Cinch Energy Corp.
TSX : CNH

Cinch Energy Corp.

March 10, 2008 16:40 ET

Cinch Energy Corp. Releases 2007 Results

CALGARY, ALBERTA--(Marketwire - March 10, 2008) - Cinch Energy Corp (TSX:CNH) ("Cinch" or the "Company") is pleased to announce its financial and operational results for the year ended December 31, 2007.

In 2007, Cinch focused its exploration program in its core areas of Chime, Kakwa and Dawson West, British Columbia and was rewarded with significant discoveries. The Company is very excited about the prospective potential of its British Columbia, Dawson acreage in the Montney, Kiskatinaw, and Wabamun zones. In particular, the Dawson area has witnessed very significant land expenditures by industry for Montney potential acreage.

2007 HIGHLIGHTS

- Exited the year with a production rate of approximately 1900 BOE/d

- Successful Kiskatinaw natural gas discovery at Dawson, British Columbia

- Increased success in the Kakwa H Dunvegan pool, Alberta

- Increased production in 2007 by 13%, averaging 1,340 BOE/d from 1,182 BOE/d in 2006

- Lowered Proven plus Probable Finding, Development and Acquisition Costs to $19.86/BOE

- Increased total proven reserves at December 31, 2007 by 13% to 4.4 million BOE

- Increased land holdings to 35 sections in Dawson, British Columbia, with Montney rights in 25 sections. A horizontal Montney well is planned for the 3rd quarter of 2008



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Three Months Ended Year Ended
December 31, December 31,
2007 2006 2007 2006
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Petroleum and natural gas
net sales, of transportation
($000's) 6,588 5,733 22,691 20,112
Production per day
Natural gas (Mcf/d) 7,749 6,500 6,687 5,851
Natural gas liquids (Bbl/d) 258 236 226 207
Equivalence at 6:1 (BOE/d) 1,549 1,320 1,340 1,182

Sales Price
Natural gas ($/Mcf) 6.61 7.49 6.99 7.14
Natural gas liquids ($/Bbl) 79.29 57.56 68.48 64.53
Equivalence at 6:1 ($/BOE) 46.22 47.22 46.38 46.62

$ $ $ $
Funds from operations
(000's) (1) 3,217 2,970 10,782 9,966
- per share, basic(1) 0.06 0.06 0.20 0.21
- per share, diluted(1) 0.06 0.06 0.20 0.20

Net Income (Loss) (000's) (3) 466 (488) (15,695) (317)
- per share, basic 0.01 (0.01) (0.29) (0.01)
- per share, diluted 0.01 (0.01) (0.29) (0.01)

Capital expenditures ($000's) 2,917 9,324 20,926 36,966

Basic weighted average shares
and special warrants
outstanding (000's) 55,625 47,813 54,485 47,813

Working capital (net debt)(2)
($000's)
As at December 31, 2007 (24,758)
As at December 31, 2006 (23,745)

As at March 7, 2008
Common Shares Outstanding 55,625,132
Options outstanding 4,899,833
- average exercise price 1.66
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(1) Funds from operations are 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
writedown of $14,616,996.


Exploration

In 2007, Cinch focused its exploration program in its core areas of Chime, Kakwa and Dawson and was rewarded with significant discoveries. Cinch participated in a total of 8 wells (2.6 net) of which 6 wells (2.3 net) were cased as potential gas wells, and 2 wells (0.3 net) were dry and abandoned. A significant gas discovery at Dawson, British Columbia in which Cinch has a 36% working interest, was flow tested at rates up to 10.1 mmcf/d. In addition, a 100% development well in the Kakwa H pool added substantial production volumes in the fourth quarter and is currently on stream at 1.7 mmcf/d. This well has added development locations to our 2008 program. The overall 2007 exploration program was reduced due to lower natural gas prices and Company partners' reconsidering their drilling programs.

Chime

The Chime property is located in northwestern Alberta, approximately 110 kilometres south of Grande Prairie. In 2007, Cinch participated in 2 gross (0.78 net) exploratory wells on the Chime block. Both wells were cased as potential gas wells and to date, one well is on stream while the other has yet to be completed. There are two wells scheduled to be drilled on the Chime property in 2008.

The Chime property consists of 10,240 gross (5,701 net) acres of developed land and 51,200 gross (15,429 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 2007, the Company continued to develop the Kakwa H Pool with the drilling of a 100% working interest development well at 10-18-61-04W6M which is now on stream at rates of approximately 1.7 mmcf/d. Additionally, during the year Cinch participated in a multi zone well (net 12.5%) which is currently producing at approximately 1.2 mmcf/d. The Company is currently drilling one development well at 100% working interest.

