Cinch Energy Corp.
TSX : CNH

Cinch Energy Corp.

March 02, 2011 17:00 ET

Cinch Energy Corp. Releases 2010 Results and 2011 Outlook

CALGARY, ALBERTA--(Marketwire - March 2, 2011) - Cinch Energy Corp. (TSX:CNH) ("Cinch" or the "Company") is pleased to announce its financial and operating results for the year ended December 31, 2010 and guidance for 2011.

2010 HIGHLIGHTS



-- Increased proven reserves in 2010 by 38% from 7.4 mmboe to 10.2 mmboe.
Proven plus probable reserves also increased by 37% from 10.6 mmboe to
14.5 mmboe.
-- Reserve replacement ratio on proven reserves of 400% and proven plus
probable reserves of 520%.
-- 2010 proven FD&A costs of $12.34 per boe and proven plus probable FD&A
costs of $9.48 per boe.
-- Reserve life index of over 15 years on a proven plus probable basis
(based on 2010 average volumes).
-- Top quartile operating expenses of $4.44 per boe.
-- Production volumes averaged 2,580 boe per day, a 9% increase over 2009,
with an average rate of 2,750 boe per day for the month of December
2010.
-- Participated in the drilling of 11 gross (3.57 net) successful
horizontal Montney wells in the Dawson area of North East British
Columbia.
-- Participated in the drilling of 2 gross (0.45 net) successful liquids
rich horizontal wells in the Deep Basin area of Alberta.
-- Year end net debt of $12.5 MM, with $50 MM of credit facilities.


2011 OUTLOOK

Facilities construction and pipeline installation for the Company's 9 gross (3.05 net) horizontal Montney wells is currently underway in the Dawson area and the wells are anticipated to be on stream by the end of March 2011. The other 2 gross (0.56 net) Montney wells commenced production in 2010. The Deep Basin wells are currently being tied into existing infrastructure. With these wells on stream, production volumes are expected to exceed 4,000 boe per day by the end of March 2011.

Planned capital investments of $49 MM during 2011 will be focussed on liquids rich gas and oil opportunities that remain economic in the current commodity price environment. The three primary areas of spending will include the Montney in British Columbia, the Deep Basin area of Alberta and a number of oil opportunities in North Western Alberta. This program is expected to be funded using internally generated cash flow, draws on the credit facility and the sale of certain non-core assets, and will be reviewed in response to commodity price changes.

The current outlook for 2011 is based on CDN $3.75/GJ AECO gas prices and US $85.00/bbl WTI oil prices. Production volumes are forecasted to average 3,700 boe per day, a 43% increase over the 2010 average production volumes. Cash flow is expected to be $17.5 MM and year end debt is forecasted at $30.5 MM. Additional details about Cinch's 2011 plans and activities are shown in the corporate presentation on the Company's website at www.cinchenergy.com.



HIGHLIGHTS

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Three months ended Year ended
December 31, December 31,
2010 2009 2010 2009
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Petroleum and natural gas sales, net
of transportation ($000's) 6,408 5,815 25,673 22,141


Sales volumes per day
Natural gas (Mcf/d) 15,541 11,235 14,176 12,990
Natural gas liquids (Bbl/d) 260 193 218 209
Equivalence at 6:1 (BOE/d) 2,850 2,065 2,580 2,374

Sales Price
Natural gas ($/Mcf) 3.38 4.56 3.94 3.86
Natural gas liquids ($/Bbl) 66.22 61.92 66.07 50.10
Equivalence at 6:1 ($/BOE) 24.44 30.61 27.26 25.55

$ $ $ $
Funds from operations (000's) (1) 2,998 2,096 11,705 9,479
- per share, basic & diluted (1) 0.03 0.04 0.14 0.17

Net loss (000's) (1,416) (1,537) (6,710) (8,904)
- per share, basic & diluted (0.01) (0.03) (0.08) (0.16)

Capital expenditures ($000's) 20,208 518 51,019 6,342

Basic weighted average shares 96,630 58,853 84,865 56,734
outstanding (000's)

Working capital (net debt) (2)
($000's)
- As at December 31, 2010 (12,485)
- As at December 31, 2009 (29,444)

As at March 1, 2011
Common shares outstanding (000's) 96,855
Options outstanding (000's) 7,875
- average exercise price 1.23
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(1) Funds from operations and funds from operations per share are not
generally accepted accounting principles ("GAAP") and represent cash
provided by operating activities on the statement of cash flows less the
effect of changes in non-cash working capital related to operating
activities.

(2) Working capital (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, 2010, were prepared by the independent engineering firm of GLJ Petroleum Consultants Ltd. ("GLJ") in accordance with the definitions set out under National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities ("NI 51-101").



-- Total proved reserves at December 31, 2010 increased 38% to 10.2 million
BOE compared to 7.4 million BOE at December 31, 2009.
-- Total proved plus probable reserves at December 31, 2010 increased 37%
to 14.5 million BOE compared to 10.6 million BOE at December 31, 2009.
-- On a proved plus probable basis, the finding, development and
acquisition costs were $9.48 per BOE ($12.34 per BOE on a proved basis).


RESERVES SUMMARY - COMPANY GROSS RESERVES(1)

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Light and Natural Variance
Medium Gas Natural Total Total (2010 vs
Crude Oil Liquids Gas 2010 2009 2009)
(mbbls) (mbbls) (mmcf) (mboe) (mboe) (mboe)
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Proved
-Developed
Producing 49 544 22,763 4,387 3,965 422
-Dev. Non-
Producing - 221 12,024 2,225 709 1,516
-Undeveloped 35 319 19,278 3,567 2,691 876
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Total Proved 84 1,084 54,065 10,179 7,365 2,814
Probable 20 466 23,254 4,361 3,204 1,157
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Total Proved
Plus Probable 104 1,550 77,319 14,540 10,569 3,971
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Note: numbers may not add due to rounding

(1) Company gross reserves are defined as the Company's interest (operating
and non-operating) share in reserves before deduction of royalties and
without including any royalty interest of the Company


NET PRESENT VALUE SUMMARY - FORECASTED PRICES AND COSTS

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Discounted at
----------------------------------------------------------------------------

Undiscounted 5% 10% 15% 20%
December 31, 2010 (1),(2),(3) ($M) ($M) ($M) ($M) ($M)
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Proved -Developed Producing 96,337 71,142 57,198 48,364 42,239
-Dev. Non-Producing 53,063 37,307 28,808 23,613 20,127
-Undeveloped 60,995 33,567 19,440 11,279 6,150
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Total Proved 210,395 142,016 105,446 83,256 68,515
Probable 125,933 59,179 35,154 23,903 17,629
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Total Proved Plus Probable 336,328 201,195 140,600 107,159 86,144
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Note: numbers may not add due to rounding

(1) Utilizing GLJ January 1, 2011 price forecast

(2) As required by NI 51-101, undiscounted well abandonment costs of $2.9
million for total proved reserves and $3.6 million for total proved plus
probable reserves are included in the net present value of future net
revenues determination.

(3) Prior to provision for 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, 2011 pricing forecasts presented below have been prepared by GLJ. These prices have been utilized in determining the reserves and cash flow forecasts above.



---------------------------------
Oil
-----------------------
Edmonton
WTI Par Price
Cushing 40 degrees
Oklahoma API
Year ($US/Bbl) ($Cdn/Bbl)
---------------------------------
Forecast
2011 88.00 86.22
2012 89.00 89.29
2013 90.00 90.92
2014 92.00 92.96
2015 95.17 96.19
2016 97.55 98.62
2017 100.26 101.39
2018 102.74 103.92
2019 105.45 106.68
2020 107.56 108.84
Thereafter +2%/yr +2%/yr
---------------------------------

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Natural Gas Liquids
----------------------------------
Natural Gas
Alberta Edmonton
Plant Edmonton Edmonton Pentanes Inflation Exchange
Gate Price Propane Butane Plus Rates Rate
Year ($Cdn/MMBtu) ($Cdn/Bbl) ($Cdn/Bbl) ($Cdn/Bbl) (%/year) ($US/$Cdn)
----------------------------------------------------------------------------
Forecast
2011 4.16 54.32 67.26 90.54 2 0.980
2012 4.74 56.25 68.75 91.96 2 0.980
2013 5.31 57.28 70.01 92.74 2 0.980
2014 5.77 58.56 71.58 94.82 2 0.980
2015 6.22 60.60 74.07 98.12 2 0.980
2016 6.53 62.13 75.94 100.59 2 0.980
2017 6.76 63.87 78.07 103.42 2 0.980
2018 6.90 65.47 80.02 106.00 2 0.980
2019 7.06 67.21 82.15 108.82 2 0.980
2020 7.21 68.57 83.80 111.01 2 0.980
Thereafter +2%/yr +2%/yr +2%/yr +2%/yr 2 0.980
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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, 2010 compared to December 31, 2009 based on forecast prices and costs by principal product type:



