Cinch Energy Corp.
TSX : CNH

Cinch Energy Corp.

March 05, 2009 16:05 ET

Cinch Energy Corp. Releases 2008 Results

CALGARY, ALBERTA--(Marketwire - March 5, 2009) - Cinch Energy Corp ("Cinch" or the "Company") (TSX:CNH) is pleased to announce its financial and operational results for the year ended December 31, 2008.

2008 Accomplishments

- Increased production by 52% from 1340 BOE/d to 2031 BOE/d

- 4th Quarter average production was 2501 BOE/d

- Successful Wabamun discovery at Dawson, which tested at 6.4 mmcf/d (85% net)

- Obtained approval for increased well density at the Kakwa E Dunvegan pool

- Proven plus Probable Reserves increased by 17% from 6.3 MMBOE's to 7.3 MMBOE's

- Increased land holdings at Dawson, British Columbia to 56 gross sections (net average working interest 45%) with Montney rights in 25 sections

Our Chairman noted in his 2007 message to shareholders that 2008 would be a "breakout" year and it certainly was with the Kiskatinaw natural gas discovery at Dawson, British Columbia in 2007, which was followed up successfully in 2008. The 2008 year continued to be an exciting year for the Company with significant production growth and again a new exploration discovery in the Wabamun horizon at Dawson which tested at 6.4 mmcf/d. These deeper exploration discoveries have delayed the Montney drilling projects, as the discovery of these deeper horizons has had a significant impact on Cinch's growth. During this period, offsetting operators have exploited the Montney horizon on their lands which has assisted Cinch in evaluating this unconventional natural gas zone on its own lands. In addition, the deeper zone potential mitigates the risks in the area as Cinch is able to evaluate the shallower Montney horizon when it drills to these deeper formations. During 2008 Cinch participated in a total of 14 wells of which 12 wells (6.04 net) were cased as potential gas wells, one farm-out well was abandoned and another well was abandoned in the shallower zone and deepened to the Wabamun. With continued exploration success and increased natural gas prices during the second half of 2008, Cinch increased its capital budget from a projected $20.3 million to approximately $33 million in 2008.

Outlook

The oil and gas industry has faced numerous fiscal changes by both the Federal and Provincial Governments in the past several years, most of which we have been able to accommodate. We now face significant new challenges in the overall economy which will affect our business. Cinch, however, has had a very exciting year in 2008 with new discoveries and corresponding growth in production. We remain very excited about these discoveries, which are located in British Columbia, and hence remain optimistic regarding the future of your Company. Cinch also has numerous opportunities in Alberta, which will be re-evaluated economically based on the March 3, 2009 announcement by the Alberta Government to provide additional incentive programs to stimulate oil and gas drilling activity in Alberta. At this time these new incentive programs have not been fully evaluated by Cinch.

The Company has budgeted for a capital program of $15 million which will be funded from existing cash flows and its bank credit facility, if required. This budget is based on natural gas prices of $5/mcf and natural gas liquids prices of $50/barrel. Your management believes that prices will improve into the third quarter of 2009 over those that we are currently experiencing. Cinch will review the economic situation and consider increasing its capital program should there be signs of commodity price improvement. Production will continue to grow over that of 2008 with the commencement of production from the 6-6 Wabamun well. Notwithstanding the reduced capital budget, Cinch's prospects are of the type that with success, we can continue to grow during these turbulent times. A Wabamun well is budgeted for in the third quarter and with the recent success in the Montney, we are anticipating participating in our first horizontal well during the summer. To process the Montney gas from future wells, the Company and its partner are in the planning stages to construct a processing facility near its current meter station on the Dawson property. These upcoming projects are very exciting for your Company and will enable the Company to position itself for future growth.



HIGHLIGHTS
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Three Months Ended Year Ended
December 31, December 31,
2008 2007 2008 2007
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Petroleum and natural gas
sales, net of transportation
($000's) 9,679 6,588 40,624 22,691
Production per day
Natural gas (Mcf/d) 13,634 7,749 10,670 6,687
Natural gas liquids (Bbl/d) 229 258 253 226
Equivalence at 6:1 (BOE/d) 2,501 1,549 2,031 1,340

Sales Price
Natural gas ($/Mcf) 6.91 6.61 8.41 6.99
Natural gas liquids ($/Bbl) 48.35 79.29 84.34 68.48
Equivalence at 6:1 ($/BOE) 42.06 46.22 54.64 46.38

$ $ $ $
Funds from operations
(000's) (1) 4,371 3,217 21,456 10,782
- per share, basic(1) 0.08 0.06 0.39 0.20
- per share, diluted(1) 0.08 0.06 0.38 0.20

Net Income (Loss) (000's) (3) (1,435) 466 1,167 (15,695)
- per share, basic (0.03) 0.01 0.02 (0.29)
- per share, diluted (0.03) 0.01 0.02 (0.29)

Capital expenditures ($000's) 6,685 2,917 32,014 20,926
Basic weighted average shares
outstanding (000's) 55,632 55,625 55,627 54,485
Working capital (net debt)(2)
($000's)
As at December 31, 2008 (35,308)
As at December 31, 2007 (24,758)

As at March 4, 2009
Common Shares Outstanding 55,631,798
Options outstanding 5,366,500
- average exercise price 1.49
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(1) Funds from operations and funds from operations per share is not a
generally accepted accounting principle ("GAAP") measure and represents
cash provided by operating activities on the statement of cash flows
less the effect of changes in non-cash working capital related to
operating activities.

(2) Net debt is a non-GAAP measure and represents the sum of the working
capital (deficiency) and the outstanding credit facility balance.

(3) Net loss for the year ended December 31, 2007 includes a goodwill
write-down of $14,616,996.


AREAS OF EXPLORATION

During 2008, Cinch continued its exploration program in its core areas of Chime, Kakwa, as well as the Dawson West area of British Columbia.

Chime

The Chime property, acquired through a farm-in arrangement in late 2002, is located in northwestern Alberta, approximately 110 kilometres south of Grande Prairie. In 2008, Cinch participated in 2 gross (0.57 net) exploratory wells on the Chime block. Both of the non-operated wells, 14-06 and 14-26 were cased as potential gas wells. To date, one well is on stream at approximately 750 mcf/d (gross) while the other has yet to be tied-in. Currently, there are no wells budgeted for the Chime property in 2009.

The Chime property consists of 11,680 gross (5,563 net) acres of developed land and 27,520 gross (10,553 net) acres of undeveloped land and Cinch is the operator of most of these lands.

Kakwa

The Kakwa property is located approximately 100 kilometres south of Grande Prairie. In 2008, the Company continued to develop the Kakwa E Pool with the drilling of three infill wells, with working interests averaging approximately 46%. All three wells are now on stream at a combined rate of approximately 1.2 mmcf/d (net). The Company also re-entered and re-drilled a 100% well in the Kakwa H Pool which is also on production.

The Kakwa property consists of 14,080 gross (3,430 net) acres of developed land and 7,680 gross (3,430 net) acres of undeveloped land.

Dawson West

In 2008, the Company participated in seven gross (3.48 net) wells. The 6-6 well (40% working interest) was drilled as a Kiskatinaw test early in the year and was then deepened to the Wabamun at Cinch's sole expense on a farm-out arrangement with our partner. The well flowed gas at a gross rate of 6.4 mmcf/d (85% working interest) and is expected to come on stream in March 2009 at rates of approximately 5 mmcf/d (gross). A follow up Wabamun test (65% working interest) was drilled late in 2008 and is currently shut-in for pressure build up and possibly further evaluation. A successful farm-in well was drilled at 13-11 (40.3% working interest) and is currently producing at 700 mcf/d (gross) from the Kiskatinaw zone. The Company also drilled a well at 12-27 (38% working interest) which offsets our 2007 Kiskatinaw success at 1-32. This well came on production in late October 2008 and is currently producing at rates of approximately 7.5 mmcf/d (gross). A Kiskatinaw test was drilled at 6-1 (40% working interest) however, the completion attempt in the Kiskatinaw zone proved unsuccessful. The Montney zone was then completed in this well resulting in a flow test of 2.6 mmcf/d (gross) along with natural gas liquids of 39 barrels per mmcf. This is a very successful vertical zone completion and has prompted the Company to budget for a horizontal Montney well to be drilled near this location some time in the summer months. The 10-15 (40% working interest) Kiskatinaw test was cased to total depth and a completion attempt on the Kiskatinaw and Montney horizons is planned during the first quarter of 2009.

Cinch holds 30,440 gross undeveloped acres (13,720 net undeveloped acres) in the Dawson Area, of British Columbia and is continuing to expand on its land holdings in this area.



Wells Drilled
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December 31, 2008 December 31, 2007
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Gross Net Gross Net
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Natural gas 12 6.04 6 2.30
Oil - - - -
Dry and abandoned 2 0.45 2 0.33
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Total 14 6.49 8 2.63
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Undeveloped Land

Cinch's undeveloped land base of 77,453 gross acres (35,579 net acres) continues to represent a significant asset to the Company. In 2008, the Company experienced expiries of undeveloped lands in the Chime Area of Alberta, however, the Company has expanded its undeveloped land holdings in the Dawson Area of British Columbia to 30,440 gross undeveloped acres (13,720 net undeveloped acres) with an average working interest of 45%. In 2008, the Dawson Area of British Columbia continued to see a developing Montney gas play with continued drilling activity and competitive land sale activity. Based on an internal evaluation, Cinch places a value of approximately $12.9 million on its undeveloped lands by taking into account land sales in the area.

The Company continues to hold a high average net working interest of 46% in its undeveloped land inventory, the majority of which is operated by Cinch.



Undeveloped Land Holdings
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December 31, 2008 December 31, 2007
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Gross Acres 77,453 113,942
Net Acres 35,579 48,641
Average Working Interest 46% 43%
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RESERVES

The corporate reserves estimates, effective December 31, 2008, 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"). Also presented is some reserve information using "Company Interest" which is defined as the Company's total working interest share before deduction of royalties payable to others and including any royalty interest of Cinch.

The Company interest reserve highlights are:

- Total proven reserves at December 31, 2008 increased 20% to 5.3 million BOE compared to 4.4 million BOE at December 31, 2007.

- Total proven plus probable reserves at December 31, 2008 increased 17% to 7.3 million BOE compared to 6.3 million BOE at December 31, 2007.