The Kakwa property consists of 5,280 gross (3,540 net) acres of developed land and 8,320 gross (5,797 net) acres of undeveloped land.

Dawson

In 2007, the Company participated in two gross (0.7 net) wells. Both were cased for Kiskatinaw gas potential. The Dawson 01-32 well is expected to go on stream in April at a restricted rate of about 6 mmcf/d while the Dawson 12-28 remains to be fully evaluated. At least three more wells are scheduled for this area in 2008.

The Company holds 35 sections of land in the Dawson Area of British Columbia, with average working interests varying between 20% to 40%. Within this land position Cinch specifically owns the Montney rights in 25 sections of land averaging a 33% working interest. The Company believes that these lands are favorably located for Montney gas potential as they lie between the ARC-operated Dawson Pool to the southeast and the Storm Exploration-operated pool to the northwest. Cinch is participating in a 3D seismic program on these lands designed to assist in the determination of the best possible locations to pursue with a horizontal drilling program that we hope to initiate during the summer. If successful, this could have a significant impact on Cinch's reserve and production base in the future.

Cinch holds 19,435 gross undeveloped acres (6,803 net undeveloped acres) in the Dawson Area, of British Columbia. In January, 2008, a well was spudded, which will earn an interest in 3 sections of land on a farmin opportunity. This well was cased for Kiskatinaw gas and is currently being completed.

Undeveloped Land

Cinch's undeveloped land base of 113,942 gross acres (48,641 net acres) continues to represent a significant asset to the Company. Although land sale activity has declined in 2007 in the Province of Alberta, the Dawson Area of British Columbia, with the emerging Montney gas play, has become an extremely competitive area for land sale activity. Cinch holds 19,435 gross undeveloped acres (6,803 net undeveloped acres) in the Dawson Area, British Columbia, which has become a core area of exploration activity for the Company. Based on an internal evaluation Cinch places a value of approximately $14.7 million on its undeveloped lands by taking into account recent land sales in the area.

The Company continues to hold a high average net working interest of 43% in its undeveloped land inventory, the majority of which is operated by Cinch. This land base allows the Company to continue with an active exploration program without having to compete with industry at land sales and to farmout lands to obtain leverage.



Undeveloped Land Holdings
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December 31, 2007 December 31, 2006
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Gross Acres 113,942 120,367
Net Acres 48,641 52,988
Average Working Interest 43% 44%
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RESERVES

The corporate reserves estimates, effective December 31, 2007, were prepared by the independent engineering firm of GLJ Petroleum Consultants Ltd. ("GLJ") in accordance with the definitions set out under National Instrument 5I-101 Standards of Disclosure for Oil and Gas Activities ("NI 51-101"). The Company interest reserve highlights are:

- Total proven reserves at December 31, 2007 increased 13% to 4.4 million BOE compared to 3.9 million BOE at December 31, 2006.

- Total proven plus probable reserves at December 31, 2007 increased 9% to 6.3 million BOE compared to 5.8 million BOE at December 31, 2006.

- On a proven plus probable basis, the finding, development and acquisition costs were $19.86 per BOE ($21.84 per BOE on a proven basis)

- On a proven plus probable basis, the finding and development costs were $15.42 per BOE ($17.96 per BOE on a proven basis).



FORECASTED PRICES AND COSTS

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

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Light and Natural Natural Total Total Variance
Medium Gas Gas 2007 2006 (2007 vs
Crude Oil Liquids 2006)

(mbbls) (mbbls) (mmcf) (mboe) (mboe) (mboe)
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Proved -Developed
Producing 7 557 19,640 3,837 3,471 366
-Developed
Non-Producing 16 34 2,996 549 402 147
-Undeveloped - - - - 45 (45)
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Total Proved 22 591 22,636 4,386 3,918 468
Probable 10 237 9,821 1,884 1,911 (27)
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Total Proved Plus
Probable 32 828 32,457 6,270 5,830 440
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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 Reserves Before Income Taxes - Forecasted Prices and
Costs

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Discounted at
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December 31, 2007 Undiscounted 8% 10% 15% 20%
(1) (2), (3) ($M) ($M) ($M) ($M) ($M)
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Proved -Developed
Producing 111,137 68,904 63,298 53,037 46,046
-Developed
Non-Producing 13,836 10,325 9,766 8,645 7,791
-Undeveloped - - - - -
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Total Proved 124,973 79,229 73,064 61,682 53,837
Probable 67,282 21,031 17,759 12,809 10,031
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Total Proved Plus Probable 192,255 100,261 90,824 74,492 63,868
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Note: May not add due to rounding

(1) Utilizing GLJ January 1, 2008 price forecast.