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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, 2009 22 5 27 38,148 16,833 54,981
Discoveries - - - - - -
Extensions 35 8 44 5,181 5,928 11,109
Infill Drilling - - - 1,698 463 2,160
Improved Recovery - - - - - -
Technical Revisions 34 7 41 14,732 (75) 14,658
Acquisitions - - - - - -
Dispositions - - - - - -
Economic Factors - (1) (1) (525) 105 (420)
Production (7) - (7) (5,170) - (5,170)
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December 31, 2010 84 20 104 54,065 23,254 77,319
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-----------------------------------------------
NATURAL GAS LIQUIDS
---------------------------
Gross
Proved
Gross Gross Plus
Proved Probable Probable
FACTORS (Mbbl) (Mbbl) (Mbbl)
-----------------------------------------------
December 31, 2009 985 393 1,378
Discoveries - - -
Extensions 147 125 273
Infill Drilling - - -
Improved Recovery - - -
Technical Revisions 37 (58) (21)
Acquisitions - - -
Dispositions - - -
Economic Factors (13) 6 (7)
Production (72) - (72)
-----------------------------
December 31, 2010 1,084 466 1,550
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Note: numbers may not add due to rounding


Additional reserve disclosure tables, as required under NI 51-101, are contained in the Annual Information Form to be filed on SEDAR.

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





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2010 2009 3 year average
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Proved + Proved + Proved +
Proved Probable Proved Probable Proved Probable
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Capital ($000's)
Exploration and
development (1) 51,019 51,019 6,342 6,342 29,791 29,791
Acquisition capital - - - - - -
Change in future
capital (4,660) (4,425) 39,144 48,062 12,278 15,279
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Total capital
including change in
future capital 46,359 46,594 45,486 54,404 42,069 45,070
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Reserve additions
(mboe) (2)
Exploration and
development (2) 3,756 4,913 2,981 4,134 2,785 3,612
Acquisition - - 13 20 4 7
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Total reserve
additions (mboe)(2) 3,756 4,913 2,994 4,154 2,789 3,619
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Costs ($/boe)
F&D 12.34 9.48 15.26 13.16 15.11 12.48
FD&A 12.34 9.48 15.19 13.10 15.08 12.45
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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 reserve additions for that year.

(2) Reserve additions for 2008, as included in the 3 year average, 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 and
2010, Cinch calculated F&D and FD&A costs per boe based on gross
reserves determined in accordance with NI 51-101, which are not
materially different from "Company interest" reserves. The estimates of
reserves for individual properties may not reflect the same confidence
level as estimates of reserves for all properties, due to the effects of
aggregation.

(3) NI 51-101 specifies how 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 reserves 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 FD&A costs that will incorporate all acquisitions net
of any dispositions during the year.


PRODUCTION & RESERVE LIFE INDEX

The Company's reserve life index using annualized fourth quarter 2010 production is 9.8 years for proved BOE reserves and 14.0 years for proved plus probable BOE reserves, consistent with the prior year.



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2010 2009
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Production rate is an: Annualized Q4 Average Annualized Q4 Average
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Production (boe/d) 2,850 2,580 2,065 2,374
Proved reserves (mboe) 10,179 10,179 7,365 7,365
Proved reserve life index
(years) 9.8 10.8 9.8 8.5
Proved plus probable
reserves (mboe) 14,540 14,540 10,569 10,569
Proved plus probable
reserve life index (years) 14.0 15.4 14.0 12.2
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Note: 2009 reserve life indexes have been revised as a result of a
miscalculation noted in the previous year.


Cinch had a December 2010 average production of approximately 2,750 BOE per day.

RESERVE REPLACEMENT

The Company's 2010 capital investment program replaced 2010 average production by a factor of 4.0 times on a proved basis and 5.2 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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2010 2010 2009 2009
Production total is an: Annualized Q4 Average Annualized Q4 Average
----------------------------------------------------------------------------
Production (mboe) 1,040 942 754 867
Proved reserve additions
after revisions
of prior periods (mboe) 3,756 3,756 2,994 2,994
Proved replacement ratio 3.6 4.0 4.0 3.5
Proved plus probable
reserve additions
after revision of prior
periods (mboe) 4,913 4,913 4,154 4,154
Proved plus probable
replacement ratio 4.7 5.2 5.5 4.8
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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 2010 actual FD&A) and an F&D basis.



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2010 2010 2009 2009
(FD&A) (F&D) (FD&A) (F&D)
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Operating netbacks ($/BOE) 17.93 17.93 17.04 17.04
Proved finding, development and net
acquisition costs after 12.34 12.34 15.19 15.26
revision of prior periods and including the
change in future
development capital ($/BOE)
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Proved recycle ratios 1.5 1.5 1.1 1.1
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Proved plus probable finding, development
and acquisition 9.48 9.48 13.10 13.16
costs after revisions of prior periods and
including the change in
future development capital ($/BOE)
----------------------------------------------------------------------------
Proved plus probable recycle ratios 1.9 1.9 1.3 1.3
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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, anticipated sale of non-core assets, expected production increases and the timing thereof, estimated 2011 production and cash flow and net debt at year end 2011, timing of completion of facilities and bringing on the 9 Montney wells in March 2011, expected operating costs and general and administrative expenses and the expected levels of activities, timing of phases of the IFRS conversion project, anticipated policy choices and adjustments to the opening balance sheet at transition to IFRS may constitute forward-looking statements under applicable securities laws and necessarily involve risks including, without limitation, risks associated with oil and gas exploration, development, exploitation, production, marketing and transportation, volatility of commodity prices, imprecision of reserve estimates, environmental risks, competition from other producers, incorrect assessment of the value of acquisitions, failure to complete and/or realize the anticipated benefits of acquisitions, delays resulting from or inability to obtain required regulatory approvals and ability to access sufficient capital from internal and external sources and changes in the regulatory and taxation environment. Consequently, the Company's actual results may differ materially from those expressed in, or implied by, the forward-looking statements. Forward-looking statements or information is based on a number of factors and assumptions which have been used to develop such statements and information but which may prove to be incorrect.

Although the Company believes that the expectations reflected in such forward-looking statements or information are reasonable, undue reliance should not be placed on forward-looking statements because the Company can give no assurance that such expectations will prove to be correct. In addition to other factors and assumptions which may be identified in this document, assumptions have been made regarding, among other things: the ability of the Company to obtain equipment and services in a timely and cost efficient manner; drilling results; the ability of the operator of the projects in which the Company has an interest to operate the field in a safe, efficient and effective manner; field production rates and decline rates; the ability to replace and expand oil and natural gas reserves through development of exploration; future oil and natural gas prices; interest rates; the regulatory framework regarding royalties; and the ability of the Company to successfully market its oil and natural gas products. Readers are cautioned that the foregoing list of factors is not exhaustive. Additional information on these and other factors that could affect the Company's operations and financial results are included elsewhere herein and in reports on file with Canadian securities regulatory authorities and may be accessed through the SEDAR website (www.sedar.com), or at the Company's website (www.cinchenergy.com). The estimate of cash flow for 2011 and of the debt at the end of 2011 represents future oriented financial information and a financial outlook in accordance with applicable securities laws. Such information has been included to provide investors with information related to the expected cash flow of the Company and the resulting net debt 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 resulting net debt and may not be appropriate for other purposes. 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 1, 2011

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 and related notes for the years ended December 31, 2010 and 2009. This commentary is based on information available as at, and is dated, March 1, 2011. Additional information relating to Cinch, including Cinch's Annual Information Form, is available on SEDAR at www.sedar.com.

Non-GAAP Measures

The MD&A contains the term "funds from operations" which should not be considered an alternative to, or 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. This number may not be comparable to that reported by other companies.

OPERATIONAL UPDATE

The Company had a very active 2010, drilling 16 wells (6.17 net) and tieing in 4 wells (1.82 net). Production increased during 2010 from an average of 2,374 BOE per day in 2009 to a December 2010 average rate of approximately 2,750 BOE per day. During February 2011, the Kakwa 5-18 Dunvegan well (60% working interest) was brought on stream and is expected to produce at a restricted rate of 5 mmcf per day (gross). Cinch also anticipates bringing on production in late March 2011, 9 horizontal Montney wells (3.05 net) drilled in the latter part of 2010. With additional production projected to be brought on stream in the first quarter of 2011, Cinch's production is expected to exceed 4,000 BOE per day by the end of March 2011.

During the first quarter of 2010, Cinch drilled and cased its first horizontal well at Dawson 4-25 (82.5% working interest) as part of the Company's Montney development program. During the remainder of the year, Cinch participated in the drilling of an additional 9 horizontal Montney wells (3.05 net). Facility construction and tie-in of Cinch's working interest Montney wells that were drilled in 2010 experienced some delays but was underway by the end of the year, with new production expected to come on stream by the end of March 2011. New production during 2010 included two Wabamun wells and two Montney wells which were producing at a combined rate of over 850 BOE per day (net) during the month of December 2010.