- On a proven plus probable basis, the finding, development and acquisition costs were $19.11 per BOE ($21.25 per BOE on a proven basis)



FORECASTED PRICES AND COSTS

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

----------------------------------------------------------------------------
Light
and Variance
Medium Natural (2008
Crude Gas Natural Total Total vs
Oil Liquids Gas 2008 2007 2007)
(mbbls) (mbbls) (mmcf) (mboe) (mboe) (mboe)
----------------------------------------------------------------------------
Proved -Developed Producing 20 584 21,890 4,252 3,837 415
-Dev. Non-Producing - 46 4,720 833 549 284
-Undeveloped - - 1,044 174 - 174
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Total Proved 20 630 27,654 5,259 4,386 873
Probable 8 235 10,883 2,057 1,884 173
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Total Proved Plus Probable 28 865 38,537 7,316 6,270 1,046
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Note: May not add due to rounding

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

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

----------------------------------------------------------------------------
Discounted at
----------------------------------------------------------------------------
Undiscounted 8% 10% 15% 20%
December 31, 2008(1)(2),(3) ($M) ($M) ($M) ($M) ($M)
----------------------------------------------------------------------------
Proved -Developed Producing 135,868 84,379 77,566 65,113 56,637
-Dev. Non-Producing 28,404 18,666 17,268 14,641 12,798
-Undeveloped 3,540 1,732 1,469 975 631
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Total Proved 167,812 104,777 96,303 80,729 70,066
Probable 83,167 25,556 21,382 15,082 11,572
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Total Proved Plus Probable 250,978 130,333 117,686 95,811 81,638
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Note: May not add due to rounding

(1) Utilizing GLJ January 1, 2009 price forecast

(2) As required by NI 51-101, undiscounted well abandonment costs of $1.9
million for total proved reserves and $2.4 million for total proved
plus probable reserves are included in the net present value of future
net revenues determination.
(3) Prior to provision of income taxes, interest, debt service charges and
general and administrative expenses. It should not be assumed that the
undiscounted and discounted future net revenues estimated by GLJ
represent the fair market value of the reserves.


Pricing Assumptions - Forecasted Prices and Costs

The January 1, 2009 pricing forecasts presented below have been prepared by GLJ. These prices have been utilized in determining the reserves and cash flow forecasts above.



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Oil
---------------------------------------
Edmonton Hardisty
WTI Par Price Heavy 12
Cushing 40 degrees degrees
Oklahoma API API
Year ($US/Bbl) ($Cdn/Bbl) ($Cdn/Bbl)
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Forecast
2009 57.50 68.61 43.10
2010 68.00 78.94 49.76
2011 74.00 83.54 54.35
2012 85.00 90.92 59.23
2013 92.01 95.91 62.54
2014 93.85 97.84 63.82
2015 95.73 99.82 65.13
2016 97.64 101.83 66.46
2017 99.59 103.89 67.83
2018 101.59 105.99 69.22
Thereafter +2%/yr +2%/yr +2%/yr
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Natural Gas Liquids
--------------------------------------------
Natural
Gas Alberta
Plant Edmonton
Gate Price Edmonton Edmonton Pentanes Inflation Exchange
($Cdn/ Propane Butane Plus Rates(a) Rate(b)
Year MMBtu) ($Cdn/Bbl ($Cdn/Bbl) ($Cdn/Bbl) %/year ($US/$Cdn)
----------------------------------------------------------------------------
Forecast
2009 7.34 43.22 52.14 69.98 2 0.825
2010 7.70 49.73 61.57 80.52 2 0.85
2011 8.10 52.63 65.16 85.21 2 0.875
2012 8.46 57.28 70.92 92.74 2 0.925
2013 8.70 60.42 74.81 97.82 2 0.95
2014 8.89 61.64 76.32 99.80 2 0.95
2015 9.09 62.89 77.86 101.81 2 0.95
2016 9.28 64.15 79.43 103.87 2 0.95
2017 9.49 65.45 81.03 105.97 2 0.95
2018 9.70 66.77 82.67 108.10 2 0.95
Thereafter +2%/yr +2%/yr +2%/yr +2%/yr 2%/yr 0.95
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RESERVE RECONCILIATION

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

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Crude Oil NGL's
(mbbls) (mbbls)
--------------------------------------
Total Total
Proved Proved
Plus Plus
Proved Probable Proved Probable
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Opening Balance
December 31, 2007 22.4 32.3 590.7 827.7
Technical 6 3.9 45.3 43.4
Exploration Discoveries - - - -
Drilling Extensions - - 50.9 45.7
Infill Drilling - - 27.4 32.8
Improved Recovery - - - -
Acquisition - - - -
Production (8.2) (8.2) (84.3) (84.3)
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Closing Balance
December 31, 2008 20.2 28.1 629.9 865.3
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Note: May not add due to rounding

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Natural Gas Equivalent
(mmcf) (mboe)
--------------------------------------
Total Total
Proved Proved
Plus Plus
Proved Probable Proved Probable
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Opening Balance
December 31, 2007 22,636.5 32,457.1 4,385.8 6,269.5
Technical 716 (80.4) 170.7 34
Exploration Discoveries - - - -
Drilling Extensions 7,274 8,946.3 1,263.3 1,536.8
Infill Drilling 932.8 1,119.3 182.8 219.4
Improved Recovery - - - -
Acquisition - - - -
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Production (3905.3) (3905.3) (743.4) (743.4)
Closing Balance
December 31, 2008 27,654.4 38,537.0 5,259.2 7,316.2
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Note: May not add due to rounding


Additional reserve disclosure tables, as required under NI 51-101, including Gross and Net reserves as defined 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)

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



----------------------------------------------------------------------------
2008 2007 3 year average
----------------------------------------------------------------------------
Proven Proven + Proven Proven + Proven Proven +
Probable Probable Probable
----------------------------------------------------------------------------
Capital ($'000s)
Exploration and
development (1) 32,014 32,014 18,799 18,799 26,624 26,624
Acquisition capital - - 2,127 2,127 3,302 3,302
Change in future
capital 2,349 2,200 (38) (2,481) 778 198
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Total capital
including change
in future capital 34,363 34,214 20,888 18,445 30,704 30,123
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Reserve additions
(mboe) (2)
Exploration and
development 1,617 1,790 1045 1058 1,136 1,270
Acquisition - - (88) (129) 75 129
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Total reserve
additions (mboe) 1,617 1,790 957 929 1,210 1,399
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Costs ($/boe)
F&D 21.25 19.11 17.96 15.42 24.13 21.11
FD&A 21.25 19.11 21.84 19.86 25.37 21.53
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Note: May not add due to rounding

(1) The aggregate of the exploration and development costs incurred in the
most recent financial year and the change during that year in estimated
future development costs generally will not reflect total finding and
development costs related to reserves additions for that year.

(2) Reserve additions 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.


NET ASSET VALUE
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Forecasted Prices
($ million, except per share) 8% B.T.
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Reserves, proved and probable (1) 130.3
Seismic data 6.5
Undeveloped land(2) 12.9
Working capital (35.3)
Common shares outstanding, basic (3) 55.6
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Net asset value ($/share) 2.06
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(1) Net present value of future net revenues before income taxes discounted
at 8%.

(2) In our calculation, we have used approximately $362 per acre as the
average land price for our undeveloped land (35,579 net acres).

(3) Based on 55,631,798 common shares outstanding at December 31, 2008.


Production & Reserve Life Index

The Company's reserve life index using annualized fourth quarter 2008 production is 5.7 years for proven BOE reserves compared to 7.8 years in 2007 and 8.0 years for proven plus probable BOE reserves compared to 11.1 years in 2007.



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2008 2007
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Production rate is an: Annualized Q4 Average Annualized Q4 Average
----------------------------------------------------------------------------
Production (boe/d) 2,501 2,031 1,549 1,340
Proved reserves (mboe) (1) 5,259 5,259 4,386 4,386
Proved reserve life index (years) 5.7 7.1 7.8 9.0
Proved plus probable reserves
(mboe) (1) 7,316 7,316 6,270 6,270
Proved plus probable reserve
life index (years) 8.0 9.8 11.1 12.8
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(1) Values 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.


Cinch exited the year at approximately 2,500 BOED.

Reserve Replacement (1)

The Company's 2008 capital investment program replaced 2008 average production by a factor of 2.2 times on a proved basis and 2.4 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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2008 2008 2007 2007
Production total is an: Annualized Q4 Average Annualized Q4 Average
----------------------------------------------------------------------------
Production (mboe) 915.4 743.4 565.4 489.1
Proved reserve additions
after revisions of prior
periods (mboe) 1,617 1,617 956.5 956.5
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Proved replacement ratio 1.8 2.2 1.7 2.0
Proved plus probable reserve
additions after revision
of prior periods (mboe) 1,790 1,790 928.8 928.8
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Proved plus probable replacement
ratio 2.0 2.4 1.6 1.9
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(1) Reserve replacement is based on "Company interest" reserves defined by
the total working interest (operating and non-operating) share before
deduction of royalties payable to others and including royalty
interests of Cinch.


Recycle Ratio (1)

The recycle ratio is a measure for evaluating the effectiveness of a company's re-investment program. The ratio measures the efficiency of capital investment. It accomplishes this by comparing the operating netback per barrel of oil equivalent to that year's reserve finding and development costs. Cinch Energy presents the recycle ratio on both an FD&A basis (based on 2008 actual FD&A) and an F&D basis.



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2008 2008 2007 2007
(FD&A) (F&D) (FD&A) (F&D)
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Operating netbacks ($/BOE) 35.10 35.10 30.13 30.13
Proved finding, development and net
acquisition costs after revision of
prior periods and including the change in
future development capital ($/BOE) 21.25 21.25 21.84 17.96
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Proved recycle ratios 1.7 1.7 1.4 1.7
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Proved plus probable finding, development
and acquisition costs after revisions of
prior periods and including the change in
future development capital ($/BOE) 19.11 19.11 19.86 15.42
----------------------------------------------------------------------------
Proved plus probable recycle ratios 1.8 1.8 1.5 2.0
----------------------------------------------------------------------------
Note: May not add due to rounding

(1) Recycle ratio is based on "Company interest" reserves defined by the
total working interest (operating and non-operating) share before
deduction of royalties payable to others and including royalty
interests of Cinch.


Other Information

Common shares of Cinch trade on the Toronto Stock Exchange under the symbol of "CNH". Additional information relating to the Company is available on SEDAR at www.sedar.com. The Annual and Special Meeting will be held on the 13th day of May, 2009 at 2:30 p.m. (Calgary time) in Great Room 3 at the Sandman Hotel Calgary, 888- 7th Avenue S.W., Calgary, Alberta.