(2) As required by NI 51-101, undiscounted well abandonment costs of $1.7
million for total proved reserves and $2.1 million for total proved plus
probable reserves are included in the Net Present Value 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, 2008 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 Natural Gas Propane Butane Pentanes
Edmonton Alberta Plant Edmonton Edmonton Plus
Par Price Gate (Then Edmonton
40 degrees Current)
Year API
($CDN/bbl) ($CDN/MMBtu) ($CDN/Bbl) ($CDN/Bbl) ($CDN/Bbl)
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2008 91.10 6.53 58.30 72.88 92.92
2009 87.10 7.33 55.74 69.68 88.84
2010 83.10 7.37 53.18 66.48 84.76
2011 81.10 7.37 51.90 64.88 82.72
2012 81.10 7.37 51.90 64.88 82.72
2013 81.10 7.37 51.90 64.88 82.72
2014 81.10 7.57 51.90 64.88 82.72
2015 81.10 7.74 51.90 64.88 82.72
2016 81.12 7.91 51.91 64.89 82.74
2017 82.76 8.08 52.97 66.21 84.42
2018+ +2.0%/yr +2.0%/yr +2.0%/yr +2.0%/yr +2.0%/yr

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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, 2006 36.8 73.2 570.7 862.8
Technical (28.0) (39.8) (38) 42.5
Exploration Discoveries - - - -
Drilling Extensions 15.6 - 146.3 13.9
Infill Drilling - - - 1.7
Improved Recovery - - - -
Acquisition 2.5 3.4 (10.5) (15.5)
Production (4.5) (4.5) (77.8) (77.8)
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Closing Balance
December 31, 2007 22.4 32.3 590.7 827.7
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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, 2006 19,865.5 29,362.8 3,918.4 5,829.8
Technical (190.5) 2,354.9 (97.7) 395.2
Exploration Discoveries 1,839.2 2,299.0 306.5 383.2
Drilling Extensions 4,043.1 1,451.3 835.7 255.8
Infill Drilling - 133.5 - 24.0
Improved Recovery - - - -
Acquisition (480.1) (703.5) (88.0) (129.4)
Production (2,440.9) (2,440.9) (489.1) (489.1)
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Closing Balance
December 31, 2007 22,636.3 32,457.1 4,385.8 6,269.5
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Note: May not add due to rounding

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

Additional reserve disclosure tables, as required under NI 51-101, will be
contained in the Annual Information Form to be filed on SEDAR on or before
March 31, 2008.


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 ("F,D&A") costs that will incorporate all acquisitions net of any dispositions during the year.



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2007 2006 3 year average
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Proven Proven + Proven Proven + Proven Proven +
Probable Probable Probable
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Capital ($'000s)
Exploration and
Development(1) 18,799 18,799 29,058 29,058 27,967 27,967
Acquisition capital 2,127 2,127 7,779 7,779 3,807 3,807
Change in future
capital (38) (2,481) 23 874 594 1,344
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Total capital
including change in
future capital 20,888 18,445 36,860 37,711 32,368 33,118
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Total capital
excluding goodwill 20,888 18,445 36,860 37,711 32,368 33,118
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Reserve additions
(mboe)
Exploration and
development 1045 1058 744 962 835 1,074
Acquisition (88) (129) 312 515 137 215
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Total reserve
additions (mboe) 957 929 1,056 1,477 972 1,289
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Costs ($/boe)
F&D 17.96 15.42 39.12 31.12 34.23 27.30
FD&A 21.84 19.86 34.92 25.53 33.32 25.70
FD&A excluding
goodwill 21.84 19.86 34.92 25.53 33.32 25.70
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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.


Production & Reserve Life Index

The Company's reserve life index using annualized fourth quarter production
is 7.8 years for proven BOE reserves compared to 8.1 years in 2006 and 11.1
years for proven plus probable BOE reserves compared to 12.1 years in 2006.

