

Petroleum and natural gas
properties 202,016,932 (82,255,729) 119,761,203
Office furniture and equipment 276,308 (275,102) 1,206
----------------------------------------------------------------------------
202,293,240 (82,530,831) 119,762,409
----------------------------------------------------------------------------
----------------------------------------------------------------------------


December 31, 2008
----------------------------------------------------------------------------
Accumulated
depletion and Net
Cost depreciation book value
$ $ $
----------------------------------------------------------------------------

Petroleum and natural gas
properties 195,709,255 (61,376,728) 134,332,527
Office furniture and equipment 269,387 (262,437) 6,950
----------------------------------------------------------------------------
195,978,642 (61,639,165) 134,339,477
----------------------------------------------------------------------------
----------------------------------------------------------------------------


For the years ended December 31, 2009 and 2008, no indirect general and administrative expenditures were capitalized.

As at December 31, 2009, $8,002,048 of costs related to undeveloped lands were excluded from costs subject to depletion (December 31, 2008 - $10,597,987). As at December 31, 2009, the depletion calculation included future development costs of $44,719,000 (December 31, 2008 - $5,575,000).

The Company has performed a ceiling test as at December 31, 2009 using the estimated average price for each of the next five years as determined by the Company's independent reserve engineers adjusted for differentials specific to the Company's reserves and expected future realized commodity prices as follows:



Natural gas Light sweet crude oil
(AECO) (Edmonton par)
CDN $/mmbtu CDN $/bbl
----------------------------------------------------------------------------
2010 5.96 83.26
2011 6.79 86.42
2012 6.89 89.58
2013 6.95 92.74
2014 7.05 95.90
----------------------------------------------------------------------------
Each benchmark price increased on average approximately 2% from 2015 and
thereafter
----------------------------------------------------------------------------
----------------------------------------------------------------------------
There was no impairment at December 31, 2009.


6. CREDIT FACILITY

As at December 31, 2009, the Company had a demand bank credit facility through ATB Financial of $43,000,000 (December 31, 2008 - $40,000,000). The facility bears interest at the lender's prime rate plus 1.70%. The effective interest rate for the year ended December 31, 2009 was 3.78% (December 31, 2008 - 4.84%) and as at December 31, 2009, there was $26,519,080 drawn on the credit facility (December 31, 2008 - $28,358,033). As collateral for the facility, the Company has provided a general security agreement with the lender constituting a first ranking security interest in all personal property and a first ranking floating charge on all real property of the Company. As at December 31, 2009 and 2008, the Company was in compliance with the terms of this facility.

7. CAPITAL LEASE OBLIGATION

The Company was committed to annual minimum payments under a capital lease agreement, which commenced in December 2004 and concluded in December 2008.

For the year ended December 31, 2009, there was $nil (2008 - $29,943) recorded in interest expense relating to capital leases.

8. ASSET RETIREMENT OBLIGATIONS

The total future asset retirement obligations result from the Company's net ownership interest in wells and facilities. Management estimates the total undiscounted amount of future cash flows required to reclaim and abandon wells and facilities as at December 31, 2009 is $6,556,000 (December 31, 2008 -$6,352,000) with a weighted average abandonment date of 16 years (December 31, 2008 - 17 years). The Company used credit adjusted, risk-free rates ranging from 5% to 10% and an inflation rate of 2% to arrive at the recorded liability of $4,035,866 at December 31, 2009 (December 31, 2008 - $3,838,337). In 2009 and 2008, the estimated abandonment dates of some of the wells were revised and extended to better reflect the economic life of the wells, thereby reducing the present value of the liability. This resulted in a net reduction of $45,110 to the present value of the liability as at December 31, 2009 (December 31, 2008 - $4,000).

The Company's asset retirement obligations changed as follows:



December 31, 2009 December 31, 2008
$ $
----------------------------------------------------------------------------
Asset retirement obligations,
beginning of year 3,838,337 3,448,714
Revisions to estimates (45,110) (4,000)
Liabilities incurred 63,525 200,829
Liabilities settled (45,409) -
Accretion expense 224,523 192,794
----------------------------------------------------------------------------

Asset retirement obligations, end of
year 4,035,866 3,838,337
----------------------------------------------------------------------------
----------------------------------------------------------------------------


9. FUTURE INCOME TAXES

Income tax expense (recovery) differs from the amount that would be computed by applying the Federal and Provincial statutory income tax rates to income (loss) before income taxes. The reasons for the differences are as follows:




2009 2008
----------------------------------------------------------------------------
Statutory income tax rate 29.24% 29.61%
$ $
----------------------------------------------------------------------------
Anticipated income tax expense (recovery) (3,530,317) 649,243
Increase/(decrease) resulting from:
Stock-based compensation expense 127,726 157,231
Other 23 -
Non-deductible items 11,089 17,503
Rate adjustment 221,879 198,023
----------------------------------------------------------------------------

Future income tax expense (recovery) (3,169,600) 1,022,000
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Future income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts for income tax purposes. The components of the Company's future income tax assets and liabilities are as follows:



December 31, 2009 December 31, 2008
$ $
----------------------------------------------------------------------------
Net book value of capital assets in
excess of tax pools (8,820,792) (12,070,395)
Share issue costs 70,082 179,629
Asset retirement obligations 1,042,868 1,007,947
Other 84,042 84,019
----------------------------------------------------------------------------
Future income taxes (7,623,800) (10,798,800)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


10. CAPITAL DISCLOSURES

The Company's primary capital management objective is to maintain a strong balance sheet through the optimization of the debt and equity balance affording the Company financial flexibility to achieve goals of continued growth and access to capital. The capital structure of the Company consists of the credit facility and shareholders' equity comprised of retained earnings and share capital.

The basis for the Company's capital structure is dependent on the Company's expected business growth and changes in the business environment. The Company manages its capital structure and makes adjustments according to market conditions to maintain flexibility while achieving the objectives stated above. To manage the capital structure, the Company may adjust capital spending, issue new shares, issue new debt, or repay existing debt.

The Company monitors its capital structure based on the current and projected ratios of net debt to funds from operations. Net debt is the sum of the working capital (deficiency) and the outstanding credit facility balance. Funds from operations 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. Net debt to funds from operations is calculated as net debt divided by funds from operations. The Company's objective is to maintain a net debt to funds from operations ratio of less than two and a half times. The net debt to funds from operations ratio at December 31, 2009 was 3.11 (1.65 at December 31, 2008), which is in excess of the Company's stated objective. The ratio may increase or decrease at certain times because of significant events such as acquisitions or dispositions, as well as large fluctuations in commodity prices. The net debt to funds from operations ratio was significantly impacted by the reduced cash flows generated during the year ended December 31, 2009. The reduced cash flows were a direct result of the economic downturn and weakened commodity prices experienced throughout 2009. Efforts are made by management after a period of variation to bring the measure back in line. To facilitate the management of this ratio, the Company prepares annual budgets and monthly forecasts, which are updated depending on various factors such as general market conditions and successful capital deployment. The annual budget is approved by the Board of Directors.

The Company has some bank reporting requirements with respect to its credit facility that the Company has complied with for the year ended December 31, 2009. As collateral for the bank credit 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.

Other than the restrictions imposed for the bank credit facility, the Company is not subject to any externally imposed capital requirements.

The Company's capital management objectives, evaluation measures, and targets remain unchanged from the previous year.

11. SHARE CAPITAL

Authorized - Unlimited number of common voting shares without par value



December 31, 2009 December 31, 2008
----------------------------------------------------------------------------
Issued Number $ Number $
----------------------------------------------------------------------------
Common shares
Balance, beginning of year 55,631,798 96,560,099 55,625,132 99,175,434
Issued for cash on
flow-through private
placement (i) 3,211,900 2,730,115 - -
Tax effect of flow-through
shares (ii) - - - (2,626,000)
Exercise of stock options
(iii) 16,667 24,500 6,666 10,665
Issue costs, net of future
taxes of $5,400 (i) - (15,541) - -
----------------------------------------------------------------------------
Share capital, end of year 58,860,365 99,299,173 55,631,798 96,560,099
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Contributed surplus
Balance, beginning of year 3,574,439 3,046,632
Non-cash compensation expense
(iv) 436,821 531,006
Transfer to share capital
(iii) (7,833) (3,199)
----------------------------------------------------------------------------
Contributed surplus, end of
year 4,003,427 3,574,439
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Common shares

(i) 2009 Private placement

On August 26, 2009, the Company issued under private placement 3,211,900 flow-through common shares at $0.85 per share for proceeds of $2,730,115 before total issue costs of $20,941. As a result of the flow-through financing, the Company had a commitment to spend $2.7 million on qualifying Canadian exploration expenditures on or before December 31, 2010. As at December 31, 2009, the Company has fully satisfied this obligation. The expenditures were renounced to investors with an effective date of renunciation of December 31, 2009.