Cinch completed two financings during the year for total gross proceeds of $59.4 million. The proceeds of both financings were primarily used to fund the Company's capital program of $51.0 million, which increased significantly from 2009. At December 31, 2010, the Company had net debt of $12.5 million, comprised of a working capital deficiency of $12.5 million, with a zero balance outstanding on its available credit facilities of $50.0 million.



PRODUCTION

----------------------------------------------------------------------------
Three months ended December 31, Year ended December 31,
2010 2009 Change 2010 2009 Change
----------------------------------------------------------------------------
% %
Natural gas
(Mcf/d) 15,541 11,235 38 14,176 12,990 9
Liquids (Bbl/d) 260 193 35 218 209 4
Equivalence
(BOE/d) 2,850 2,065 38 2,580 2,374 9
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----------------------------------------------------------------------------


Production for the three months ended December 31, 2010 increased 38% compared to the same period of 2009 primarily due to new wells coming on production in 2010. Natural gas production volumes in the fourth quarter of 2010 included approximately 255 BOE per day (net) from the Dawson 6-30 well, which came on production at the beginning of June 2010, and approximately 180 BOE per day (net) from the Dawson 1-22 well, which came on production in July 2010. In addition, in November 2010, the Dawson 7-25 well came on production, averaging 425 BOE per day (net) during the remainder of the fourth quarter. Also, in December 2010, the Dawson 5-23 well came on production at an average rate of approximately 90 BOE per day (net) for the month.

Production for the year ended December 31, 2010 was 9% higher than the average production for the previous year. On an annual basis, 2010 included a full year of production from the Dawson 1-33 well, producing at an average rate of 580 BOE per day (net). Also, production from the Dawson 6-30 well averaged approximately 330 BOE per day (net) since the beginning of June 2010.

Production during the fourth quarter of 2010 increased 8% from the previous quarter primarily due to new production from the Dawson 7-25 well, which came on production in November 2010, and the Dawson 5-23 well, which came on production in December 2010.



PRICES

----------------------------------------------------------------------------
Three months ended
December 31, Year ended December 31,
2010 2009 Change 2010 2009 Change
----------------------------------------------------------------------------
% %
Natural gas ($/Mcf) 3.38 4.56 (26) 3.94 3.86 2
Liquids($/Bbl) 66.22 61.92 7 66.07 50.10 32
Equivalence ($/BOE) 24.44 30.61 (20) 27.26 25.55 7
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Realized natural gas prices were 26% lower in the fourth quarter of 2010 compared to the same quarter in 2009 and 2% higher year over year. Realized natural gas prices during the fourth quarter of 2010 were consistent with the previous quarter. The Company's natural gas production continues to be unhedged and is marketed in the Alberta and British Columbia spot markets.

Natural gas liquids pricing was 7% and 32% higher for the three months and year ended December 31, 2010, respectively, compared to the same periods of 2009 and 5% higher than the third quarter of 2010. This is consistent with a steady improvement in oil and natural gas liquids pricing throughout 2010. Natural gas liquids represented approximately 9% of the Company's oil and gas production on a BOE basis for the fourth quarter of 2010. The Company has not hedged any of its liquids production.



REVENUES

Dollars in thousands, except per unit amounts
----------------------------------------------------------------------------
Three months ended
December 31, Year ended December 31,
2010 2009 Change 2010 2009 Change
----------------------------------------------------------------------------
$ $ % $ $ %
Oil and gas sales,
net of transportation 6,408 5,815 10 25,673 22,141 16
Per BOE 24.44 30.61 (20) 27.26 25.55 7
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Revenues for the three months and year ended December 31, 2010 were 10% and 16% higher, respectively, compared to the same periods of 2009 as a result of increased production. Revenues for the three months ended December 31, 2010 increased 12% from the third quarter of 2010 due to an increase in natural gas production of 171 BOE per day at comparable prices, as well as an increase in natural gas liquids production of approximately 53 BOE per day at higher prices than the third quarter.

Transportation expenses were approximately $0.08 per BOE lower for the year ended December 31, 2010 compared to 2009. This decrease was the result of an increase in the proportion of the Company's production 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,
2010 2009 Change 2010 2009 Change
----------------------------------------------------------------------------
$ $ % $ $ %
Royalties (1) 1,141 1,020 12 4,611 3,419 35
Per BOE 4.35 5.37 (19) 4.90 3.95 24
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----------------------------------------------------------------------------

(1) Royalties for prior periods have been reclassified to reflect the change
in presentation of gas processing credits from operating expenses to
royalties.


Royalties for the three months and year ended December 31, 2010 were 12% and 35% higher, respectively, compared to the same periods of 2009 primarily due to increased revenues. The royalty rate (crown royalties and gross overriding royalties as a percentage of oil and gas sales) for 2010 was 18% of oil and gas revenues, compared with a royalty rate of 15% for 2009. The royalty rate for 2010 was higher than 2009 partly due to higher royalties paid on the Dawson 6-6 well during 2010. This well was on royalty holiday until June 2009 and, as a result, crown royalties paid on this well were $256 thousand higher in 2010 compared to 2009. In addition, a 32% increase in liquids pricing year over year, combined with a modest increase in liquids production, resulted in a higher royalty rate for natural gas liquids during 2010. These increases were partially offset by the net drilling credits received during the third quarter of 2010.

Royalties for the fourth quarter of 2010 were approximately twice as high as the $553 thousand of royalties recorded during the third quarter primarily due to the drilling credits that were purchased during the third quarter thereby effectively reducing crown royalties, as well as an increase in revenues during the fourth quarter. In addition, the 2% royalty holiday on the Dawson 1-33 well expired in November 2010 which resulted in royalties of 23%, or approximately $84 thousand recorded for the month of December for this well.



OPERATING EXPENSES

Dollars in thousands, except per unit amounts
----------------------------------------------------------------------------
Three months ended
December 31, Year ended December 31,
2010 2009 Change 2010 2009 Change
----------------------------------------------------------------------------
$ $ % $ $ %
Operating (1) 1,061 822 29 4,183 3,948 6
Per BOE 4.05 4.33 (6) 4.44 4.56 (3)
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(1) Operating expenses for prior periods have been reclassified to reflect
the change in presentation of gas processing credits from operating
expenses to royalties.


Total operating expenses during the three months and year ended December 31, 2010 increased 29% and 6%, respectively, compared to the same periods of 2009 primarily due to increased variable expenses relating to new production, as well as higher operating expenses associated with the new Montney production. In the fourth quarter of 2010, there were also increases in compressor and equipment maintenance, contractor and technical services, and inspection costs compared to the same period of the prior year. Operating expenses per BOE for the year ended December 31, 2010 were slightly lower than the prior year.

Total operating expenses for the fourth quarter of 2010 were comparable to operating expenses reported during the third quarter of 2010. On a per BOE basis, operating expenses during the fourth quarter of 2010 were 6% lower than operating expenses of $4.31 per BOE during the third quarter due to increased production volumes in the fourth quarter.

Operating expenses are not expected to exceed $5.50 per BOE in 2011. The higher forecasted expenses per BOE reflect the higher operating expenses associated with the increased Montney production forecasted for 2011. Anticipated costs per BOE can change, however, depending on the Company's actual production levels.



GENERAL AND ADMINISTRATIVE EXPENSES

Dollars in thousands, except per unit amounts
----------------------------------------------------------------------------
Three months ended
December 31, Year ended December 31,
2010 2009 Change 2010 2009 Change
----------------------------------------------------------------------------
$ $ % $ $ %
General and
administrative 1,583 1,768 (10) 6,222 4,705 32
Per BOE 6.04 9.31 (35) 6.61 5.43 22
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Total general and administrative ("G&A") expenses in 2010 were 32% higher than the previous year due to higher salaries and benefits, and increased stock based compensation expense. During the first few months of 2010, the Company made some senior management changes and staff additions which resulted in severance payments and increased stock based compensation. The Company does not capitalize any indirect general and administrative expenses. In addition, Cinch's Board of Directors began receiving cash compensation in 2010. Bank charges also increased in 2010 as a result of increased standby fees and increased bank fees associated with the addition of a second credit facility received in August 2010. G&A costs per BOE were $6.61 compared to $5.43 in the previous year due to increased total G&A partially offset by higher production.

Total general and administrative expenses for the fourth quarter of 2010 were 10% lower than the same period of 2009 because 2009 included the costs associated with the retirement of Cinch's previous Chief Executive Officer. G&A expenses for the fourth quarter of 2010 were comparable to the previous quarter of 2010.