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2007 2006
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Calculated using:
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Annualized Annualized
Q4 Average Q4 Average
Production Production Production Production
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Production (boe/d) 1,549 1,340 1,320 1,182
Proved reserves (mboe) (1) 4,386 4,386 3,918 3,918
Proved reserve life index
(years) 7.8 9.0 8.1 9.1
Proved plus probable
reserves (mboe) (1) 6,270 6,270 5,830 5,830
Proved plus probable reserve
life index (years) 11.1 12.8 12.1 13.5
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(1) Company interest reserves means 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 1,900 BOED.

Reserve Replacement

The Company's 2007 capital investment program replaced 2007 average
production by a factor of 2.0 times on a proved basis and 1.9 times on a
proved plus probable basis.

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2007 2007 2006 2006
(Average) (Annualized Q4) (Average) (Annualized Q4)
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Production (mboe) 489.1 565.4 431.4 481.7
Proved reserve additions
after revisions of
prior periods (mboe) 956.5 956.5 1,056 1,056
Proven replacement ratio 2.0 1.7 2.4 2.2
Proved plus probable
reserve additions after
revision of prior
periods (mboe) 928.8 928.8 1,477 1,477
Proved plus probable
replacement ratio 1.9 1.6 3.4 3.1
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Recycle Ratio

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 presents the recycle ratio on both an FD&A basis (based on 2007 actual FD&A) and an F&D basis.



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2007 2007 2006 2006
(FD&A) (F&D) (FD&A) (F&D)
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Operating netbacks ($/BOE)(1) 30.13 30.13 30.20 30.20
Proved finding, development and net
acquisition costs after revision of
prior periods and including the change
in future development capital ($/BOE) 21.84 17.96 34.92 39.12
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Proved recycle ratios 1.4 1.7 0.9 0.8
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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) 19.86 15.42 25.53 31.12
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Proved plus probable recycle ratios 1.5 2.0 1.2 1.0
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Note: May not add due to rounding

(1) Operating netbacks are calculated by subtracting royalties and operating
costs from revenues.


OUTLOOK

The 2007 year presented challenges to the oil and gas industry with natural gas prices continuing to fluctuate dramatically, causing the industry to reconsider and delay some of its drilling programs. The industry was then faced with a review of the existing royalty structure by the Alberta Government, which again created significant uncertainty going forward and to a certain extent remains unresolved. Not withstanding these issues your management remains optimistic with respect to the future, in particular with respect to its Dawson acreage in British Columbia.

The Company is budgeting for capital expenditures of $20.3 million which will be funded from existing cash flows and its bank credit facility. The Company's credit facility is currently set at $33 million which is not subject to review until April.

The Company is very excited about the prospective potential of its British Columbia, Dawson acreage in the Montney, Kiskatinaw, and Wabamun zones. In particular, the Dawson area has witnessed very significant expenditures by industry for Montney potential acreage. The success in this zone appears to be exploited through new horizontal drilling techniques and completion fracing procedures which previously were not available to industry. Cinch has budgeted a horizontal Montney well on its Dawson acreage for the third or fourth quarter of 2008. These upcoming drilling plans in 2008 continue to provide your management with optimism regarding the future growth potential for your Company.

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 14th day of May, 2008 at 10:00 a.m. (Calgary time) in Great Room 3 at the Sandman Hotel Calgary, 888- 7th Avenue S.W., Calgary, Alberta.

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.

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 incurring flow-through expenditures, budgeted capital expenditures and the method of funding thereof, anticipated decline rates of new wells and production profile, expected royalty rates and changes to the Alberta royalty regime and the possible effect thereof on the Company and its allocation of capital, expected operating expenses and general and administrative expenses, drilling, completion and tie-in plans and the expected levels of activities may constitute forward-looking statements under applicable securities laws and necessarily involve risks including, without limitation, risks associated with oil and gas exploration, development, exploitation, production, marketing and transportation, volatility of commodity prices, imprecision of reserve estimates, environmental risks, competition from other producers, incorrect assessment of the value of acquisitions, failure to complete and/or realize the anticipated benefits of acquisitions, delays resulting from or inability to obtain required regulatory approvals and ability to access sufficient capital from internal and external sources and changes in the regulatory and taxation environment. As a consequence, the Company's actual results may differ materially from those expressed in, or implied by, the forward-looking statements. Readers are cautioned that the foregoing list of factors is not exhaustive. Additional information on these and other factors that could affect the Company's operations and financial results are included elsewhere herein and in reports on file with Canadian securities regulatory authorities and may be accessed through the SEDAR website (www.sedar.com), or at the Company's website (www.cinchenergy.com). Furthermore, the forward-looking statements contained in this release are made as at the date of this MD&A 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.