Forward Looking Statements

Statements throughout this release that are not historical facts may be considered to be "forward looking statements." These forward-looking statements sometimes include words to the effect that management believes or expects a stated condition or result. All estimates and statements that describe the Company's objectives, goals, or future plans, including management's assessment of future plans and operations, anticipated commodity prices and their impact, timing of expenditures, budgeted capital expenditures and the method of funding thereof and the nature of the expenditures, expected production increases and the timing thereof, expected decline rates of new wells, expected decrease in cash flows for 2009, timing of phases of IFRS conversion project, timing of drilling, completion and tie-in of wells, expected royalty rates and changes to the Alberta royalty regime and the possible effect thereof on the Company and its allocation of capital, expected royalty rates, operating costs and general and administrative expenses and the expected levels of activities may constitute forward-looking statements under applicable securities laws and necessarily involve risks including, without limitation, risks associated with oil and gas exploration, development, exploitation, production, marketing and transportation, volatility of commodity prices, imprecision of reserve estimates, environmental risks, competition from other producers, incorrect assessment of the value of acquisitions, failure to complete and/or realize the anticipated benefits of acquisitions, delays resulting from or inability to obtain required regulatory approvals and ability to access sufficient capital from internal and external sources and changes in the regulatory and taxation environment. Consequently, the Company's actual results may differ materially from those expressed in, or implied by, the forward-looking statements. Forward-looking statements or information is based on a number of factors and assumptions which have been used to develop such statements and information but which may prove to be incorrect.

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 manor; field production rates and decline rates; the ability to replace and expand oil and natural gas reserves through development of exploration; future oil and natural gas prices; interest rates; the regulatory framework regarding royalties; and the ability of the Company to successfully market its oil and natural gas products. Readers are cautioned that the foregoing list of factors is not exhaustive. Additional information on these and other factors that could affect the Company's operations and financial results are included elsewhere herein and in reports on file with Canadian securities regulatory authorities and may be accessed through the SEDAR website (www.sedar.com), or at the Company's website (www.cinchenergy.com). Furthermore, the forward-looking statements contained in this release are made as at the date of this release and the Company does not undertake any obligation to update publicly or to revise any of the included forward-looking statements, whether as a result of new information, future events or otherwise, except as may be required by applicable securities laws.

Barrel of Oil Equivalency

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

MANAGEMENT'S DISCUSSION AND ANALYSIS

March 4, 2009

The following management's discussion and analysis ("MD&A") should be read in conjunction with Cinch Energy Corp.'s ("Cinch" or the "Company") audited financial statements for the years ended December 31, 2008 and 2007. This commentary is based on the information available as at, and is dated, March 4, 2009. Additional information relating to Cinch, including the Company's Annual Information Form when filed, is on SEDAR at www.sedar.com.

Non-GAAP Measures

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

The MD&A contains the term "net debt" which is the sum of the working capital (deficiency) and the outstanding credit facility balance. This number may not be comparable to that reported by other companies.

OPERATIONAL UPDATE

Production for 2008 averaged 2,031 BOE/d, a 52% increase over the 2007 average production of 1,340 BOE/d. This is the fifth consecutive quarter of increased production for the Company. Cinch further anticipates increasing production during the first quarter of 2009 when the Dawson 6-6 (85% working interest) Wabamun well commences production at an estimated rate of 5 mmcf/d (gross). This well is expected to come on stream in early March 2009.

The Company's average production for the fourth quarter of 2008 was 2,501 BOE/d, an increase of 22% over the third quarter average production of 2,049 BOE/d and a 61% increase over the average production for fourth quarter of 2007 of 1,549 BOE/d. The fourth quarter of 2008 production reflects two new wells in Dawson, British Columbia, which came on production in October 2008 at combined initial production rates of approximately 550 BOE/d (net). It is anticipated that these new wells will experience typical Deep Basin decline rates during the first year of production, stabilizing thereafter.

During the fourth quarter of 2008, the Company drilled, completed, and tied-in locations primarily in the Dawson area. At Dawson, the Company completed the Dawson 6-1 vertical well (40% working interest) in the Montney zone. The Montney was fraced and flow tested over a 4-day period with gas rates stable at 2.6 mmcf/d (gross). The Company is encouraged by this production test and is projecting a horizontal well to be drilled near the Dawson 6-1 well during the summer of 2009. The Dawson 10-15 well (40% working interest) has been cased to the Kiskatinaw zone and the Company anticipates completing the Kiskatinaw and Montney zones during the first quarter of 2009.

The Company incurred $6.7 million of capital expenditures in the three months ended December 31, 2008 and exited the quarter with net debt of $35.3 million, of which $28.4 million was drawn on its $40 million demand bank credit facility.



PRODUCTION

----------------------------------------------------------------------------
Three Months Ended December 31, Year Ended December 31,
2008 2007 Change 2008 2007 Change
----------------------------------------------------------------------------
Sales volumes % %
Natural gas (Mcf/d) 13,634 7,749 76 10,670 6,687 60
Liquids (Bbl/d) 229 258 (11) 253 226 12
Equivalence (BOE/d) 2,501 1,549 61 2,031 1,340 52

Sales prices $ $ % $ $ %
Natural gas ($/Mcf) 6.91 6.61 5 8.41 6.99 20
Liquids($/Bbl) 48.35 79.29 (39) 84.34 68.48 23
Equivalence ($/BOE) 42.06 46.22 (9) 54.64 46.38 18
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----------------------------------------------------------------------------


Sales volumes for the three months and year ended December 31, 2008 increased 76% and 60%, respectively, compared to the same periods of 2007 due to eight additional wells that came on production since December 2007. It is anticipated that the new wells will experience typical Deep Basin decline rates in their first year of production. The Company's production is primarily from deep, tight gas, which normally experiences high decline rates in the first year, with decline rates typically reducing and stabilizing thereafter and providing a strong production base. As the Company builds a larger production base, declines on new production should have a less significant impact.

Natural gas prices were 5% higher in the fourth quarter of 2008 compared to the same quarter of 2007 and 20% higher year over year. The Company's natural gas production continues to be unhedged and is marketed in the Alberta spot market.

Natural gas liquids pricing was 39% lower in the fourth quarter of 2008 compared to the same quarter of 2007 and 23% higher year over year. Natural gas liquids revenues represent approximately 19% of the oil and gas revenues for 2008. 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,
2008 2007 Change 2008 2007 Change
----------------------------------------------------------------------------
$ $ % $ $ %

Petroleum and natural
gas sales, net of
transportation 9,679 6,588 47 40,624 22,691 79
Per BOE 42.06 46.22 (9) 54.64 46.38 18
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Revenues for the three months and year ended December 31, 2008 were 47% and 79% higher, respectively, than the same periods of 2007 primarily due to higher natural gas production, as well as significantly higher commodity prices. Although fourth quarter production was 452 BOE/d greater than that of the third quarter production, the Company generated lower revenues due to significantly lower realized commodity prices in the fourth quarter.

Transportation expenses decreased by approximately $0.16 per BOE for the year ended December 31, 2008 compared to 2007 primarily due to lower transportation fees in British Columbia, which did not have any producing wells in 2007.



ROYALTIES

Dollars in thousands, except per unit amounts
----------------------------------------------------------------------------
Three Months Ended December 31, Year Ended December 31,
2008 2007 Change 2008 2007 Change
----------------------------------------------------------------------------
$ $ % $ $ %
Royalties 2,542 1,258 102 10,324 4,765 117
Per BOE 11.05 8.82 25 13.89 9.74 43
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----------------------------------------------------------------------------


Royalty expense increased in the three months and year ended December 31, 2008 compared to the same periods of 2007 due to higher revenues, as well as the expiration of royalty holidays on higher producing wells. The royalty rate (royalties as a percentage of oil and gas sales) for the year ended 2008 was approximately 25% which is 4% higher than the 2007 rate of 21%. This rate is comprised of both crown royalties and gross overriding royalties. The increased royalty rate in 2008 reflects the expiration of royalty holidays on higher producing wells, as well as a higher crown royalty rate paid in British Columbia compared to Alberta in 2008. The maximum crown royalty rate, however, in British Columbia is lower compared to the maximum crown royalty rate in Alberta under the new Alberta royalty framework effective January 1, 2009.

The Company anticipates a potential increase in the royalty rate effective January 1, 2009 due to the implementation of the Alberta royalty framework. The royalty rate is dependent on many factors including commodity prices, well production, as well as total depths of the producing wells. The royalty rate can change significantly depending on these factors and as such can be difficult to predict. At a natural gas price of $5/mcf, which is the price used for the Company's 2009 budget, the royalty rate for 2009 will not vary significantly from the 2008 rate. As commodity prices increase, the Corporate royalty rate will also increase with a maximum royalty rate of 50% on high producing wells in Alberta, whereas the maximum royalty rate on high producing wells in British Columbia is 27%.

On March 3, 2009, the Government of Alberta announced a three-point incentive program to stimulate new and continued economic activity in Alberta, which is further discussed in the Global Financial Crisis section. At this time, the impact of these changes to Cinch's financial position cannot be reasonably determined or estimated. The Company will review the proposed changes and continue to monitor any further amendments and will update its plans as required.



OPERATING EXPENSES

Dollars in thousands, except per unit amounts
----------------------------------------------------------------------------
Three Months Ended December 31, Year Ended December 31,
2008 2007 Change 2008 2007 Change
----------------------------------------------------------------------------
$ $ % $ $ %
Operating 1,225 837 46 4,336 3,183 36
Per BOE 5.32 5.87 (9) 5.83 6.51 (10)
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----------------------------------------------------------------------------


Total operating expenses increased in the three months and year ended December 31, 2008 compared to the same periods of 2007 mostly due to higher gas gathering and processing fees attributable to higher production volumes. There were also increases in compressor and equipment maintenance, methanol and chemical treating, operators overhead, as well as increased insurance costs. Operating expenses per BOE were $0.68/BOE or 10% lower in 2008 compared to 2007 mostly attributable to increased production, as well as increased operational efficiencies.

Total operating expenses for the fourth quarter of 2008 were higher compared to the third quarter due to higher gas gathering and processing fees attributable to higher production volumes. Operating expense per BOE decreased due to increased production in the fourth quarter of 2008.

In the third quarter of 2008, the Company forecasted operating expenses per BOE to further decrease in the fourth quarter of 2008 with average operating expenses per BOE for the year forecasted at $5.75 per BOE. The operating costs per BOE for 2008 were only slightly higher than projected at $5.83 per BOE for the year.