(ii) 2007 Private placement

On February 21, 2007, the Company issued under private placement 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 was required to incur such expenditures on or before December 31, 2008. As at December 31, 2008, the Company had incurred all required expenditures. The tax benefit of $2,626,000, related to the flow-through shares, was renounced in its entirety in January 2008.

(iii) Exercise of options

On November 12, 2009, 16,667 stock options were exercised for a total cash consideration of $16,667 (16,667 stock options at $1.00); this was recorded as an increase to share capital. Due to the exercise of the stock options, $7,833 has been transferred out of contributed surplus into share capital. This amount reflects the stock-based compensation expense that was previously recorded attributable to these options. During 2009, a total of $24,500 was recorded in share capital as a result of the stock options exercised.

(iv) Stock 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 outstanding during the year of 56,734,001 (2008 - 55,627,426). The diluted per share amounts for the year are calculated assuming the exercise of outstanding, in-the-money options, and future compensation costs to be incurred on outstanding options resulting in a weighted average number of common shares of 57,121,814 (2008 - 56,376,401). As at December 31, 2009, there were 1,895,000 outstanding, in-the-money options however these options are antidilutive due to the net loss recorded during the year and, therefore, are not included in the determination of dilutive per share amounts. For the year ended December 31, 2008, the diluted per share amount is calculated based on 3,071,167 outstanding, in-the-money options. Per share calculations that are anti-dilutive are not presented.

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 market 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:



2009 2008
Weighted Weighted
average average
Number of exercise Number of exercise
options price options price
----------------------------------------------------------------------------
$ $
Stock options outstanding,
beginning of year 5,509,833 1.51 5,365,834 1.69
Granted 1,050,000 0.81 930,000 0.72
Exercised (16,667) 1.00 (6,666) 1.12
Expired (587,000) 1.87 (371,000) 1.88
Forfeited (206,666) 1.63 (408,335) 1.77
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Stock options outstanding,
end of year 5,749,500 1.34 5,509,833 1.51
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Stock options outstanding at the end of the year are comprised of the following:



December 31, 2009
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Exercisable options
---------------------
Weighted average Number of Weighted
Number of remaining life exercisable average
Exercise price options (years) options price
----------------------------------------------------------------------------
$ $
0.70 -- 1.00 3,279,500 3.55 1,214,664 0.91
1.01 -- 1.50 760,000 1.76 751,666 1.24
1.51 -- 2.00 200,000 1.71 200,000 1.52
2.01 -- 2.50 890,000 1.05 890,000 2.24
2.51 -- 3.00 495,000 0.34 495,000 2.54
3.01 -- 3.50 125,000 0.67 125,000 3.30
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1.34 5,749,500 2.53 3,676,330 1.63
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The fair value of stock options granted to employees, directors, and consultants during the years ended December 31, 2009 and 2008, was estimated on the date of grant using the Black Scholes option pricing model with the following weighted average assumptions: dividend yield of zero percent (2008 - zero percent), expected volatility of 73.90 percent (2008 - 68.23 percent), risk-free interest rate of 2.27 percent (2008 - 2.29 percent), and an expected life of four years (2008 - four years). Outstanding options granted during the year ended December 31, 2009 had an estimated weighted average fair value of $0.45 per option (December 31, 2008 - $0.38 per option), for a total estimated value of $472,500 (2008 - $349,500). For the year ended December 31, 2009, a total of $436,821 (2008 -$531,006) has been recognized as stock-based compensation expense in general and administrative expenses with an offsetting credit to contributed surplus.

12. COMMITMENTS

The Company entered into an operating lease for office premises beginning on December 1, 2009 and expiring on November 30, 2014, which requires minimum monthly payments of $19,704 for the first two years of the lease, $20,415 for the third year of the lease, and $21,126 for the last two years of the lease, for a total of $102,075 for the next five years.