MANAGEMENT'S DISCUSSION AND ANALYSIS

March 7, 2008

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, 2007 and 2006. This commentary is based on the information available as at, and is dated, March 7, 2008. Additional information relating to Cinch, including Cinch'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 the fourth quarter of 2007 increased 28% over the third quarter and increased 22% over the first nine months of 2007 due to 4 new wells coming on production in October 2007 at an initial combined rate of over 700 BOE/d (net). As a result of the additional production, the Company exited 2007 at a rate of approximately 1,900 BOE/d. It is anticipated that the new wells will experience typical Deep Basin decline rates of approximately 50% during the first year of production stabilizing thereafter. The fourth quarter production also reflects approximately 3 weeks of down time at the Musreau gas plant due to a plant expansion resulting in curtailed production for the month of November.

During the fourth quarter of 2007, the Company drilled, completed and tied-in locations primarily in the Kakwa, Chime and Dawson areas. At Dawson, the Company was anticipating tieing in well in January, 2008, which was drilled in the fourth quarter of 2007. This well, of which Cinch owns a 36% working interest, was flow tested in December over a 4 day period at rates up to 10.1 mmcf/d. Based on recent communications with the operator, the tie in of this well has been delayed due to some Westcoast issues and is now anticipated to come on stream in April 2008. In the fourth quarter of 2007, the Company also acquired additional lands in the Dawson area bringing the Company's total land holdings in that area to 35 sections. The Dawson area is very active with offsetting operators announcing exploration success in the Montney zone. The Company is closely monitoring the current activities in this area and continues to evaluate the release of new information.

The Company incurred $2.9 million of capital expenditures in the three months ended December 31, 2007 and exited the quarter with net debt of $24.8 million, with $20.6 million drawn on its $33 million demand bank credit facility.

IMPACT OF ALBERTA NEW ROYALTY FRAMEWORK

Management of the Company has reviewed the new proposed Alberta Royalty Framework ("NRF"). The proposed royalty changes are sensitive to well production rates, prices and well depths. On January 1, 2009, royalty rates for high volume natural gas wells will be significantly increased, while the lower rate wells could pay similar and, in some cases, lower royalties. Wells drilled to measured depths greater than 2,000 meters are eligible for a reduced royalty rate, although the ultimate reduction, if any, is dependent upon the rate of the well and the price at the time of production. The majority of Cinch's wells range in depths from 2,300 to over 3,000 meters. Our understanding of the proposed royalty changes is that the initial royalty relief received under the current deep gas royalty program will be eliminated. Based on the information provided and the Company's internally estimated forecast production for 2009, we believe the new royalty rates, which will become effective January 1, 2009, could increase the Company's corporate royalty rate from the current rate of 21% to a range between 23% to 30% assuming a natural gas price between $6/mcf to $8.50/mcf. It is currently not possible to determine what the Company's royalty rate will be in 2009, but an increase in the royalty rate will have a negative impact on Cinch's cash flows.

Management believes that the proposed royalty changes becoming effective January 1, 2009 will negatively impact the economics of the Company's deep gas drilling program in Alberta. In many instances, under the proposed royalty framework, it will no longer be economical for mid-depth and many multi-zone deep basin producers, especially at higher production rates. Management has already begun to see the impact of the proposed royalty changes through reduced partner willingness to participate in capital projects in Alberta. This impact will only be amplified as we move further into 2008 and certain projects originally planned for the later part of the year and extending into January 2009 are deemed uneconomical under the proposed royalty framework resulting in an increased number of cancelled projects. This is especially true for deep basin producers, whom under the proposed framework will be losing the deep gas royalty holiday incentives currently being provided. Cinch has adjusted its exploration and development capital budget for 2008 by reducing capital spending in Alberta and increasing capital spending in the Dawson Area of British Columbia where royalty rates are more favourable. The government has stated its intention to consult with industry and review the NRF for unintended consequences. It is not known at this time whether any further revisions to the proposal will be made nor what their impact will be.