Operating expenses are not expected to exceed $5.50 per BOE in 2009 with the increased forecasted volumes. 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,
2008 2007 Change 2008 2007 Change
----------------------------------------------------------------------------
$ $ % $ $ %
General and
administrative 1,330 1,114 19 4,013 3,985 1
Per BOE 5.78 7.81 (26) 5.40 8.15 (34)
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----------------------------------------------------------------------------


Total general and administrative expenses increased for the three months ended December 31, 2008, compared to the same period of 2007 due to higher salaries and wages, public company related expenses, and contractor costs partially offset by higher overhead recoveries. The increased salaries in the fourth quarter reflect a bonus paid out to the employees due to the Company growth achieved during the year. The increased contractor costs and public company related expenses in the fourth quarter were a direct result of the initial work performed on the implementation of international financial reporting standards ("IFRS"), as discussed in the recent accounting pronouncements section below.

Total general and administrative expenses for the year ended December 31, 2008 were consistent with the same period of 2007. Higher public company related expenses, and computer software costs, were offset by higher overhead recoveries. As at March 4, 2009, the Company has 5,366,500 options outstanding, amounting to approximately 9.6% of the 55,631,798 outstanding common shares. The Company does not capitalize any indirect general and administrative expenses.

General and administrative expenses per BOE were $2.75/BOE lower in 2008, a 34% decrease compared to 2007. The decrease in general and administrative expenses per BOE for the three months and year ended December 31, 2008 compared to the same periods of 2007 can be attributed to higher production in 2008.

General and administrative expenses for 2009 are not expected to exceed $4.75 per BOE due to higher budgeted production volumes for the year.



INTEREST EXPENSE

Dollars in thousands, except per unit amounts
----------------------------------------------------------------------------
Three Months Ended December 31, Year Ended December 31,
2008 2007 Change 2008 2007 Change
----------------------------------------------------------------------------
$ $ % $ $ %
Interest expense 327 302 8 1,160 962 21
Per BOE 1.42 2.12 (33) 1.56 1.97 (21)
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----------------------------------------------------------------------------


Interest expense increased in the three months and year ended December 31, 2008 compared to the same periods of 2007 due to higher draws on the Company's bank credit facility in 2008, exiting the year with an outstanding credit facility balance of $28.4 million on its 40.0 million credit facility. In 2007, the Company exited the year with an amount outstanding under its credit facility of $20.6 million. In November 2008, the Company increased its revolving demand bank credit facility from $34 million to $40 million. The facility bears interest at the lender's prime rate plus one quarter to one-half basis points depending on the Company's net debt to funds from operations ratio. The increase in the credit facility provides increased flexibility for the Company. The available amount under the credit facility is subject to review in April 2009.



ACCRETION OF ASSET RETIREMENT OBLIGATIONS EXPENSE

Dollars in thousands, except per unit amounts
----------------------------------------------------------------------------
Three Months Ended December 31, Year Ended December 31,
2008 2007 Change 2008 2007 Change
----------------------------------------------------------------------------
$ $ % $ $ %
Accretion expense 52 47 11 193 179 8
Per BOE 0.22 0.33 (33) 0.26 0.36 (28)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Accretion expense increased in the three months and year ended December 31, 2008 compared to the same periods of 2007 due to an increase in the number of wells, as well as an increase in the Company's estimate of the credit adjusted risk-free interest rate on which the liability is accreted. In December 2008, as a result of the current economic environment, and to better reflect increased borrowing costs, the Company increased its credit adjusted risk-free rate from 7.5% to 10.0% to calculate its asset retirement obligations.



DEPLETION AND DEPRECIATION EXPENSE

Dollars in thousands, except per unit amounts
----------------------------------------------------------------------------
Three Months Ended December 31, Year Ended December 31,
2008 2007 Change 2008 2007 Change
----------------------------------------------------------------------------
$ $ % $ $ %
Depletion and
depreciation 5,667 3,767 50 18,544 12,890 44
Per BOE 24.63 26.43 (7) 24.94 26.35 (5)
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----------------------------------------------------------------------------


Total depletion and depreciation expense for the three months and year ended December 31, 2008 increased compared to the same periods in 2007 due to higher production volumes, as well as a larger capital asset balance being depleted, partially offset by reserve additions for 2008. Depletion and depreciation expense per BOE for the three months and year ended December 31, 2008 decreased compared to the same period of 2007 due to positive drilling results resulting in reserve additions.



TAXES

Dollars in thousands, except per unit amounts
----------------------------------------------------------------------------
Three Months Ended December 31, Year Ended December 31,
2008 2007 Change 2008 2007 Change
----------------------------------------------------------------------------
$ $ % $ $ %
Current 4 - 100 4 - 100
Future income taxes
expense (recovery) (10) (1,177) (99) 1,022 (2,111) 148
Per BOE (0.03) (8.26) (100) 1.38 (4.32) 132
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----------------------------------------------------------------------------


A future income tax recovery was recorded in the three months ended December 31, 2008 consistent with the net loss experienced during the quarter. A majority of this future income tax recovery was offset by an increase in the future income tax rate. The increase in the rate was a result of changes in the timing of the reversals of temporary differences.

The future income tax recovery recorded in the fourth quarter of 2007 reflects the reduction in future tax rates as legislated by the Federal Government in December 2007, when the Federal Government announced reduced corporate tax rates for 2008 through to 2012.

The future income tax expense recorded for the year ended December 31, 2008 is consistent with the net income earned during the period.



Tax pools at December 31, 2008:

Dollars in thousands
----------------------------------------------------------------------------
2008 2007
$ $
----------------------------------------------------------------------------
COGPE 15,687 13,559
CDE 25,216 25,935
CEE 29,256 29,007
UCC 18,053 18,332
----------------------------------------------------------------------------
88,212 86,833
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The Company's tax pools increased in 2008 as a result of capital expenditures that were higher than the tax deductions needed to eliminate taxable income. On February 21, 2007, the Company completed an equity financing for flow-through shares of $10 million. This amount has been deducted from the tax pools in 2008 as the flow-through expenditures were renounced in January 2008, effective December 31, 2007. As at December 31, 2008, all the required expenditures have been incurred.



NET INCOME (LOSS) AND FUNDS FROM OPERATIONS

In thousands, except per share figures
----------------------------------------------------------------------------
Three Months Ended December 31, Year Ended December 31,
2008 2007 Change 2008 2007 Change
----------------------------------------------------------------------------
$ $ % $ $ %
Net Income (Loss) (1,435) 466 (408) 1,167 (15,695) 107
per basic share (0.03) 0.01 (400) 0.02 (0.29) 107
per diluted share (0.03) 0.01 (405) 0.02 (0.29) 107
Funds from operations 4,371 3,217 36 21,456 10,782 99
per basic share 0.08 0.06 33 0.39 0.20 97
per diluted share 0.08 0.06 33 0.38 0.20 92
Weighted average share
outstanding 55,632 55,625 - 55,627 54,485 2
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----------------------------------------------------------------------------


For the year ended December 31, 2008, the Company generated net income of $1.17 million, attributable to increased production and higher commodity prices realized compared to the same period of 2007. During the third quarter of 2007, the Company wrote down goodwill of $14.6 million, which generated a larger loss for 2007. The goodwill write-down did not have an impact on the value of the Company's oil and gas properties.

For the three months ended December 31, 2008, the Company incurred a net loss of $1.43 million, due to higher royalties, higher depletion and depreciation, as well as higher operating expenses compared to the same period of 2007. The net income generated in the fourth quarter of 2007 relates to a future tax recovery reflecting the reduction in future tax rates, as previously discussed. The fourth quarter of 2008 was significantly affected by the decline in commodity prices, and although the Company increased its production by 22%, the revenues earned were lower in the fourth quarter compared to the third quarter of 2008.

The Company's funds from operations for the three months and year ended December 31, 2008, increased by 36% and 99%, respectively, over the same periods of 2007. Funds from operations in 2008 are higher due to increased revenues attributable to higher production, higher commodity prices, as well as increased operational efficiencies. As discussed above, the substantial decline in commodity prices during the fourth quarter of 2008 largely impacted the Company's cash flows.



LIQUIDITY AND CAPITAL RESOURCES

Dollars in thousands
----------------------------------------------------------------------------
As at December 31,
2008 2007 Change
----------------------------------------------------------------------------
$ $ %
Working capital deficiency, excluding credit
facility (6,950) (4,168) 67
Credit facility (28,358) (20,589) 38
----------------------------------------------------------------------------
Net debt (35,308) (24,758) 43
Shareholders' equity (84,394) (85,315) (1)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


At December 31, 2008, the Company had net debt of $35.3 million, comprised of a working capital deficiency of $6.9 million and an amount outstanding on its credit facility of $28.4 million. The $10.5 million increase in net debt from December 31, 2007 can be attributed to capital expenditures of $32.0 million partially offset by funds from operations for the year ended December 31, 2008 of $21.5 million.

The fourth quarter funds from operations were $4.4 million, which is a $1.2 million decrease from the third quarter funds from operations of $5.6 million. The decrease in funds from operations combined with capital expenditures of $6.7 million in the fourth quarter resulted in the Company exiting 2008 with net debt of $35.3 million, a $2.3 million increase from the third quarter net debt of $33.0 million.

In 2009, the Company is planning to drill, complete and tie-in locations primarily in the Dawson area with a capital budget of approximately $15 million based on estimated average commodity prices of $5/mcf for natural gas and $50 per barrel for natural gas liquids. The Company plans to fund its 2009 capital program from cash flows and plans to adjust the program accordingly depending on cash flows generated. In response to the deteriorating economic environment, along with unstable commodity prices, the Company feels it is prudent to project a conservative capital program and continue to monitor the balance sheet until the economic climate shows signs of improvement.

In April 2009, the revolving demand bank credit facility of $40 million is scheduled for review. The new borrowing base will be dependent on Company reserves and the price deck used along with other assumptions utilized by the bank in the course of their review. If the review results in a reduction in the demand bank credit facility, this will reduce financial flexibility for the Company. The Company will then re-evaluate the planned capital budget for 2009 and adjust the budget accordingly.

The decrease in shareholder's equity at December 31, 2008 from December 31, 2007 can mostly be attributed to the tax effect of $10 million in flow-through share expenditures renounced in January 2008 on flow-through shares issued in February 2007, partially offset by the net income realized in 2008.



CAPITAL EXPENDITURES

Additions to property, plant and equipment

Dollars in thousands
----------------------------------------------------------------------------
Year Ended December 31,
2008 2007
----------------------------------------------------------------------------
$ $
Land and rentals 3,872 2,581
Seismic 1,736 281
Drilling, completing and equipping 21,964 15,852
Pipelines and facilities 4,285 2,289
Other assets 157 (77)
----------------------------------------------------------------------------
Total 32,014 20,926
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Capital expenditures for the year ended December 31, 2008 include approximately $3.6 million relating to land acquisitions in the Dawson and Kakwa areas. The balance of the capital expenditures was incurred on drilling, completion, and tie-in operations primarily in the Dawson, Kakwa, and Chime areas. At December 31, 2008, based on an external third party reserve assessment, additional reserves were added through drilling and completion operations in the Dawson area.