G & A expenses for 2011 are not expected to exceed $4.75 per BOE, due to higher budgeted production volumes expected in 2011. Anticipated costs per BOE can change, however, depending on the Company's actual production levels.



INTEREST EXPENSE

Dollars in thousands, except per unit amounts
----------------------------------------------------------------------------
Three months ended
December 31, Year ended December 31,
2010 2009 Change 2010 2009 Change
----------------------------------------------------------------------------
$ $ % $ $ %
Interest expense - 256 (100) 192 1,077 (82)
Per BOE - 1.35 (100) 0.20 1.24 (84)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Interest expense decreased during the three months and year ended December 31, 2010 compared to the same periods of 2009 primarily due to the two financings that were completed during 2010 which resulted in lower average debt balances throughout the year and a zero balance outstanding on the Company's credit facilities since September, 2010. In 2009, the Company exited the year with $26.5 million outstanding under its credit facility.



ACCRETION OF ASSET RETIREMENT OBLIGATIONS EXPENSE

Dollars in thousands, except per unit amounts
----------------------------------------------------------------------------
Three months ended
December 31, Year ended December 31,
2010 2009 Change 2010 2009 Change
----------------------------------------------------------------------------
$ $ % $ $ %
Accretion expense 72 59 22 263 225 17
Per BOE 0.27 0.31 (13) 0.28 0.26 8
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The accretion expense increased during the three months and year ended December 31, 2010 compared to the same periods of 2009 due to an increased number of wells with asset retirement obligations. The accretion expense for the fourth quarter of 2010 is consistent with the accretion expense recorded during the third quarter of 2010.



DEPLETION AND DEPRECIATION EXPENSE

Dollars in thousands, except per unit amounts
----------------------------------------------------------------------------
Three months ended
December 31, Year ended December 31,
2010 2009 Change 2010 2009 Change
----------------------------------------------------------------------------
$ $ % $ $ %
Depletion and
depreciation 4,518 4,021 12 19,103 20,892 (9)
Per BOE 17.23 21.16 (19) 20.29 24.11 (16)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Total depletion and depreciation expense for the year ended December 31, 2010 was 9% lower than the previous year due to an increase in the reserve base for 2010 due to positive drilling results. On a per BOE basis, depletion and depreciation expense for the three months and year ended December 31, 2010 decreased 19% and 16%, respectively, due to an increase in the reserve base used to calculate depletion.

Total depletion and depreciation expense for the fourth quarter of 2010 was 14% lower than the third quarter of 2010 and 21% lower on a per BOE basis due to an increase in the reserve base recorded in the fourth quarter of 2010.



TAXES

Dollars in thousands, except per unit amounts
----------------------------------------------------------------------------
Three months ended
December 31, Year ended December 31,
2010 2009 Change 2010 2009 Change
----------------------------------------------------------------------------
$ $ % $ $ %
Future income tax
recovery 517 582 (11) 2,117 3,170 (33)
Per BOE 1.97 3.06 (36) 2.25 3.66 (39)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


A future income tax recovery was recorded for the three months and year ended December 31, 2010 consistent with the net loss experienced during those periods.



Tax pools at December 31:

Dollars in thousands
----------------------------------------------------------------------------
2010 2009
----------------------------------------------------------------------------
COGPE 19,542 11,470
CDE 37,300 21,947
CEE 52,699 36,910
UCC 13,138 15,117
----------------------------------------------------------------------------
122,679 85,444
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The Company's tax pools increased during 2010 as a result of capital expenditures of $51.0 million, which were higher than the tax pools needed to eliminate taxable income.



NET LOSS AND FUNDS FROM OPERATIONS

In thousands, except per share amounts
----------------------------------------------------------------------------
Three months ended
December 31, Year ended December 31,
2010 2009 Change 2010 2009 Change
----------------------------------------------------------------------------
$ $ % $ $ %
Net loss (1,416) (1,537) (8) (6,710) (8,904) (25)
per basic share (0.01) (0.03) (67) (0.08) (0.16) (50)
per diluted share (0.01) (0.03) (67) (0.08) (0.16) (50)

Funds from
operations(1) 2,998 2,096 43 11,705 9,479 23
per basic
share(1) 0.03 0.04 (25) 0.14 0.17 (18)
per diluted
share(1) 0.03 0.04 (25) 0.14 0.17 (18)

Weighted average
shares outstanding 96,630 58,853 64 84,865 56,734 50
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1) Funds from operations and funds from operations per share are not
generally accepted accounting principles ("GAAP") and represent cash
provided by operating activities on the statement of cash flows less the
effect of changes in non-cash working capital related to operating
activities.


For the year ended December 31, 2010, the Company incurred a net loss of $6.7 million, compared to a net loss of $8.9 million for the prior year. The decrease in net loss year over year is primarily due to increased revenues in 2010 resulting from higher production and lower interest expense, partially offset by increased G&A expenses and higher royalties. The net loss per basic and diluted share was reduced by the increase in the weighted average shares outstanding during 2010.

The net loss of $1.4 million for the fourth quarter of 2010 was lower than the net loss of $2.1 million recorded during the third quarter of 2010 primarily due to an increase in revenues quarter over quarter, and decreased depletion and depreciation expense, partially offset by an increase in royalties during the fourth quarter.

The Company's funds from operations for the three months and year ended December 31, 2010 were 43% and 23% higher, respectively, than the same periods of 2009. Funds from operations in 2010 were higher primarily as a result of higher revenues, partially offset by higher royalties and higher operating costs. Despite this increase, funds from operations per basic and diluted share for the three months and year ended December 31, 2010 decreased 25% and 18%, respectively, when compared to the same periods of 2009 as a result of the increase in the weighted average number of shares outstanding throughout 2010.

Funds from operations recorded during the fourth quarter of 2010 were comparable to the $2.9 million recorded during the third quarter of 2010.

The increase in the weighted average number of shares outstanding from the previous year is attributable to the additional shares issued in conjunction with the financings completed in January and September 2010, as well as stock options that were exercised during the year.



LIQUIDITY AND CAPITAL RESOURCES

Dollars in thousands
----------------------------------------------------------------------------

December 31, 2010 December 31, 2009 Change
----------------------------------------------------------------------------
$ $ %
Working capital (deficiency),
excluding credit facility (12,485) (2,925) 327

Credit facility - (26,519) (100)
----------------------------------------------------------------------------
Working capital (net debt) (12,485) (29,444) (58)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


At December 31, 2010, the Company had net debt of $12.5 million, comprised of a working capital deficiency of $12.5 million, with a zero balance outstanding on its available credit facilities of $50.0 million. The $17.0 million improvement in net debt from December 31, 2009 can be attributed to net proceeds of $55.8 million received from the financings completed in January and September of 2010 and exercised stock options, as well as $11.7 million of funds from operations for the year, partially offset by capital expenditures of $51.0 million.

In April 2010, Cinch completed its annual line of credit review with its lender and the Company's credit facility was reduced from $43.0 million to $36.0 million, primarily as a result of lower forecasted natural gas prices. In August 2010, the Company obtained an increase to its line of $1.5 million due to positive drilling results. The Company also entered into a second credit facility in the amount of $12.5 million to be used for general corporate purposes but it incurs higher standby fees and interest rates. This resulted in total credit facilities of $50.0 million. Management continues to closely monitor the balance sheet to ensure it is in compliance with its debt covenants.

Subsequent to December 31, 2010, Cinch received confirmation from its lender that, effective December 31, 2010, the authorized limits for its two credit facilities were amended to $40.0 million and $10.0 million, respectively, (previously $37.5 million and $12.5 million, respectively) based on a borrowing base review. The total borrowing base under the two facilities remains at $50.0 million, however, the associated bank charges and interest rates are more favorable under the primary facility. The next review of the Company's current credit facilities is scheduled for April 2011.



Shareholders' equity:

In thousands
----------------------------------------------------------------------------
December 31, 2010 December 31, 2009 Change
----------------------------------------------------------------------------
%
Shareholders' equity ($) 129,605 78,658 65
Common shares outstanding 96,630 58,860 64
Stock options outstanding 8,150 5,750 42
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The increase in shareholders' equity and the number of common shares outstanding from December 31, 2009 is primarily attributable to two financings completed in January and September 2010. In January 2010, the Company issued 22,493,300 common shares at $1.65 per share for net proceeds of $35.0 million. In September 2010, the Company issued 11,896,750 common shares at $1.45 per share and 2,860,000 flow-through common shares at $1.75 per share for net proceeds of $20.8 million.

During the year ended December 31, 2010, 3.9 million stock options were issued, 520 thousand stock options were exercised, 230 thousand options were forfeited, and 715 thousand options expired.

As at December 31, 2010, the Company's outstanding stock options amounted to 8.4% of the outstanding common shares. As at March 1, 2011, there were 96,855,415 common shares and 7,874,501 stock options outstanding. Since December 31, 2010, 50,000 stock options have expired and 225,000 stock options have been exercised.