13. FINANCIAL INSTRUMENTS

Analysis of financial assets and liabilities by measurement basis

The following analyzes the carrying amounts of the financial assets and liabilities by category as defined by CICA Handbook Section 3855, "Financial Instruments - Recognition and Measurement":

Carrying value of financial instruments as at December 31, 2009:



----------------------------------------------------------------------------
Receivables Other financial Total carrying
liabilities value
$ $ $
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Financial assets
Accounts receivable 3,872,925 3,872,925
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Financial liabilities
Accounts payable and accrued
liabilities 8,034,501 8,034,501
Credit facility 26,519,080 26,519,080
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Carrying value of financial instruments as at December 31, 2008:

----------------------------------------------------------------------------
Receivables Other financial Total carrying
liabilities value
$ $ $
----------------------------------------------------------------------------
Financial assets
Accounts receivable 5,902,432 5,902,432
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Financial liabilities
Accounts payable and accrued
liabilities 13,940,693 13,940,693
Credit facility 28,358,033 28,358,033
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Fair Value of financial instruments

The fair value of a financial instrument is the amount that would be agreed on in an arm's-length transaction between knowledgeable, willing parties who are under no obligation to act. Fair values can be determined by reference to prices for a financial instrument in active markets to which the Company has access. In the absence of an active market, the Company determines fair values based on valuation models or by reference to other similar products in active markets. As at December 31, 2009 and 2008, the Company did not have any financial instruments measured at fair value.

Financial instruments recognized on the balance sheets consist of accounts receivable, accounts payable, and credit facility. As at December 31, 2009 and 2008, there was no significant difference between the carrying amounts of these financial instruments reported on the balance sheets and their estimated fair values given their short terms to maturity.

Financial risk factors

The Company is exposed to a number of different financial risks arising from the normal course of business exposures, as well as the Company's use of financial instruments. These risk factors include market risks relating to commodity prices, and interest rates, as well as liquidity risk and credit risk.

Market risk

Market risk is the risk or uncertainty arising from possible market price movements and their impact on the future performance of the Company. The market price movements that could adversely affect the value of the Company's financial assets, liabilities and expected future cash flows include commodity price risk and interest rate risk.

Commodity price risk

The Company is exposed to commodity price risk since its revenue is dependent on the price of natural gas and to a lesser extent natural gas liquids and crude oil. An increase of CDN$1.00/mcf in the price of natural gas would increase income before tax by $4.0 million (2008 - $2.9 million). A similar decrease in commodity prices would have the opposite impact. As of December 31, 2009, the Company's natural gas and liquids production continues to be unhedged and is marketed in the Alberta spot market.

As at December 31, 2009, the Company had no fixed price contracts associated with future production.

Interest rate risk

The Company is exposed to interest rate risk, which arises primarily from its variable rate credit facility. The credit facility has a floating interest rate which fluctuates based on prevailing market conditions. As at December 31, 2009, $26.5 million (2008 - $28.4 million) is subject to movements in floating interest rates. If interest rates on the floating credit facility decreased by 1%, it is estimated that income before tax for the year would increase by approximately $265 thousand (2008 -$261 thousand), assuming all other variables remained constant. A similar increase in the interest rate would have the opposite impact.

Credit risk

Credit risk arises from credit exposure to joint venture partners. The maximum exposure to credit risk is equal to the carrying value of the financial assets.

The Company is 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. In the event such entities fail to meet their contractual obligations to the Company, such failures may have a material adverse effect on the Company's business, financial condition, and results of operations.

The objective of managing third party credit risk is to minimize losses in financial assets. The Company assesses the credit quality of its partners, taking into account their financial position, past experience and other factors. 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 accounts receivable on a monthly basis. As at December 31, 2009, the Company held capital advances of $130 thousand (2008 - $979 thousand). As at December 31, 2009, no receivable balance has been deemed uncollectible or written off during the period. As at December 31, 2009, the majority of the accounts receivable balance was current with only 5% outstanding for more than 90 days.

Liquidity risk

Liquidity risk arises through excess financial obligations over available financial assets due at any point in time. The Company's objective in managing liquidity risk is to maintain sufficient available reserves in order to meet its liquidity requirements at any point in time. The Company achieves this by managing its capital spending and maintaining sufficient funds in its credit facility. As at December 31, 2009, the Company had $26.5 million outstanding on its $43.0 million credit facility.

The Company's operating cash requirements, including amounts projected to complete its existing capital expenditure program, are continuously monitored and adjusted depending on cash flows generated. There are, however, inherent liquidity risks, including the possibility that additional financing may not be available to the Company, or that actual capital expenditures may exceed those planned. In an effort to mitigate these risks, the Company intends to closely monitor the balance sheets and adjust its forecasted spending accordingly.

14. SUBSEQUENT EVENT

On January 28, 2010, the Company issued, through a bought-deal financing, a total of 22,493,300 common shares at $1.65 per share for gross proceeds of $37,113,945. Net proceeds from the offering, which were temporarily used to reduce outstanding indebtedness, will be used to fund the Company's ongoing exploration and development program and for general corporate purposes.

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