Management's primary strategy is to expend capital on exploration and development drilling and earn land by drilling. The Company may, however, also purchase land or complete acquisitions where considered strategic.

The Company's 2009 capital program is budgeted at approximately $15 million (subject to adjustment based on cash flows generated) with the majority of the capital expenditures projected for the Dawson area located in British Columbia.

BUSINESS RISKS AND RISK MANAGEMENT

General

The long-term commercial success of the Company depends on its ability to find, acquire, develop and commercially produce oil and natural gas reserves. Cinch attempts to reduce risk in accomplishing these goals through the combination of hiring experienced and knowledgeable personnel and careful evaluation.

The Company's program is exploratory in nature and in areas with deep, tight gas. The wells the Company drills therefore tend to be deep (a substantial portion are deeper than 2,500 meters), and are subject to higher drilling costs than those in more shallow areas. In addition, most wells require fracture treatment before they are capable of production, also increasing costs. The Company mitigates the additional economic pressure that this creates by carefully evaluating risk/reward scenarios for each location, by taking what management considers to be appropriate working interests after considering project risk, by practicing prudent operations so that drilling risk is decreased, by ranking and limiting the zones that the Company is willing to complete, and also by drilling deep so that the multi-zone potential of the area can be accessed and potentially developed. The Company operates the majority of its lands, which provides a measure of control over the timing and location of capital expenditures. In addition, the Company monitors capital spending on an ongoing and regular basis in order to maintain liquidity.

Commodity price fluctuations pose a risk to the Company, and management monitors these on an ongoing basis. External factors beyond the Company's control may affect the marketability of the natural gas and natural gas liquids produced. To date, the Company has not implemented any hedging instruments.

The Company has selected the appropriate personnel to monitor operations and has automated field information where possible, so that operational issues can be assessed and dealt with on a timely basis. The Company, however, is not the operator in all cases and therefore not all operational issues are within its control. Management will address them nonetheless, and attempt to implement solutions, which may be by their nature longer term.

Oil and natural gas exploration, development and production operations are subject to all the risks and hazards typically associated with such operations, including hazards such as fire, explosion, blowouts, and spills, each of which could result in damage to wells, production facilities, other property and the environment or in personal injury. In accordance with industry practice, the Company insures against most of these risks (although not all such risks are insurable). The Company maintains liability insurance in an amount that it considers consistent with industry practice although the nature of these risks is such that liabilities could potentially exceed policy limits. The Company also reduces risk by operating a large percentage of its operations. As such, the Company has control over the quality of work performed and the personnel involved.

Attracting and retaining qualified individuals is crucial to the Company's success. The Company understands the importance of maintaining competitive compensation levels given the competitive environment in which the Company operates. The inability to attract and retain key employees could have a material adverse effect on the Company.

The Company's ability to move heavy equipment in the field is dependent on weather conditions. Rain and snow can affect conditions, and many secondary roads and future oil and gas production sites are incapable of supporting the weight of heavy equipment until the roads are thoroughly dry. The duration of difficult conditions can have an impact on the Company's activity levels and potentially delay operations.

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

All phases of the oil and natural gas business present environmental risks and hazards and are subject to environmental regulation pursuant to a variety of federal, provincial and local laws and regulations. Compliance with such legislation can require significant expenditures and a breach may result in the imposition of fines and penalties, some of which may be material. Environmental legislation is evolving in a manner expected to result in stricter standards and enforcement, larger fines and liability and potentially increased capital expenditures and operating costs.

Given the evolving nature of the debate related to climate change and the control of greenhouse gases and resulting requirements, it is not currently possible to predict either the nature of those requirements or the impact on the Company and its operations and financial condition. The Company optimizes its operations with respect to compressor fuel usage and natural gas flaring so that a reduction in emissions is realized.

Global financial crisis

Recent market events and conditions, including disruptions in the international credit markets and other financial systems and the deterioration of global economic conditions, have caused significant volatility to commodity prices. These conditions became evident in the latter part of 2008 and are continuing in 2009, causing a loss of confidence in the broader U.S. and global credit and financial markets. This resulted in the collapse of and government intervention in, major banks, financial institutions and insurers and creating a climate of greater volatility, less liquidity, widening of credit spreads, a lack of price transparency, increased credit losses and tighter credit conditions. Notwithstanding various actions by governments, concerns about the general condition of the capital markets, financial instruments, banks, investment banks, insurers and other financial institutions caused the broader credit markets to further deteriorate and stock markets to decline substantially. These factors have negatively impacted company valuations and will impact the performance of the global economy going forward.

Petroleum prices are expected to remain volatile for the near future as a result of market uncertainties over the supply and demand of these commodities due to the current state of the world economies.

However, in 2008 Cinch significantly increased cash flows from operations over the prior years but forecasts a decrease in cash flows for 2009 assuming that average commodity prices in 2009 will remain low. Cinch has secured an increased revolving demand bank credit facility of $40 million (previously $34 million) that will enhance the Company's ability to manage through these uncertain times, although availability of the amount is subject to a review in April 2009. If the review results in a decrease in the demand bank credit facility, it will reduce the Company's financial flexibility.

On March 3, 2009, the Government of Alberta announced a three-point incentive program to stimulate new and continued economic activity in Alberta which included a drilling royalty credit for new conventional oil and natural gas wells and a new well royalty incentive program. Under the drilling royalty credit program a $200 per meter royalty credit will be available on new conventional oil and natural gas wells drilled between April 1, 2009 and March 31, 2010, subject to certain maximum amounts. The maximum credits available will be determined by the Company's production level in 2008 and its drilling activity between April 1, 2009 and March 31, 2010. Based on Cinch's 2008 production it will be entitled to a maximum credit of 50% of royalties payable in the period April 1, 2009 and March 31, 2010. The new well incentive program will apply to wells beginning production of conventional oil and natural gas between April 1, 2009 and March 31, 2010 and provides for a maximum 5% royalty rate for the first 12 months of production, up to a maximum of 50,000 barrels of oil or 500 Mmcf of natural gas. At this time, the impact of these changes to Cinch's financial position and results of operation cannot be reasonably determined or estimated. The Company will continue to monitor any changes and will update its plans as required.

Substantial Capital Requirements

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

In view of the current economic environment, the Company has prudently projected a conservative capital program and thereby, has reduced capital spending in 2009. The Company plans to fund its 2009 capital program from cash flows and adjust the program accordingly depending on cash flows generated. The Company will continue to closely monitor its balance sheet, manage the credit facility and access to credit markets in the coming year.

Third Party Credit Risk

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

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

DISCLOSURE CONTROLS AND PROCEDURES

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

INTERNAL CONTROLS OVER FINANCIAL REPORTING

The Company's Chief Executive Officer and Chief Financial Officer have designed, or caused to be designed under their supervision, internal control over financial reporting. Such officers have evaluated, or caused to be evaluated under their supervision, the effectiveness of the Company's internal control over financial reporting at the financial year end of the Company and have concluded that such internal control over financial reporting is effective, at the financial year end of the Company, to provide reasonable assurance regarding the reliability of the Company's financial reporting and preparation of financial statements for external purposes in accordance with Canadian GAAP.

The Company is required to disclose herein any change in the Company's internal control over financial reporting that occurred during the period beginning on October 1, 2008 and ended on December 31, 2008 that has materially affected, or is reasonably likely to materially affect, the Company's internal control over financial reporting. No material changes in the Company's internal control over financial reporting were identified during such period that have materially affected, or are reasonably likely to materially affect, the Company's internal control over financial reporting.

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

CONTRACTUAL OBLIGATIONS, COMMITMENTS, AND GUARANTEES

The Company has contractual obligations and commitments in the normal course of its operating and financing activities. These obligations and commitments have been considered when assessing the Company's cash requirements in its analysis of future liquidity.



Dollars in thousands
----------------------------------------------------------------------------
Payments
Total less than 1-3 4-5 greater
1 year years years than 5
$ $ $ years
$ $
----------------------------------------------------------------------------
Operating lease 190 190 - - -
----------------------------------------------------------------------------
190 190 - - -
----------------------------------------------------------------------------
----------------------------------------------------------------------------


On February 21, 2007, the Company issued 7,812,500 flow-through common shares for gross proceeds of $10 million. In January 2008, the Company renounced $10 million of Canadian exploration expenditures to the flow-through investors effective December 31, 2007 and is required to incur such expenditures on or before December 31, 2008. As at December 31, 2008, the Company has incurred all required expenditures.

CHANGES IN ACCOUNTING POLICIES

Effective January 1, 2008 the Company adopted the CICA Handbook Section 1535, Capital Disclosures, Handbook Section 3862, Financial Instruments - Disclosures, Handbook Section 3863, Financial Instruments - Presentation and Handbook Section 1400, General Standards of Financial Statement Presentation. The adoption of Section 1535 resulted in additional disclosure with regard to the Company's objectives, policies, and processes for managing capital. The adoption of Sections 3862 and 3863 did not impact the classification and valuation of the Company's financial instruments due to the nature of the financial instruments recorded on the balance sheet and the contracts to which the Company is a party to. The adoption of Section 1400 did not have an impact on the Company due to the fact management has always assessed the Company's ability to continue as a going concern.

Effective October 1, 2008 the Company adopted the CICA Handbook Section 3064, Goodwill and Intangible Assets. The adoption of Section 3064 resulted in recognizing all goodwill and intangible assets in accordance with CICA Handbook Section 1000, "Financial Statement Concepts." This standard has no impact on the Company's financial statements.

For more information on these policies, see note 3 of the Company's financial statements for the year ended December 31, 2008.

RECENT ACCOUNTING PRONOUNCEMENTS

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

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

The Company commenced its IFRS conversion project this year. The 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 Canadian GAAP and IFRS. The Company has determined that the areas of accounting differences with the highest potential to impact 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.

The Company is currently engaged in the design and planning phase of the project, which involves documenting the high impact areas identified and evaluating the different accounting policy options available under IFRS. During this phase, the Company will also assess the impact that a conversion to IFRS will have on its policies and procedures, information technology and accounting systems, as well as internal controls. The Company anticipates completing this phase and moving to the solution development phase later in 2009.