CAPITAL EXPENDITURES

Additions to property, plant and equipment

Dollars in thousands
----------------------------------------------------------------------------
Year ended December 31,
2010 2009
----------------------------------------------------------------------------

Land and rentals 10,358 469
Seismic 333 (133)
Drilling, completing and equipping 38,420 8,630
Pipelines and facilities 1,687 2,061
Other assets 221 (56)
----------------------------------------------------------------------------
51,019 10,971
Property dispositions (net of acquisitions) - (4,629)
----------------------------------------------------------------------------
Total 51,019 6,342
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Capital expenditures for the year ended December 31, 2010 include approximately $10.4 million relating to land acquisitions in Alberta and British Columbia. Capital expenditures of $38.4 million were incurred on drilling, completion and tie-in operations primarily in the Dawson area of British Columbia, as well as an oil prospect in Alberta.

The Company's 2011 capital program is budgeted at approximately $49 million (subject to adjustments based on cash flows generated), and will be focused on liquids rich gas and oil opportunities that remain economic in the current commodity price environment.

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 a combination of hiring experienced and knowledgeable personnel and careful evaluation.

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 significant 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. Natural gas prices are expected to remain volatile for the near future as a result of market uncertainties over the supply and demand of this commodity due to various factors including the current state of the world economies. Reduced natural gas prices directly impact the Company's cash flow and forecasted spending. The financings completed in January 2010 and September 2010, as well as the increase in the credit facilities in August 2010 have enhanced the Company's ability and flexibility in dealing with the current depressed natural gas price environment. 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 the operator in all cases and therefore not all operational issues are within its control. Management will address them nonetheless, and attempt to implement solutions, which may be 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'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.

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, due to lower commodity pricing, exposes the Company to additional risk. There can be no assurance that debt or equity financing, or cash generated by operations will be available or sufficient to meet these requirements or for other corporate purposes or, if debt or equity financing is available, that it will be on terms acceptable to the Company. The inability of the Company to access sufficient capital for its operations could have a material adverse effect on the Company's business, financial condition, results of operations and prospects.

Third Party Credit Risk

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

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

CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

The Company's Chief Executive Officer and Chief Financial Officer have designed, or caused to be designed under their supervision, disclosure controls and procedures to provide reasonable assurance that: (i) material information relating to the Company is made known to the Company's Chief Executive Officer and Chief Financial Officer by others, particularly during the period in which the annual and interim 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 controls over financial reporting to provide reasonable assurance regarding the reliability of the Company's financial reporting and preparation of financial statements for external purposes in accordance with Canadian GAAP. Such officers have evaluated, or caused to be evaluated under their supervision, the effectiveness of the Company's internal controls over financial reporting at the financial year end of the Company and have concluded that the Company's internal controls over financial reporting are effective at the financial year end of the Company for the foregoing purposes.

The Company is required to disclose any change in the Company's internal controls over financial reporting that occurred during the period beginning on October 1, 2010 and ending on December 31, 2010 that has materially affected, or is reasonably likely to materially affect, the Company's internal controls over financial reporting. No material changes in the Company's internal controls over financial reporting were identified during such period that have materially affected, or are reasonably likely to materially affect, the Company's internal controls over financial reporting.

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

CONTRACTUAL OBLIGATIONS, COMMITMENTS, AND GUARANTEES

The Company has contractual obligations and commitments in the normal course of its operating and financing activities. These obligations and commitments have been considered when assessing the Company's cash requirements in its analysis of future liquidity. As at December 31, 2010, the Company has the following commitments over the next five years:



Dollars in thousands
----------------------------------------------------------------------------
greater
Total less than than 5
1 year 1-3 years 4-5 years years
----------------------------------------------------------------------------

Transportation
agreements (i) 3,542 1,060 2,064 418 -
Operating lease (ii) 969 237 499 233 -
----------------------------------------------------------------------------
----------------------------------------------------------------------------


(i) Transportation agreements

The Company has committed to firm-service contracts for the transportation of its natural gas. The amounts above are the minimum obligations that the Company is required to pay under the terms of the contracts.

(ii) Office lease

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.

Flow-through Shares

On September 2, 2010, the Company issued 2,860,000 flow-through shares at $1.75 per share for gross proceeds of $5.0 million. As a result, the Company has a commitment to spend $5.0 million on qualifying Canadian exploration expenditures on or before December 31, 2011. The expenditures were renounced to investors in January 2011, with an effective date of renunciation of December 31, 2010. As at December 31, 2010, $5.0 million of qualifying exploration expenditures have been incurred and the Company has fully satisfied its obligation.

RECENT ACCOUNTING PRONOUNCEMENTS

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 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 completed the design and planning phase of the project, which involved 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, internal controls and business activities. It is not expected that IFRS will result in any significant changes to the Company's business activities.

In 2010, the Company continued to work through the solution development phase, which involves the selection and documentation of IFRS accounting policies and procedures, as well as the development of accounting systems to enable Cinch to track and report the financial information required to prepare financial statements under IFRS. Cinch anticipates selecting the following IFRS accounting policies, however, these may change as the Company finalizes this phase:



-- IAS 1 provides the choice of presenting expenses in the statement of
comprehensive income using a classification based on either their nature
or their function within the entity. Cinch plans to keep the current
expense classification and disclose items by nature in a separate note
to the financial statements.
-- IFRS recommends using the direct method for the statement of cash flows
but does allow the indirect method to be used. Cinch plans to continue
to present the statement of cash flows using the indirect method.
-- IAS 16 provides the option to measure property, plant and equipment
("PP&E") using either the cost model or the revaluation model for each
class of PP&E. Cinch intends to use the cost model to account for PP&E.
-- IAS 16 does not define the oil and gas reserves base to be used in the
calculation of depletion, depreciation and amortization ("DD&A"). Cinch
intends to use total proved reserves and forecast pricing to calculate
its DD&A under IFRS.
-- IFRS 6 provides flexibility on the accounting for exploration and
evaluation ("E&E") assets. Cinch intends to capitalize all types of E&E
expenditures incurred once the legal right to explore has been acquired
until the property has been allocated proved reserves. Cinch does not
intend to amortize its E&E assets and plans to derecognize such assets
when no future value is expected to be derived from them.


During the last quarter of 2010, Cinch finalized its January 1, 2010 opening balance sheet under IFRS, utilizing the following exemptions:



-- The Company applied the amendment to IFRS 1 First Time Adoption of
International Reporting Standards, which allows full cost accounting
companies to elect, at the time of adoption, to measure E&E assets at
the amount determined under the entity's previous GAAP. The amendment
also permits full cost accounting companies to measure, at the time of
adoption, oil and gas assets in the D&P 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.
-- IFRS 3 Business Combinations was not 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 was not applied to equity instruments granted
after November 7, 2002 that vested before January 1, 2010.
-- The Company applied the transitional provision in IFRIC 4 Determining
whether an Arrangement contains a Lease and assessed all arrangements as
at the date of transition.


The Company anticipates making the following adjustments to the opening balance sheet at the date of transition to IFRS. However, these adjustments may change as a result of changes in IFRS standards or changes to the Company's selected policies. Furthermore, readers are cautioned that the calculations indicated below have not been audited by the Company's auditors, nor approved by the Audit Committee or the Board of Directors of the Company and may still be subject to change.