PRODUCTION

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Three Months Ended Year Ended
December 31, December 31,
2007 2006 Change 2007 2006 Change
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Sales volumes % %
Natural gas (Mcf/d) 7,749 6,500 19 6,687 5,851 14
Liquids (Bbl/d) 258 236 9 226 207 9
Equivalence (BOE/d) 1,549 1,320 17 1,340 1,182 13

Sales prices $ $ % $ $ %
Natural gas ($/Mcf) 6.61 7.49 (12) 6.99 7.14 (2)
Liquids($/Bbl) 79.29 57.56 38 68.48 64.53 6
Equivalence ($/BOE) 46.22 47.22 (2) 46.38 46.62 (1)
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Sales volumes for the year ended December 31, 2007 increased compared to 2006 due to additional wells coming on production.

Sales volumes for the three months ended December 31, 2007 increased compared to the same period in 2006 due to 4 additional wells coming on production in October 2007. As a result, the Company exited 2007 at a rate of approximately 1,900 BOE/d. 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. The Company's fourth quarter production volumes were impacted by 3 weeks of downtime at the Musreau gas plant in November 2007 for a plant expansion.

Natural gas prices were 12% lower in the fourth quarter of 2007 compared to the same quarter of 2006 and 2% lower 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 38% higher in the fourth quarter of 2007 compared to the same quarter of 2006 and 6% higher year over year. Natural gas liquids revenues represent approximately 25% of the oil and gas revenues for 2007. The Company has not hedged any of its liquids production.



REVENUES

Dollars in thousands, except per unit amounts
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Three Months Ended Year Ended
December 31, December 31,
2007 2006 Change 2007 2006 Change
----------------------------------------------------------------------------
$ $ % $ $ %
Oil and gas sales, net of
transportation 6,588 5,733 15 22,691 20,112 13
Per BOE 46.22 47.22 (2) 46.38 46.62 (1)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Revenues for the three months and year ended December 31, 2007 are higher than the same periods of 2006 primarily as a result of higher natural gas production, as previously discussed. Transportation expenses increased by approximately $0.26 per BOE for the year ended December 31, 2007 compared to the same period of 2006 as a result of rate increases.



ROYALTIES

Dollars in thousands, except per unit amounts
----------------------------------------------------------------------------
Three Months Ended Year Ended
December 31, December 31,
2007 2006 Change 2007 2006 Change
----------------------------------------------------------------------------
$ $ % $ $ %
Royalties, net of ARTC 1,258 1,126 12 4,765 4,111 16
Per BOE 8.82 9.27 (5) 9.74 9.53 2
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Royalty expense, net of Alberta Royalty Tax Credit ("ARTC"), increased in the three months and year ended December 31, 2007 compared to the same periods of 2006 due to the elimination of the Alberta royalty tax credit of $500,000, effective January 1, 2007, as well as higher production and expiration of royalty holidays on higher producing wells.

The Company anticipates that its royalty rate in 2008 (royalties as a percentage of oil and gas sales), will be higher than 2007 at approximately 25% due to the expiration of royalty holidays on higher producing wells which occurred in the third and fourth quarters of 2007. Management further anticipates an increase in the royalty rate effective January 1, 2009 should the proposed Alberta royalty framework be implemented. Anticipated royalty rates can change however, depending upon commodity prices, actual success achieved and the zone in which productive success is achieved.



OPERATING EXPENSES

Dollars in thousands, except per unit amounts
----------------------------------------------------------------------------
Three Months Ended Year Ended
December 31, December 31,
2007 2006 Change 2007 2006 Change
----------------------------------------------------------------------------
$ $ % $ $ %
Operating 837 759 10 3,183 3,065 4
Per BOE 5.87 6.25 (6) 6.51 7.10 (8)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Total operating expenses increased in the three months and year ended December 31, 2007 compared to the same periods of 2006 mostly due to higher gas gathering and processing fees attributable to higher production volumes. There were also increases in road use and lease maintenance, contractor costs, as well as increased property taxes. Operating expenses per BOE decreased as a result of increased production in 2007, providing a larger production base over which to spread the fixed costs.

Total operating expenses as well as operating expenses per BOE were lower in the fourth quarter of 2007 compared to the third quarter due to property taxes expensed in the third quarter over lower production when compared to the fourth quarter.

Operating expenses are not expected to exceed $5.25 per BOE in 2008. 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 Year Ended
December 31, December 31,
2007 2006 Change 2007 2006 Change
----------------------------------------------------------------------------
$ $ % $ $ %
General and
administrative 1,114 932 20 3,985 3,548 12
Per BOE 7.81 7.68 2 8.15 8.22 (1)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Total general and administrative expenses increased for the three months and year ended December 31, 2007 compared to the same periods of 2006 due to higher salaries and related compensation. In order to remain competitive in the marketplace, salaries and related compensation increased by approximately $300 thousand for the year ended December 31, 2007. As at March 7, 2008, the Company has 4,899,833 options outstanding, amounting to approximately 8.8% of outstanding common shares. The Company does not capitalize any indirect general and administrative expenses. Total general and administrative expenses also increased due to lower overhead recoveries received as a result of a change in the mix of operated versus non-operated activities.