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

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

On January 20, 2009, the Emerging Issues Committee of CICA issued new Abstract #173, "Credit Risk and the Fair Value of Financial Assets and Financial Liabilities," concerning the measurement of financial assets and financial liabilities. There has been diversity in practice as to whether an entity's own credit risk and the credit risk of the counterparty are taken into account in determining the fair value of financial instruments. The Committee reached a consensus that these risks should be taken into account in the measurement of financial assets and financial liabilities. The Abstract is effective for all financial assets and financial liabilities measured at fair value for the interim and annual financial statements issued for periods ending on or after the date of issuance of the Abstract with retrospective application without restatement of prior periods. The Company will be applying the new Abstract at the beginning of its 2009 fiscal year. The Company is currently assessing the impact of the Abstract on the measurement of its financial assets and financial liabilities. The Company does not expect the implementation to have a significant impact on the Company's operations, financial position, or disclosures.

CRITICAL ACCOUNTING ESTIMATES

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

Reserves

The estimate of reserves is used in forecasting what will ultimately be recoverable from the properties and their economic viability and in calculating the Company's depletion and potential impairment of asset carrying costs. The process of estimating reserves is complex and requires significant interpretation and judgment. It is affected by economic conditions, production, operating and development activities, and is performed using available geological, geophysical, engineering, and economic data. Reserves at year-end are evaluated by an independent engineering firm and quarterly updates to those reserves are estimated by the Company.

Revenue Estimates

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

Cost Estimates

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

Asset Retirement Obligations

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

Income taxes

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

TREND ANALYSIS

In 2008, the Company continued to focus on drilling, completion, and tie-in operations; and anticipates drilling, re-completing and tieing-in multiple wells in 2009, notwithstanding a projected conservative capital program.

The Company has made great strides on building a stable production base, and continues to work on achieving growth. The Company achieved its 2008 production projections averaging 2,501 BOE/d during the fourth quarter of 2008, which resulted in average production of 2,031 BOE/d for the year as a result of new wells coming on production. In the fourth quarter of 2008, two new Dawson wells came on production at an initial combined rate of over 550 BOE/d (net). This is the fifth consecutive quarter of increased production for the Company. Cinch anticipates increasing its production during the first quarter of 2009 when the Dawson 6-6 (85% working interest) Wabamun well commences production at an estimated rate of 5 mmcf/d (gross).

The Company is affected by commodity price variations. The volatility in oil and gas prices that we have experienced in the past few years directly affects the revenues and cash flows generated by the Company. In late 2005, the market experienced high commodity prices resulting in increased activity and strong equity valuations. In 2006, we started seeing a softening of the natural gas market and large decreases in prices when compared to the previous year. The decrease in commodity prices impacts the Company by reducing cash flows available for exploration and challenges the economics of potential capital projects. In 2007, the natural gas market continued to soften until the fourth quarter when natural gas prices strengthened while entering the winter months. During the first half of 2008, commodity prices increased significantly, with natural gas prices at levels that had not been seen since late 2005, and natural gas liquids and oil prices reaching all time highs. In the latter half of 2008, global commodity prices declined resulting in a decrease in revenues, as well as a decrease of cash flows available to fund the Company's capital program. The softening market has also affected the Company's 2009 capital budget. The budget is planned to be funded from cash flows and adjusted accordingly depending on cash flows generated. The economy continues to show considerable weakness along with the commodity prices being very unstable. The Company feels it is prudent to closely monitor the balance sheet until the economic climate, as well as commodity prices show signs of improvements, which analysts currently do not foresee happening until late 2009 or even into 2010.



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


Q1 Q2 Q3 Q4 Annual
----------------------------------------------------------------------------
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) (1) (29,160) (26,424) (32,994) (35,308)(35,308)
----------------------------------------------------------------------------
Production (BOE/d) 1,579 1,991 2,049 2,501 2,031
----------------------------------------------------------------------------
2007 $ $ $ $ $
----------------------------------------------------------------------------
Petroleum and natural gas sales,
net of transportation and before
royalties 6,116 5,582 4,405 6,588 22,691
Funds from operations 3,371 2,589 1,605 3,217 10,782
Per share - basic 0.06 0.05 0.03 0.06 0.20
- diluted 0.06 0.05 0.03 0.06 0.20
Net income (268) (709) (15,184) 466 (15,695)
Per share - basic (0.01) (0.01) (0.27) 0.01 (0.29)
- diluted (0.01) (0.01) (0.27) 0.01 (0.29)
Capital expenditures 6,228 3,930 7,851 2,917 20,926
Total assets 136,520 134,834 125,730 125,682 125,682
Working capital (net debt)(1) (17,264) (18,673) (24,987) (24,758)(24,758)
----------------------------------------------------------------------------
Production (BOE/d) 1,354 1,249 1,208 1,549 1,340
----------------------------------------------------------------------------
2006 $ $ $ $ $
----------------------------------------------------------------------------
Petroleum and natural gas sales,
net of transportation and before
royalties 5,200 4,692 4,487 5,733 20,112
Funds from operations 2,475 2,406 2,115 2,970 9,966
Per share - basic 0.05 0.05 0.05 0.06 0.21
- diluted 0.05 0.05 0.04 0.06 0.20
Net income (loss) (131) 879 (576) (488) (317)
Per share - basic (0.00) 0.02 (0.01) (0.01) (0.01)
- diluted (0.00) 0.02 (0.01) (0.01) (0.01)
Capital expenditures 6,696 13,542 7,403 9,324 36,966
Total assets 113,356 121,861 125,894 136,983 136,983
Working capital (net debt)(1) (820) (11,942) (17,307) (23,745)(23,745)
----------------------------------------------------------------------------
Production (BOE/d) 1,130 1,141 1,135 1,320 1,182
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Note: numbers may not cross-add due to rounding
(1) Working capital (net debt) excludes the long-term financial liabilities
which consists of the long-term portion of the capital lease obligation
(December 31, 2008 - $0, December 31, 2007 -- $0, December 31, 2006 --
$276,806).

Financial Statements

Cinch Energy Corp.

December 31, 2008 and 2007

CINCH ENERGY CORP.
BALANCE SHEETS

As at December 31, 2008 2007
$ $
----------------------------------------------------------------------------

ASSETS (note 7)

Current
Accounts receivable (notes 4 and 14) 5,902,432 4,150,650
Prepaid expenses and deposits 1,088,325 859,335
----------------------------------------------------------------------------
6,990,757 5,009,985

Property, plant and equipment (note 5) 134,339,477 120,672,360
----------------------------------------------------------------------------

141,330,234 125,682,345
----------------------------------------------------------------------------
----------------------------------------------------------------------------


LIABILITIES AND SHAREHOLDERS' EQUITY

Current
Accounts payable and accrued
liabilities (note 14) 13,940,693 8,894,185
Credit facility (notes 7 and 14) 28,358,033 20,589,362
Current portion of capital lease obligation
(notes 8 and 14) - 284,112
----------------------------------------------------------------------------
42,298,726 29,767,659

Asset retirement obligations (note 9) 3,838,337 3,448,714

Future income taxes (note 10) 10,798,800 7,150,800
----------------------------------------------------------------------------
56,935,863 40,367,173
----------------------------------------------------------------------------

Commitments (notes 12 and 13)

Shareholders' equity

Share capital (note 12) 96,560,099 99,175,434
Contributed surplus (note 12) 3,574,439 3,046,632
Deficit (15,740,167) (16,906,894)
----------------------------------------------------------------------------

84,394,371 85,315,172
----------------------------------------------------------------------------

141,330,234 125,682,345
----------------------------------------------------------------------------
----------------------------------------------------------------------------


CINCH ENERGY CORP.
STATEMENTS OF OPERATIONS AND DEFICIT

For the years ended December 31, 2008 2007
$ $
----------------------------------------------------------------------------

Revenue
Oil and gas sales 42,056,496 23,711,341
Transportation (1,432,877) (1,020,548)
Royalties (10,323,932) (4,765,175)
Other income 139,423 85,178
----------------------------------------------------------------------------
30,439,110 18,010,796
----------------------------------------------------------------------------

Expenses
Operating 4,336,167 3,183,424
General and administrative (note 12) 4,013,491 3,985,397
Interest on credit facility 1,130,547 932,309
Interest on capital lease (note 8) 29,943 29,505
Accretion of asset retirement obligations (note 9) 192,794 178,504
Depletion and depreciation 18,543,520 12,890,281
Goodwill impairment (note 6) - 14,616,996
----------------------------------------------------------------------------
28,246,462 35,816,416
----------------------------------------------------------------------------

Income (loss) before income taxes 2,192,648 (17,805,620)

Taxes (note 10)
Current income tax expense 3,921 -
Future income tax expense (recovery) 1,022,000 (2,110,800)
----------------------------------------------------------------------------
1,025,921 (2,110,800)
----------------------------------------------------------------------------

Net income (loss) and comprehensive income (loss)
for the year 1,166,727 (15,694,820)

Deficit, beginning of year (16,906,894) (1,212,074)
----------------------------------------------------------------------------

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

Net income (loss) and comprehensive income (loss)
for the year per share (note 12)

Basic and diluted 0.02 (0.29)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying notes


CINCH ENERGY CORP.
STATEMENTS OF CASH FLOWS

For the years ended December 31, 2008 2007
$ $
----------------------------------------------------------------------------

Operating activities
Net income (loss) for the year 1,166,727 (15,694,820)
Add (deduct)non-cash items:
Depletion and depreciation 18,543,520 12,890,281
Accretion of asset retirement obligations 192,794 178,504
Non-cash compensation expense (note 12) 531,006 901,983
Goodwill impairment - 14,616,996
Future income tax expense (recovery) 1,022,000 (2,110,800)
----------------------------------------------------------------------------
21,456,047 10,782,144
Net change in non-cash working capital 1,040,114 430,137
----------------------------------------------------------------------------
Cash provided by operating activities 22,496,161 11,212,281
----------------------------------------------------------------------------

Investing activities
Additions to property, plant and equipment (32,013,808) (20,925,909)
Net change in non-cash working capital 2,025,622 (2,794,646)
----------------------------------------------------------------------------
Cash used in investing activities (29,988,186) (23,720,555)
----------------------------------------------------------------------------

Financing activities
Increase in credit facility 7,768,671 3,285,029
Issue of common shares, net of issue costs 7,466 9,407,888
Payments on capital lease (284,112) (268,483)
Net change in non-cash working capital - 83,840
----------------------------------------------------------------------------
Cash provided by financing activities 7,492,025 12,508,274
----------------------------------------------------------------------------

Decrease in cash - -

Cash and cash equivalents, beginning of year - -
----------------------------------------------------------------------------

Cash and cash equivalents, end of year - -
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Supplemental information:
Cash taxes paid 3,921 -
Cash interest paid 1,160,490 961,813
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying notes


CINCH ENERGY CORP.