-- Canadian GAAP does not distinguish between E&E assets and D&P assets.
IFRS has a separate reporting standard for assets in the E&E phase. The
Company has classified its PP&E assets at January 1, 2010 into E&E
assets and D&P assets for the IFRS transition balance sheet. The
Company's E&E assets under IFRS at transition are expected to be
approximately $8.6 million. The Company performed a transition date
impairment test on these assets and concluded that they were not
impaired.
-- The Company has allocated the remaining carrying value of PP&E assets to
D&P assets based on the December 31, 2009 independent engineers'
reserves evaluation. Carrying values were allocated to the individual
units of account to facilitate the depletion calculation under IFRS,
which is required at a lower level than under Canadian GAAP.
-- Both IFRS and Canadian GAAP require that oil and gas assets be tested
for impairment. Under Canadian GAAP, impairment testing for oil and gas
assets is a two-step process, comparing discounted cash flow to the
carrying amount only when the carrying amount is not supported by the
undiscounted cash flow. However, under IAS 36, the impairment test is a
one-step process comparing carrying amount to discounted cash flow. The
impairment testing under IFRS is also done at a lower level than under
Canadian GAAP. Due to this change, the Company anticipates recognizing
an impairment of approximately $9.5 million on D&P assets at the
transition date.
-- Cinch is required to recognize asset retirement obligations under both
Canadian GAAP and IFRS. However, under IFRS, the liability is discounted
using a rate that appropriately reflects the risks of the liabilities
and re-measured at each reporting period for changes in the discount
rate. The Company has performed its preliminary calculation for
decommissioning liability at January 1, 2010 and concluded that an
increase of approximately $600,000 to the liability will be recorded at
the transition date.
-- Cinch is required to recognize stock-based compensation under both
Canadian GAAP and IFRS. However, under IFRS, when stock option awards
vest gradually, each tranche must be considered as a separate award.
Furthermore, IFRS requires that forfeitures be estimated on initial
measurement rather than accounted for as they occur. The Company has
performed its preliminary calculation for stock-based compensation and
concluded that a decrease to contributed surplus and an increase to
retained earnings of approximately $50,000 will be recorded at the
transition date.
-- Cinch is required to recognize future taxes under both Canadian GAAP and
IFRS; however, significant differences exist between both standards.
Under Canadian GAAP, the tax liability associated with the renunciation
of flow-through shares is recognized when the expenditures are actually
renounced to investors. Under IFRS, the Company intends to recognize the
tax liability on the effective date of the renunciation. Under IFRS,
taxes arising from the re-measurement of an item that was previously
recognized directly in equity are also recognized in equity, rather than
in income (referred to as "backward tracing"). Under Canadian GAAP, this
backward tracing is prohibited except on business combinations and
financial reorganizations. The Company has performed its preliminary
calculation of the future income tax liability at January 1, 2010 and
expects a decrease in the liability of approximately $1.9 million,
primarily as a result of the impairment recognized on D&P assets. The
Company also expects to reclassify approximately $4.6 million from
retained earnings to share capital as a result of backward tracing of
the tax impact of flow-through shares.


The Company is currently in the process of finalizing the IFRS comparatives for 2010 and has started to account for transactions in 2011 using IFRS accounting policies and procedures. The Company expects to be ready to report first quarter 2011 results under IFRS.

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, if any, 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 personnel, internal calculations, historical and industry experience.

Cost Estimates

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

Asset Retirement Obligations

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

Income Taxes

The Company records future tax liabilities to account for the expected future tax consequences of events that have been recorded in its financial statements. These amounts are estimates; the actual tax consequences may differ from the estimates due to changing tax rates and regimes, as well as changing estimates of cash flow 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 oil and gas exploration and production industry is cyclical in nature. The Company's financial position, results of operations and cash flows are significantly impacted by commodity price variations, particularly natural gas prices. Commodity price changes can also indirectly impact expected production by changing the amount of funds available to reinvest in exploration and development activities. Decreases in commodity prices not only reduce revenues and cash flows available for exploration, they may also challenge the economics of potential capital projects by reducing the quantities of reserves that are commercially recoverable.

Natural gas prices have fluctuated greatly in the past few years directly impacting the Company's revenues and cash flow available to fund the Company's capital program. In the latter half of 2008, global commodity prices declined and remained soft throughout most of 2009, until the fourth quarter, when commodity prices began to stabilize with the first signs of economic recovery. This stabilization continued into the first few months of 2010, but natural gas prices began to decrease again near the end of the first quarter of 2010 and continued to remain weak throughout 2010 and entering the first few months of 2011. Despite the challenges that the Company has faced in the past few years with depressed natural gas prices, the Company continues to work on achieving growth. The Company's average production has gone from 2,031 BOE per day in 2008 to 2,374 BOE per day in 2009 to 2,580 BOE per day in 2010. The increase in production has helped to offset the impact of the weakened natural gas prices over the past few years.

The Company's capital program is dependent on cash flow generated by operations and access to capital markets. In 2008, Cinch generated $21 million of cash flow and therefore was able to fund a $32 million capital budget. Cinch's 2009 capital budget was significantly lower than the previous year at $6.3 million (net of dispositions) mostly due to the decrease in cash flow generated caused by the significant decrease in commodity prices from 2008 to 2009. In 2010, Cinch completed two financings, generating $55.8 million net to the Company, which allowed Cinch to proceed with an active capital program for 2010, totaling $51.0 million of capital spending throughout the year. With depressed natural gas prices, access to capital markets to fund capital programs could become increasingly challenging thereby potentially forcing the company in the future to align its capital budget with cash flows generated.



SELECTED ANNUAL AND QUARTERLY INFORMATION
(000's, except per share data, or as indicated)

Q1 Q2 Q3 Q4 Annual
----------------------------------------------------------------------------
2010 $ $ $ $ $
----------------------------------------------------------------------------
Petroleum and natural gas
sales, net of
transportation and before
royalties 7,115 6,431 5,719 6,408 25,673
Funds from operations 2,960 2,878 2,869 2,998 11,705
Per share - basic 0.04 0.03 0.03 0.03 0.14
- diluted 0.04 0.03 0.03 0.03 0.14
Net loss (1,306) (1,865) (2,123) (1,416) (6,710)
Per share - basic (0.02) (0.02) (0.02) (0.01) (0.08)
- diluted (0.02) (0.02) (0.02) (0.01) (0.08)
Capital expenditures 15,063 5,719 10,029 20,208 51,019
Total assets 138,020 138,708 152,481 159,210 159,210
Working capital (net debt) (6,503) (8,941) 4,718 (12,485) (12,485)
----------------------------------------------------------------------------
Average production (BOE/d) 2,302 2,535 2,627 2,850 2,580
----------------------------------------------------------------------------
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 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)
----------------------------------------------------------------------------
Average 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 130,566 132,156 142,147 141,423 141,423
Working capital (net debt) (29,160) (26,424) (32,994) (35,308) (35,308)
----------------------------------------------------------------------------
Average production (BOE/d) 1,579 1,991 2,049 2,501 2,031
----------------------------------------------------------------------------
Note: numbers may not cross-add due to rounding


Financial Statements

Cinch Energy Corp.

December 31, 2010




CINCH ENERGY CORP.

BALANCE SHEETS

As at December 31, 2010 2009
$ $
----------------------------------------------------------------------------
ASSETS (note 6)

Current
Cash (note 12) 42,704 -
Accounts receivable (notes 4 & 12) 6,003,942 3,872,925
Prepaid expenses and deposits 911,143 1,236,359
----------------------------------------------------------------------------
6,957,789 5,109,284

Property, plant and equipment (note 5) 152,252,106 119,762,409
----------------------------------------------------------------------------

159,209,895 124,871,693
----------------------------------------------------------------------------
----------------------------------------------------------------------------
LIABILITIES AND SHAREHOLDERS' EQUITY

Current
Accounts payable and accrued liabilities
(note 12) 19,443,198 8,034,501
Credit facility (notes 6 and 12) - 26,519,080
----------------------------------------------------------------------------
19,443,198 34,553,581
Asset retirement obligations (note 7) 4,873,169 4,035,866
Future income taxes (note 8) 5,289,000 7,623,800
----------------------------------------------------------------------------
29,605,367 46,213,247
----------------------------------------------------------------------------
Commitments (note 11)

Shareholders' equity
Share capital (note 10) 156,021,449 99,299,173
Contributed surplus (note 10) 4,937,330 4,003,427
Deficit (31,354,251) (24,644,154)
----------------------------------------------------------------------------
129,604,528 78,658,446
----------------------------------------------------------------------------
159,209,895 124,871,693
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying notes


CINCH ENERGY CORP.

STATEMENTS OF OPERATIONS, COMPREHENSIVE LOSS AND DEFICIT

For the years ended December 31, 2010 2009
$ $
----------------------------------------------------------------------------

Revenue
Oil and gas sales 27,237,148 23,645,561
Transportation (1,564,598) (1,504,934)
Royalties (note 13) (4,611,343) (3,419,367)
Other income 75,558 51,370
----------------------------------------------------------------------------
21,136,765 18,772,630
----------------------------------------------------------------------------

Expenses
Operating (note 13) 4,183,120 3,947,978
General and administrative (note 10) 6,221,910 4,704,827
Interest on credit facility 192,457 1,077,222
Accretion of asset retirement obligations
(note 7) 262,979 224,523
Depletion and depreciation 19,103,496 20,891,667
----------------------------------------------------------------------------
29,963,962 30,846,217
----------------------------------------------------------------------------

Loss before income taxes (8,827,197) (12,073,587)

Taxes (note 8)
Current income tax expense - -
Future income tax recovery 2,117,100 3,169,600
----------------------------------------------------------------------------
2,117,100 3,169,600
----------------------------------------------------------------------------

Net loss and comprehensive loss for the year (6,710,097) (8,903,987)

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

Deficit, end of year (31,354,251) (24,644,154)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Net loss and comprehensive loss for the year
per share (note 10)

Basic and diluted (0.08) (0.16)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

See accompanying notes


CINCH ENERGY CORP.