General and administration expenses per BOE increased for the three months ended December 31, 2007 compared to the same period of 2006 due to higher total general and administrative expenses partially offset by higher production in 2007. General and administration expense per BOE for the year ended December 31, 2007 decreased compared to 2006 as a result of increased production in 2007.

Total general and administrative expenses increased in the fourth quarter of 2007 compared to the third quarter due to higher salaries and related compensation, as well as lower overhead recoveries, as previously discussed.

General and administrative expenses for 2008 are not expected to exceed $5.75 per BOE as a result of higher budgeted production volumes for the year.



INTEREST EXPENSE

Dollars in thousands, except per unit amounts
----------------------------------------------------------------------------
Three Months Ended Year Ended
December 31, December 31,
2007 2006 Change 2007 2006 Change
----------------------------------------------------------------------------
$ $ % $ $ %
Interest expense 302 250 21 962 461 109
Per BOE 2.12 2.06 3 1.97 1.07 84
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Interest expense increased in the three months and year ended December 31, 2007 compared to the same periods of 2006 due to higher draws on the Company's bank credit facility in 2007, exiting the year with an outstanding credit facility balance of $20.6 million. In 2006, the Company did not draw on its $33 million bank line until the second quarter and exited the year with an amount outstanding under its credit facility of $17.3 million.



ACCRETION OF ASSET RETIREMENT OBLIGATIONS EXPENSE

Dollars in thousands, except per unit amounts
----------------------------------------------------------------------------
Three Months Ended Year Ended
December 31, December 31,
2007 2006 Change 2007 2006 Change
----------------------------------------------------------------------------
$ $ % $ $ %
Accretion expense 47 14 236 179 63 185
Per BOE 0.33 0.12 175 0.36 0.15 140
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Accretion expense increased in the three months and year ended December 31, 2007 compared to the same periods of 2006 as a result of an increase in the number of wells, as well as an increase in the Company's estimate of the risk-free interest rate on which the liability is accreted.



DEPLETION AND DEPRECIATION EXPENSE

Dollars in thousands, except per unit amounts
----------------------------------------------------------------------------
Three Months Ended Year Ended
December 31, December 31,
2007 2006 Change 2007 2006 Change
----------------------------------------------------------------------------
$ $ % $ $ %
Depletion and
depreciation 3,767 3,243 16 12,890 10,897 18
Per BOE 26.43 26.71 (1) 26.35 25.26 4
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Total depletion and depreciation expense for the three months and year ended December 31, 2007 increased compared to the same periods in 2006 as a result of a larger capital asset balance being depleted as well as higher production volumes, partially offset by reserve additions for 2007. Depletion and depreciation expense per BOE for the three months ended December 31, 2007 decreased compared to the same period of 2006 due to positive drilling results resulting in reserve additions partially offset by a larger capital asset balance. Depletion and depreciation expense per BOE for the year ended December 31, 2007 increased slightly compared to the same period in 2006 as a result of a larger capital asset balance being depleted.



TAXES

Dollars in thousands, except per unit amounts
----------------------------------------------------------------------------
Three Months Ended Year Ended
December 31, December 31,
2007 2006 Change 2007 2006 Change
----------------------------------------------------------------------------
$ $ % $ $ %
Current - - - - - -
Future income taxes
(recovery) (1,177) (81) 1,353 (2,111) (1,570) 34
Per BOE (8.26) (0.66) 1,152 (4.32) (3.64) 19
----------------------------------------------------------------------------
----------------------------------------------------------------------------


A future income tax recovery was recorded in the three months and year ended December 31, 2007 commensurate with the net loss experienced during those periods. The future income tax recovery recorded in the fourth quarter of 2007 also reflects the reduction in future tax rates as legislated by the Federal Government in December, 2007. The Federal Government announced reduced corporate tax rates for 2008 through to 2012. The 2006 future tax calculations were impacted by stock compensation expense, and by the partial non-deductibility of crown charges, elimination of ARTC and the resource allowance deduction. At this time, all of the latter three items are no longer a consideration in federal tax calculations for 2007 and future years, as a result of amendments to the Income Tax Act. Also, in the second quarter of 2006, the future tax liability previously recognized by the Company was recalculated to reflect lower tax rates as legislated by the Federal Government on June 22, 2006. The difference between the original estimate of the future tax liability and the adjusted estimate at lower tax rates resulted in a large future tax recovery recorded in the second quarter reflected in the year ended December 31, 2006 balance.