NOTES TO FINANCIAL STATEMENTS

December 31, 2008 and 2007

1. DESCRIPTION OF BUSINESS

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

2. SIGNIFICANT ACCOUNTING POLICIES

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

Property, Plant and Equipment

Petroleum and natural gas properties

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

Ceiling test

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

Depletion

Depletion of petroleum and natural gas properties and related production equipment is provided on accumulated costs using the unit of production method based on estimated proven petroleum and natural gas reserves, before royalties, as determined by independent 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 cost of unproven properties, plus the estimated future development costs associated with proven undeveloped reserves.

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

Office furniture and equipment

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

Goodwill

Goodwill represents the excess purchase price over the fair value of identifiable assets and liabilities acquired in business combinations. Goodwill is subject to ongoing annual impairment reviews, or more frequent as economic events dictate, based on the fair value of the Company's assets. The fair value of the Company's assets is determined and compared to the book value of those assets. If the fair value of the assets is less than the book value, then a second test is performed to determine the amount of the impairment. The amount of the impairment is determined by deducting the fair value of the Company's individual assets and liabilities from the fair value of the total assets to determine the implied fair value of goodwill and comparing that amount to the book value of the Company's goodwill. Any excess of the book value over the implied value of goodwill is the impairment amount.

Leases

Leases are classified as either capital or operating in nature. Capital leases are those 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 statement of operations and deficit. The liability is periodically adjusted for revisions in either the timing or the amount of the original estimated cash flows associated with the obligation. 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 tax assets and liabilities of a change in tax rates is recognized in the statement of operations and deficit in the period in which the change is substantively enacted.

Revenue Recognition

Revenues from the sale of petroleum and natural gas and related products are recognized when title passes.

Stock Based Compensation

The Company has a stock based compensation plan, which is described in note 12. 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 is used to purchase common shares at the estimated average market price for the period.

3. CHANGES IN ACCOUNTING POLICIES

Effective January 1, 2008, the Company adopted four new accounting standards issued by the Canadian Institute of Chartered Accountants ("CICA"): Handbook Section 1535 "Capital Disclosures," Section 3862 "Financial Instruments - Disclosures," Section 3863 "Financial Instruments - Presentation," and Section 1400 "General Standards of Financial Statement Presentation."

Effective October 1, 2008 the Company adopted the CICA Handbook Section 3064, "Goodwill and Intangible Assets."

Impact upon adoption of Sections 1535, 3862, 3863, 1400 and 3064

The adoption of Section 1535 resulted in additional disclosures with regard to the Company's objectives, policies, and processes for managing capital (note 11). The adoption of Sections 3862 and 3863 did not impact the classification and valuation of the Company's financial instruments (note 14) due to the nature of the financial instruments recorded on the balance sheet and the contracts to which the Company is a party. The adoption of section 1400 had no impact on the Company due to the fact that, as part of its overall assessment, management has always evaluated the Company's ability to continue as a going concern. The adoption of Section 3064 did not impact the Company due to the fact that there was no goodwill or intangible asset balance on the Company's balance sheet upon adoption of the new Section.

Future accounting changes

On February 13, 2008, the Canadian Accounting Standards Board (AcSB) confirmed the use of International Financial Reporting Standards ("IFRS") for publicly accountable profit-oriented enterprises beginning on January 1, 2011 with appropriate comparative data from the prior year. IFRS will replace Canada's current Generally Accepted Accounting Principles ("GAAP") for those enterprises. These include listed companies and other profit-oriented enterprises that are responsible to large or diverse groups of stakeholders. Under IFRS, the primary audience is capital markets and as a result, there is significantly more disclosure required, specifically for quarterly reporting. While IFRS uses a conceptual framework similar to Canadian GAAP, there are significant differences in accounting policies that must be addressed.

The Company is assessing the effects of the adoption of IFRS by comparing differences between Canadian GAAP and IFRS. It has determined that the area 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 conversion to IFRS could also result in other impacts, some of which may be significant in nature. At this time, the impact of these changes to the Company's financial position and results of operations cannot be reasonably determined or estimated for any of the IFRS conversion impacts identified. The Company will continue to monitor any changes in the adoption of IFRS, as well as continue to assess the impact of these new standards on its financial statements.

In December 2008, the CICA issued Handbook Section 1582 "Business Combinations," which will replace CICA Handbook Section 1581 of the same name. Under this guidance, the purchase price used in a business combination is based on the fair value of shares exchanged at their market price at the date of the exchange. Currently, the purchase price used is based on the market price of the shares for a reasonable period before and after the date of the acquisition is agreed upon and announced. This new standard generally requires all acquisition costs to be expensed, which currently are capitalized as part of the purchase price. Contingent liabilities are to be recognized at fair value at the acquisition date and re-measured at fair value through 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.

On January 20, 2009, the Emerging Issues Committee of the CICA issued Abstract #173, "Credit Risk and the Fair Value of Financial Assets and Financial Liabilities," concerning the measurement of financial assets and financial liabilities. There has been diversity in practice as to whether an entity's own credit risk and the credit risk of the counterparty are taken into account in determining the fair value of financial instruments. The Committee reached a consensus that these risks should be taken into account in the measurement of financial assets and financial liabilities. The Abstract is effective for all financial assets and financial liabilities measured at fair value for the interim and annual financial statements issued for periods ending on or after the date of issuance of the Abstract with retrospective application without restatement of prior periods. The Company will be applying the new Abstract at the beginning of its 2009 fiscal year. The Company is currently assessing the impact of the Abstract on the measurement of its financial assets and financial liabilities. The Company does not expect the implementation to have a significant impact on the Company's operations, financial position, or disclosures.

4. ACCOUNTS RECEIVABLE

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

The Company has not previously experienced any material credit losses on the collection of receivables. Of the Company's significant individual accounts receivable at December 31, 2008, approximately 91% was owed from five customers (December 31, 2007 - 92% was owed from four customers).

5. PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment



December 31, 2008
----------------------------------------------------------------------------
Accumulated
depletion and Net
Cost depreciation book value
$ $ $
----------------------------------------------------------------------------
Petroleum and natural gas
properties 195,709,255 (61,376,728) 134,332,527
Office furniture and equipment 269,387 (262,437) 6,950
----------------------------------------------------------------------------

195,978,642 (61,639,165) 134,339,477
----------------------------------------------------------------------------
----------------------------------------------------------------------------


December 31, 2007
----------------------------------------------------------------------------
Accumulated
depletion and Net
Cost depreciation book value
$ $ $
----------------------------------------------------------------------------
Petroleum and natural gas
properties 162,472,330 (42,636,583) 119,835,747
Equipment under capital lease 1,020,307 (277,145) 743,162
Office furniture and equipment 311,213 (217,762) 93,451
----------------------------------------------------------------------------

163,803,850 (43,131,490) 120,672,360
----------------------------------------------------------------------------
----------------------------------------------------------------------------


For the years ended December 31, 2008 and 2007, no indirect general and administrative expenditures were capitalized.

As at December 31, 2008, $10,597,987 of costs related to undeveloped lands were excluded from costs subject to depletion (December 31, 2007 - $8,383,314). As at December 31, 2008, the depletion calculation included future development costs of $5,575,000 (December 31, 2007 - $3,226,000).

The Company has performed an impairment test as at December 31, 2008 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
Natural Gas Liquids
(Aeco) (Edmonton)
CDN $/mmbtu CDN $/bbl
----------------------------------------------------------------------------
2009 6.02 54.51
2010 7.27 64.04
2011 7.64 78.21
2012 8.05 83.31
2013 8.35 86.97
----------------------------------------------------------------------------
Each benchmark price increased on average approximately 2% from 2014 and
thereafter
----------------------------------------------------------------------------
----------------------------------------------------------------------------

There was no impairment at December 31, 2008.


6. GOODWILL

The Company tested the goodwill balance during 2007 taking into account the decline in corporate economic value reflected by the Company's share price as well as oil and gas asset and corporate sale transactions. Based on the Company's assessment, it was determined that the goodwill amount on the balance sheet could no longer be supported. As a result, the entire goodwill balance of $14,616,996, which was initially recorded as part of the Rio Alto Resources International Inc. acquisition on August 12, 2004, was deemed impaired.

7. CREDIT FACILITY

As at December 31, 2008, the Company had a demand, bank credit facility through ATB Financial of $40,000,000 (December 31, 2007 - $33,000,000). The facility bears interest at the lender's prime rate plus one quarter to one-half basis points depending on the Company's net debt to funds from operations ratio. Net debt is defined as the sum of working capital (deficiency) and the outstanding credit facility balance. Funds from operations represent cash provided by operating activities on the statement of cash flows less the effect of changes in non-cash working capital related to operating activities. The effective interest rate for the year ended December 31, 2008 was 4.84% (December 31, 2007 - 6.10%) and as at December 31, 2008, there was $28,358,033 drawn on the credit facility (December 31, 2007 - $20,589,362). As collateral for the facility, the Company has provided a general security agreement with the lender constituting a first ranking security interest in all personal property and a first ranking floating charge on all real property of the Company.

8. CAPITAL LEASE OBLIGATION

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

For the year ended December 31, 2008, there was $29,943 (2007 - $29,505) recorded in interest expense relating to capital leases.

9. 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, 2008 is approximately $6,352,000 (December 31, 2007 -$5,870,000) with a weighted average abandonment date of 17 years (December 31, 2007 - 18 years). The Company used credit adjusted, risk-free rates ranging from 5% to 10% and an inflation rate of 2% to arrive at the recorded liability of $3,838,337 at December 31, 2008 (December 31, 2007 - $3,448,714). In 2008, the estimated abandonment dates of some of the wells were revised to better reflect their economic lives. This resulted in a net reduction of $4,000 to the present value of the liability.

The Company's asset retirement obligations changed as follows:



December 31, December 31,
2008 2007
$ $
----------------------------------------------------------------------------
Asset retirement obligations, beginning of year 3,448,714 2,934,899
Adjustment to abandonment dates (4,000) -
Liabilities incurred 200,829 335,311
Accretion expense 192,794 178,504
----------------------------------------------------------------------------

Asset retirement obligations, end of year 3,838,337 3,448,714
----------------------------------------------------------------------------
----------------------------------------------------------------------------


10. FUTURE INCOME TAXES

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



2008 2007
----------------------------------------------------------------------------
Statutory income tax rate 29.61% 32.12%
$ $
Anticipated income tax expense (recovery) 649,243 (5,719,165)
Increase/(decrease) resulting from:
Goodwill impairment - 4,694,979
Stock based compensation expense 157,231 289,717
Other - 23,833
Non-deductible items 17,503 -
Rate adjustment 198,023 (1,400,164)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Future income tax expense (recovery) 1,022,000 (2,110,800)
----------------------------------------------------------------------------


The rate adjustment for the year ended December 31, 2008, reflects an increase in the estimated future income tax rate used to calculate future income taxes. In December 2007, the future tax liability previously recognized by the Company was recalculated to reflect lower tax rates as legislated by the Federal Government. The difference between the original estimate of the future tax liability and the adjusted estimate at lower tax rates resulted in a future tax recovery in 2007.