STATEMENTS OF CASH FLOWS

For the years ended December 31, 2010 2009
$ $
----------------------------------------------------------------------------

Operating activities
Net loss for the year (6,710,097) (8,903,987)
Add (deduct) non-cash items:
Depletion and depreciation 19,103,496 20,891,667
Accretion of asset retirement obligations 262,979 224,523
Non-cash compensation expense (note 10) 1,165,401 436,821
Future income tax recovery (2,117,100) (3,169,600)
----------------------------------------------------------------------------
11,704,679 9,479,424
Net change in non-cash working capital 102,094 (1,975,818)
----------------------------------------------------------------------------
Cash provided by operating activities 11,806,773 7,503,606
----------------------------------------------------------------------------

Investing activities
Additions to property, plant and equipment (51,018,869) (10,971,263)
Dispositions (net of acquisitions) of property,
plant and equipment - 4,629,670
Net change in non-cash working capital 9,500,802 (2,048,901)
----------------------------------------------------------------------------
Cash used in investing activities (41,518,067) (8,390,494)
----------------------------------------------------------------------------

Financing activities
Decrease in credit facility (26,519,080) (1,838,953)
Issue of common shares, net of issue costs 56,273,078 2,725,841
----------------------------------------------------------------------------
Cash provided by financing activities 29,753,998 886,888
----------------------------------------------------------------------------

Change in cash 42,704 -

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

Cash, end of year 42,704 -
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Supplemental information:
Cash taxes paid - -
Cash interest paid 192,457 1,077,222
----------------------------------------------------------------------------
----------------------------------------------------------------------------

See accompanying notes


CINCH ENERGY CORP.

NOTES TO FINANCIAL STATEMENTS

December 31, 2010 and 2009

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 acquisitions, 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 proven 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 proven plus probable reserves plus the cost of undeveloped 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 undeveloped 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, comprehensive loss 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 10. The Company has adopted the fair value based method of accounting for stock options. Stock option expense is recorded as a general and administrative expense for all options 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 cash, accounts receivable, accounts payable, accrued liabilities and the credit facility. 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

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 has selected appropriate accounting policies for reporting under IFRS. The Company has also assessed the impact the changeover will have on current procedures, information technology, accounting systems and internal controls.

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 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. This standard has no impact on the Company's financial statements.

4. ACCOUNTS RECEIVABLE

A substantial portion of the Company's accounts receivable is with oil and gas marketing entities and joint venture partners. 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. As at December 31, 2010, approximately 95% of accounts receivable was less than 30 days overdue.



5. PROPERTY, PLANT AND EQUIPMENT

As at December 31, 2010
----------------------------------------------------------------------------
Accumulated
depletion and Net
Cost depreciation book value
$ $ $
----------------------------------------------------------------------------
Petroleum and natural gas
properties 253,584,209 (101,355,729) 152,228,480
Office furniture and equipment 302,224 (278,598) 23,626
----------------------------------------------------------------------------
253,886,433 (101,634,327) 152,252,106
----------------------------------------------------------------------------
----------------------------------------------------------------------------


As at 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
----------------------------------------------------------------------------
----------------------------------------------------------------------------


For the years ended December 31, 2010 and 2009, no indirect general and administrative expenditures were capitalized.

As at December 31, 2010, $16,365,845 of costs related to undeveloped properties were excluded from costs subject to depletion (December 31, 2009 - $8,002,048) and $40,059,000 of future development costs were included in costs subject to depletion (December 31, 2009 - $44,719,000).

The Company has performed a ceiling test as at December 31, 2010 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
----------------------------------------------------------------------------
2011 4.16 86.22
2012 4.74 89.29
2013 5.31 90.92
2014 5.77 92.96
2015 6.22 96.19
----------------------------------------------------------------------------
Each benchmark price increased on average approximately 2% from 2016 and
thereafter

----------------------------------------------------------------------------
----------------------------------------------------------------------------

There was no impairment at December 31, 2010.


6. CREDIT FACILITY

As at December 31, 2010, the Company had revolving demand bank credit facilities through ATB Financial totaling $50,000,000 (December 31, 2009 - $43,000,000). The primary facility of $40,000,000 bears interest at the lender's prime rate plus margins ranging from 1.0% to 2.25% based on financial statement ratios. The second facility of $10,000,000 bears interest at the lender's prime rate plus margins ranging from 2.50% to 3.75% based on financial statement ratios. The effective interest rate for the year ended December 31, 2010 was 3.75% (December 31, 2009 - 3.78%). As at December 31, 2010, there were no amounts outstanding on the credit facilities (December 31, 2009 - $26,519,080). As collateral for the facilities, 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.

7. 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, 2010 is $7,275,263 (December 31, 2009 - $6,555,980) with an average abandonment date of 13 years (2009 - 16 years). The Company used a credit adjusted, risk-free rate ranging from 5% to 10% and an inflation rate of 2% to arrive at the recorded liability of $4,873,169 at December 31, 2010 (December 31, 2009 - $4,035,866). In the first quarter of 2010 and in December 2010, the estimated abandonment dates of some of the wells were revised to better reflect the economic life of the wells which increased the present value of the liability when compared to December 31, 2009.

The Company's asset retirement obligations changed as follows:



December 31, 2010 December 31, 2009
----------------------------------------------------------------------------
$ $
----------------------------------------------------------------------------

Asset retirement obligations,
beginning of year 4,035,866 3,838,337
Revisions to estimates 412,305 (45,110)
Liabilities incurred 222,338 63,525
Liabilities settled (60,319) (45,409)
Accretion expense 262,979 224,523
----------------------------------------------------------------------------

Asset retirement obligations, end of
year 4,873,169 4,035,866
----------------------------------------------------------------------------
----------------------------------------------------------------------------


8. FUTURE INCOME TAXES

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



2010 2009
----------------------------------------------------------------------------

Net loss before income taxes $8,827,197 $12,073,587
Statutory income tax rate 28.11% 29.24%

$ $
----------------------------------------------------------------------------
Anticipated income tax recovery 2,481,325 3,530,317
Decrease resulting from:
Rate adjustment (32,723) (221,902)
Stock based compensation expense (327,594) (127,726)
Non-deductible items (3,908) (11,089)
----------------------------------------------------------------------------

Future income tax recovery 2,117,100 3,169,600
----------------------------------------------------------------------------
----------------------------------------------------------------------------


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:



As at December As at December
31, 2010 31, 2009
----------------------------------------------------------------------------
$ $
----------------------------------------------------------------------------
Net book value of capital assets in excess
of tax pools (8,331,481) (8,820,792)
Non-capital losses 972,700 -
Share issue costs 757,371 70,082
Asset retirement obligations 1,228,265 1,042,868
Other 84,145 84,042
----------------------------------------------------------------------------

Future income tax liability (5,289,000) (7,623,800)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


As at December 31, 2010, the Company had unused non-capital losses of $3,859,957 (2009 - $nil) which expire in 2029.

9. 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 deficit, contributed surplus 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 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. 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 half times. The net debt to funds from operations ratio at December 31, 2010 was 1.07 (December 31, 2009 - 3.11), which is in line with the Company's objectives. The net debt to funds from operations ratio was positively impacted by the financings completed in January 2010 and September 2010.

The net debt to funds from operations ratio may increase or decrease at certain times as a result of significant events such as acquisitions or dispositions, share issuances, as well as large fluctuations in commodity prices. To facilitate the management of this ratio, the Company prepares annual budgets and monthly forecasts, which are updated depending on varying factors such as general market conditions and successful capital deployment. The annual budget is approved by the Board of Directors and reviewed as required.

The Company has various banking reporting requirements with respect to its credit facilities that the Company has complied with for the year ended December 31, 2010. In addition, the bank credit facilities contain a financial covenant requiring that the Company's ratio of current assets plus the undrawn balance on the credit facilities to the current liabilities less the balance outstanding on the credit facilities not fall below 1:1. As at December 31, 2010, this ratio was 2.92:1, thereby satisfying the financial covenant. As collateral for the bank credit facilities, 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 by the bank credit facilities, 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.



10. SHARE CAPITAL

Authorized - Unlimited number of common voting shares without par value

December 31, 2010 December 31, 2009
----------------------------------------------------------------------------
Issued Number $ Number $
----------------------------------------------------------------------------
Common shares
Balance, beginning of year 58,860,365 99,299,173 55,631,798 96,560,099
Issued for cash on
financings (i) 37,250,050 59,369,233 3,211,900 2,730,115
Tax effect of flow-through
shares (ii) - (688,100) - -
Issue costs, net of future
taxes of $905,800 (i) - (2,687,455) - (15,541)
Exercise of stock options (iii) 520,000 728,598 16,667 24,500
----------------------------------------------------------------------------
Share capital, end of year 96,630,415 156,021,449 58,860,365 99,299,173
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Contributed surplus
Balance, beginning of year 4,003,427 3,574,439
Non-cash compensation
expense (iv) 1,165,401 436,821
Transfer to share capital
(iii) (231,498) (7,833)
----------------------------------------------------------------------------
Contributed surplus, end of
year 4,937,330 4,003,427
----------------------------------------------------------------------------
----------------------------------------------------------------------------


(i) Financings

On January 28, 2010, the Company issued a total of 22,493,300 common shares at $1.65 per share for proceeds of $37,113,945 before total issue costs of $2,164,230 ($1,608,230 net of tax). Net proceeds from the offering were used to fund the Company's exploration and development program and for general corporate purposes.