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



December 31, December 31,
2008 2007
$ $
----------------------------------------------------------------------------
Net book value of capital assets in excess of
tax pools (12,070,395) (8,527,115)
Share issue costs 179,629 421,141
Asset retirement obligations 1,007,947 871,145
Other 84,019 84,029
----------------------------------------------------------------------------

Future income taxes (10,798,800) (7,150,800)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


11. 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 credit facility and shareholders' equity comprised of retained earnings and share capital.

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

The Company monitors its capital structure based on the current and projected ratios of net debt to funds from operations. Net debt is the sum of the working capital (deficiency) and the outstanding credit facility balance. Funds from operations 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, 2008 is 1.65 (2.30 at December 31, 2007). The ratio may increase or decrease at certain times because of significant events such as acquisitions or dispositions, as well as large fluctuations in commodity prices. Efforts are made by management after a period of variation to bring the measure back in line. To facilitate the management of this ratio, the Company prepares annual budgets and monthly forecasts, which are updated depending on various factors such as general market conditions and successful capital deployment. The annual budget is approved by the Board of Directors.

The Company has some bank reporting requirements with respect to its credit facility that the Company has complied with for the year ended December 31, 2008. As collateral for the bank credit facility, the Company has provided a general security agreement with the lender constituting a first ranking security interest in all Company property and a first ranking floating charge on all real property of the Company.

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

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



12. SHARE CAPITAL

Authorized - Unlimited number of common voting shares without par value

December 31, 2008 December 31, 2007
----------------------------------------------------------------------------
Issued Number $ Number $
----------------------------------------------------------------------------
Common shares
Balance, beginning of year 55,625,132 99,175,434 47,757,632 89,584,611
Issued for cash on warrant
exercise (i) - - 55,000 33,935
Issued for cash on
flow-through
private placement (ii) - - 7,812,500 10,000,000
Tax effect of flow-through
shares (ii) - (2,626,000) - -
Exercise of stock options (iii) 6,666 10,665 - -
Issue costs, net of future
taxes of $149,000 - - - (443,112)
----------------------------------------------------------------------------
Balance, end of year 55,631,798 96,560,099 55,625,132 99,175,434
----------------------------------------------------------------------------
Special warrants
Balance at beginning and
end of year - - 55,000 33,935
Exercise of special
warrants (i) - - (55,000) (33,935)
----------------------------------------------------------------------------
Balance, as at end of the year - - - -
----------------------------------------------------------------------------
Share capital, end of year 55,631,798 96,560,099 55,625,132 99,175,434
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Contributed surplus
Balance, beginning of year 3,046,632 2,144,649
Non-cash compensation
expense (iv) 531,006 901,983
Transfer to share
capital (iii) (3,199) -
----------------------------------------------------------------------------
Contributed surplus, end of
year 3,574,439 3,046,632
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Common Shares

(i) Exercise of special warrants

During the year ended December 31, 2007, special warrant holders exercised 55,000 special warrants in exchange for 55,000 common shares for no additional cash consideration. As at December 31, 2008, there are no special warrants outstanding.

(ii) Private placement

On February 21, 2007, the Company issued under private placement 7,812,500 flow-through common shares at $1.28 per share for proceeds of $10,000,000 before total issue costs of $592,112. The Company is required to incur such expenditures on or before December 31, 2008. As at December 31, 2008, the Company has incurred all required expenditures. The tax benefit of $2,626,000, related to the flow-through shares, was renounced in its entirety in January 2008.

(iii) Exercise of options

On August 27, 2008, 6,666 stock options were exercised for a total cash consideration of $7,466 (3,333 stock options at $1.00 and 3,333 stock options at $1.24); this was recorded as an increase to share capital. Due to the exercise of the stock options, $3,199 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. As at December 31, 2008, a total of $10,665 has been recorded in share capital as a result of the stock options exercised.

(iv) Stock options

Non-cash compensation expense is comprised of the stock option benefit for all outstanding options amortized over the vesting period of the options.

Per share amounts

Basic per share amounts have been calculated using the weighted average number of common shares outstanding during the year of 55,627,426 (2007- 54,484,844). The diluted per share amounts for the year are calculated assuming the exercise of outstanding, in-the-money options, and future compensation costs to be incurred on outstanding options resulting in a weighted average number of common shares of 56,376,401 (2007 - 54,484,844). For the year ended December 31, 2008, the diluted per share amount is calculated based on 3,071,167 outstanding, in-the-money options (2007 - nil). Per share calculations that are anti-dilutive are not presented.

Stock option plan

The Company has a stock option plan authorizing the grant of options to purchase shares to designated participants, being directors, officers, employees or consultants. Under the terms of the plan, the Company may grant options to purchase shares equal to a maximum of ten percent of the total issued and outstanding shares and special warrants of the Company. The aggregate number of options that may be granted to any one individual must not exceed five percent of the total issued and outstanding shares, and special warrants. Options are granted at exercise prices equal to the estimated market value of the shares at the date of grant and may not exceed a ten year term. The vesting for options granted occurs over a three year period, with one third of the number granted vesting on each of the first, second, and third anniversary dates of the grant unless otherwise specified by the Board of Directors at the time of grant.



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

2008 2007
Weighted Weighted
Average Average
Number of Exercise Number of Exercise
Options Price Options Price
----------------------------------------------------------------------------
$ $
Stock options outstanding,
beginning of
year 5,365,834 1.69 4,071,334 1.96
Granted 930,000 0.72 1,584,500 0.98
Exercised (6,666) 1.12 - -
Expired (371,000) 1.88 - -
Forfeited (408,335) 1.77 (290,000) 1.57
----------------------------------------------------------------------------
Stock options outstanding, end of
year 5,509,833 1.51 5,365,834 1.69
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Stock options outstanding at the end of the year are comprised of the
following:

December 31, 2008
----------------------------------------------------------------------------
Exercisable Options
------------------------
Weighted Average
Number of Remaining Life Number of Weighted
Exercise Price Options (years) Exercisable Options Average Price
----------------------------------------------------------------------------
$ $
0.70 - 1.00 2,319,500 4.02 471,499 0.97
1.01 - 1.50 776,667 2.76 514,997 1.24
1.51 - 2.00 787,000 1.19 720,334 1.81
2.01 - 2.50 1,006,666 1.99 758,328 2.22
2.51 - 3.00 495,000 1.34 478,334 2.54
3.01 - 3.50 125,000 1.67 125,000 3.30
----------------------------------------------------------------------------
1.51 5,509,833 2.78 3,068,492 1.86
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The fair value of stock options granted to employees, directors, and consultants during the year ended December 31, 2008 and 2007, was estimated on the date of grant using the Black Scholes option pricing model with the following weighted average assumptions: dividend yield of zero percent (2007 - zero percent), expected volatility of 68.23 percent (2007 - 51.62 percent), risk-free interest rate of 2.29 percent (2007 - 3.90 percent), and an expected life of four years (2007 - four years). Outstanding options granted during the year ended December 31, 2008 had an estimated weighted average fair value of $0.38 per option (December 31, 2007 - $0.43 per option), for a total estimated value of $349,500 (2007 - $681,465). For the year ending December 31, 2008, a total of $531,006 (2007 - $901,983) has been recognized as stock compensation expense in general and administrative expenses with an offsetting credit to contributed surplus.

13. COMMITMENTS

The Company has entered into an operating lease for office premises expiring on November 30, 2009, which requires minimum monthly payments of $17,262 for the remainder of the lease.

14. 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 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, 2008:

----------------------------------------------------------------------------
Receivables Other financial Total carrying
liabilities value
----------------------------------------------------------------------------
$ $ $
Financial assets
Accounts receivable 5,902,432 5,902,432
----------------------------------------------------------------------------
Financial liabilities
Accounts payable and accrued
liabilities 13,940,693 13,940,693
Credit facility 28,358,033 28,358,033
----------------------------------------------------------------------------
Carrying value of financial instruments as
at December 31, 2007:

----------------------------------------------------------------------------
Receivables Other financial Total carrying
liabilities value
----------------------------------------------------------------------------
$ $ $
Financial assets
Accounts receivable 4,150,650 4,150,650
----------------------------------------------------------------------------
Financial liabilities
Accounts payable and accrued
liabilities 8,894,185 8,894,185
Credit facility 20,589,362 20,589,362
Capital lease obligation 284,112 284,112
----------------------------------------------------------------------------


Fair value of financial instruments

The fair value of a financial instrument is the amount that would be agreed on in an arm's-length transaction between knowledgeable, willing parties who are under no obligation to act. Fair values can be determined by reference to prices for a financial instrument in active markets to which the Company has access. In the absence of an active market, the Company determines fair values based on valuation models or by reference to other similar products in active markets.

Financial instruments recognized on the balance sheet consist of accounts receivable, accounts payable, and credit facility. As at December 31, 2008, 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 risks relating to commodity prices, and interest rates, as well as liquidity risk and credit risk.

Market risk

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

Commodity price risk

The Company is exposed to commodity price risk since its 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 by $2.9 million (2007 - $2.0 million). A similar decrease in commodity prices would have the opposite impact. As of December 31, 2008, the Company's natural gas and liquids production continues to be unhedged and is marketed in the Alberta spot market.

As at December 31, 2008, the Company had no fixed price contracts associated with future production.

Interest rate risk

The Company is exposed to interest rate risk, which arises primarily from its variable rate credit facility. The credit facility has a floating interest rate that will fluctuate based on prevailing market conditions. As at December 31, 2008, $28.4 million (2007 - $20.6 million) is subject to movements in floating interest rates. If interest rates on the floating credit facility decreased by 1%, it is estimated that earnings before tax for the year would increase by approximately $261 thousand (2007 - $158 thousand), assuming all other variables remained constant. A similar increase in the interest rate would have the opposite impact.

The objective of the Company's interest rate management activities is to minimize the amount of interest paid on the credit facility. In order to manage this risk, the Company utilizes short-term (less than 90 days) guaranteed notes that bear interest at a lower rate.

Credit risk

Credit risk arises from credit exposure to joint venture partners including 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 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 receivable on a monthly basis. As at December 31, 2008, the Company held capital advances of $979 thousand (2007 - $813 thousand). As at December 31, 2008, 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 facility. As at December 31, 2008, the Company had $28.4 million outstanding on its $40.0 million credit facility.

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

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