On September 2, 2010, the Company issued a total of 11,896,750 common shares at $1.45 per share and 2,860,000 common shares issued on a flow-through basis at $1.75 per share for total proceeds of $22,255,288 before total issue costs of $1,429,025 ($1,079,225 net of tax). Net proceeds from the offering, which were temporarily used to reduce outstanding indebtedness, are being used primarily to fund the Company's ongoing exploration and development program. As a result of the issuance of flow-through shares, the Company has a commitment to spend $5.0 million on qualifying Canadian exploration expenditures on or before December 31, 2011. The expenditures were renounced to investors in January 2011, with an effective date of renunciation of December 31, 2010. As at December 31, 2010, $5.0 million of qualifying exploration expenditures have been incurred and the Company has satisfied the obligation.

(ii) 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 had fully satisfied this obligation. The tax benefit of $688,100, related to the flow-through shares, was renounced in its entirety in February 2010.

(iii) Exercise of Options

On January 11, 2010, 80,001 stock options were exercised for a total cash consideration of $84,401 (80,001 stock options at an average price of $1.05) which was recorded as an increase to share capital. Due to the exercise of the stock options, $37,466 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.

On March 10, 2010, 9,999 stock options were exercised for a total cash consideration of $8,399 (9,999 stock options at an average price of $0.84) which was recorded as an increase to share capital. Due to the exercise of the stock options, $4,033 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 the month of April 2010, 430,000 stock options were exercised for a total cash consideration of $404,300 (430,000 stock options at an average price of $0.94) which was recorded as an increase to share capital. Due to the exercise of the stock options, $189,999 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 the year ended December 31, 2010, a total of $728,598 was recorded in share capital as a result of stock options exercised.

(iv) Stock Options

Non-cash compensation expense recorded in general and administrative expenses 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 84,864,727 (2009 - 56,734,001). As at December 31, 2010, all of the stock options are anti-dilutive and therefore not included in the determination of dilutive per share amounts.

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 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. Options are granted at exercise prices equal to the estimated fair value of the shares at the date of grant and may not exceed a ten year term. The vesting for options granted occurs over a three year period, with one third of the number granted vesting on each of the first, second, and third anniversary dates of the grant unless otherwise specified by the Board of Directors at the time of grant.

The following is a continuity of stock options for which shares have been reserved:



As at December As at December
31, 2010 31, 2009
----------------------------------------------------------------------------
Number of Weighted Number of Weighted
options average options average
exercise exercise
price price
$ $
----------------------------------------------------------------------------
Stock options outstanding,
beginning of period 5,749,500 1.34 5,509,833 1.51
Granted 3,865,000 1.32 1,050,000 0.81
Expired (715,000) 2.60 (587,000) 1.87
Forfeited (229,999) 1.86 (206,666) 1.63
Exercised (520,000) 0.96 (16,667) 1.00
----------------------------------------------------------------------------
Stock options outstanding, end of
period 8,149,501 1.23 5,749,500 1.34
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Stock options outstanding as at December 31, 2010 are comprised of the
following:

Weighted
average
Weighted average Number of price of
Number of remaining life exercisable exercisable
Exercise price options (years) options options
----------------------------------------------------------------------------
$ $
----------------------------------------------------------------------------

0.70 - 1.00 2,829,501 2.56 1,977,836 0.88
1.01 - 1.50 3,910,000 4.02 620,000 1.25
1.51 - 2.00 775,000 3.44 200,000 1.52
2.01 - 2.50 585,000 0.23 585,000 2.22
2.51 - 2.57 50,000 0.08 50,000 2.57
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1.23 8,149,501 3.16 3,432,836 1.24
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The fair value of stock options granted to employees, directors, and consultants during the years ended December 31, 2010 and 2009, 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 (2009 - zero percent), expected volatility of 75.44 percent (2009 - 73.90 percent), risk-free interest rate of 2.03 percent (2009 - 2.27 percent), and an expected life of four years (2009 - four years). Outstanding options granted during the year ended December 31, 2010 had an estimated weighted average fair value of $0.75 per option (December 31, 2009 - $0.45 per option), for a total estimated value of $2,895,502 (2009 - $472,500). For the year ended December 31, 2010, a total of $1,165,401 (2009 - $436,821) has been recognized as stock-based compensation expense in general and administrative expenses with an offsetting credit to contributed surplus.

11. COMMITMENTS

As at December 31, 2010, the Company has the following commitments over the next five years:



Total 2011 2012 2013 2014 Thereafter
$ $ $ $ $ $
----------------------------------------------------------------------------

Transportation
agreements (i) 3,541,795 1,060,262 1,090,227 973,349 265,304 152,653
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Office lease (ii) 968,752 237,162 245,692 253,512 232,386 -
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(i) Transportation agreements

The Company has committed to firm-service contracts for the transportation of its natural gas. The amounts above are the minimum obligations that the Company is required to pay under the terms of the contracts.

(ii) Office lease

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.

12. FINANCIAL INSTRUMENTS

Analysis of Financial Assets and Liabilities by Measurement Basis

Financial assets and financial liabilities are measured on an ongoing basis at cost, fair value or amortized cost. The following table analyzes the carrying amounts of the financial assets and liabilities by category as defined by Section 3855 of the CICA Handbook:



Carrying value of financial instruments:

As at December 31, 2010
----------------------------------------------------------------------------
Other Total
Held for Loans and financial carrying
trading receivables liabilities value
$ $ $ $
----------------------------------------------------------------------------
Financial assets
Cash 42,704 - - 42,704
Accounts receivable - 6,003,942 - 6,003,942
----------------------------------------------------------------------------

Financial liabilities
Accounts payable and accrued
liabilities - - 19,443,198 19,443,198
----------------------------------------------------------------------------
----------------------------------------------------------------------------


As at December 31, 2009
----------------------------------------------------------------------------
Other Total
Loans and financial carrying
receivables liabilities value
$ $ $
----------------------------------------------------------------------------

Financial assets
Accounts receivable 3,872,925 - 3,872,925
----------------------------------------------------------------------------

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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----------------------------------------------------------------------------


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 value 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 value based on valuation models or by reference to other similar products in active markets. As at December 31, 2010 and 2009, the Company did not have any financial instruments measured at fair value.

Financial instruments recognized on the balance sheet consist of cash, accounts receivable, accounts payable, and the credit facility. As at December 31, 2010 and 2009, there was no significant difference between the carrying amounts of these financial instruments reported on the balance sheet 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 risk 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 its 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 revenues are 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 earnings before tax for 2010 by $4.6 million (2009 - $4.0 million). A similar decrease in commodity prices would have the opposite impact. As at December 31, 2010, the Company's natural gas and liquids production continues to be unhedged and is marketed in the Alberta and British Columbia spot markets.

As at December 31, 2010, 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 facilities. The credit facilities have floating interest rates which fluctuate based on prevailing market conditions. As at December 31, 2010, $nil (2009 - $26.5 million) is subject to movements in floating interest rates. If interest rates on the floating credit facilities were 1% lower, it is estimated that year to date earnings before tax would increase by approximately $51 thousand (2009 - $265 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 and marketers included in accounts receivable. 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 the third party credit risk is to minimize losses in financial assets. The Company assesses the credit quality of the 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 receivables on a semi-monthly basis. As at December 31, 2010, the Company held capital advances of $62 thousand (2009 - $130 thousand). As at December 31, 2010 and December 31, 2009, no receivable balance has been deemed uncollectible or written off during the period.

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 facilities. As at December 31, 2010, the Company did not have any balance outstanding against its available credit facilities of $50.0 million.

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 sheet and adjust its forecasted spending accordingly.

13. RECLASSIFICATION

In the second quarter of 2010, the Company changed the classification of gas processing credits received from the Government of Alberta under the New Royalty Framework, which was implemented January 1, 2009. These credits were previously presented as a reduction to operating expenses and are now presented as a reduction to royalties. There is no impact on the reported net loss for the year ended December 31, 2010. The effect of these changes for the year ended December 31, 2009 is as follows:



Year ended December 31, 2009
----------------------------------------------------------------------------
As previously
classified Adjustment Reclassified
$ $ $
----------------------------------------------------------------------------
Royalties (4,347,143) 927,776 (3,419,367)
Operating 3,020,202 927,776 3,947,978
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