Tax pools at December 31, 2007:

Dollars in thousands
----------------------------------------------------------------------------
2007 2006
$ $
----------------------------------------------------------------------------
COGPE 13,559 12,593
CDE 25,935 23,266
CEE 29,007 18,272
UCC 18,332 21,346
----------------------------------------------------------------------------
86,833 75,477
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The Company's tax pools increased in 2007 as a result of capital expenditures which were higher than the tax deductions needed to eliminate taxable income. On February 21, 2007, the Company completed an equity financing for gross proceeds of $10 million, issuing 7,812,500 common shares on a flow through basis at $1.28 per share. 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. The Company anticipates no difficulties in meeting this obligation.



NET INCOME AND FUNDS FROM OPERATIONS

In thousands, except per share figures
----------------------------------------------------------------------------
Three Months Ended Year Ended
December 31, December 31,
2007 2006 Change 2007 2006 Change
----------------------------------------------------------------------------
$ $ % $ $ %
Net Income (Loss) 466 (488) (195)(15,695) (317) 4,851
per basic share 0.01 (0.01) (182) (0.29) (0.01) 4,251
per diluted share 0.01 (0.01) (184) (0.29) (0.01) 4,376
Funds from operations 3,217 2,970 8 10,782 9,966 8
per basic share 0.06 0.06 - 0.20 0.21 (4)
per diluted share 0.06 0.06 - 0.20 0.20 (1)
Weighted average share
& special warrants
outstanding 55,625 47,813 16 54,485 47,813 14
----------------------------------------------------------------------------
----------------------------------------------------------------------------


For the year ended December 31, 2007, the Company incurred a net loss of $15.7 million of which $14.6 million is attributable to a goodwill writedown in the third quarter of 2007. The goodwill writedown was a result of the weakening natural gas prices in 2007, particularly in the third quarter, and that, combined with the 2006 Federal Government's announcement relating to the taxation of income trusts and the uncertainty and apprehension surrounding the proposed Alberta royalty changes, created difficult market conditions, and impacted valuations for natural gas producers. The goodwill writedown has no impact on the value of the Company's oil and gas properties. The net loss experienced during the year can also be attributed to higher royalties, general and administrative expenses, operating expenses, and depletion and depreciation expense, partially offset by higher revenues compared to the same period of 2006. The net income incurred in the fourth quarter of 2007 is attributed to a future tax recovery which reflects the reduction in future tax rates, as previously discussed. The Company did incur a loss before taxes for the fourth quarter of 2007 of $711 thousand.

The Company generated positive funds from operations for the three months and year ended December 31, 2007, resulting in an 8% increase over funds from operations generated in the same periods of 2006. Funds from operations are higher primarily as a result of increased revenues due to higher production levels.



LIQUIDITY AND CAPITAL RESOURCES

Dollars in thousands
----------------------------------------------------------------------------
As at December 31,
2007 2006 Change
----------------------------------------------------------------------------
$ $ %
Working capital deficiency,
excluding credit facility (4,168) (6,441) 35
Credit facility (20,589) (17,304) (19)
----------------------------------------------------------------------------
Net debt (24,758) (23,745) (4)
Capital lease obligation - (277) 100
Shareholders' equity (85,315) (90,551) (6)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


At December 31, 2007, the Company had net debt of $24.8 million, comprised of a working capital deficiency of $4.2 million and an amount outstanding on its credit facility of $20.6 million. The $1 million increase in net debt from December 31, 2006 can be attributed to capital expenditures of $20.9 million and capital lease payments of $277 thousand offset by proceeds of $9.4 million (net of issue costs) received from a flow through financing completed on February 21, 2007 and funds from operations for the year ended December 31, 2007 of $10.8 million.

The fourth quarter funds from operations were $3.2 million, which is a $1.6 million increase from the third quarter funds from operations of $1.6 million and that combined with capital expenditures of $2.9 million in the fourth quarter, resulted in the Company exiting 2007 with net debt of $24.8 million, a $300 thousand decrease from the third quarter net debt of $25.1 million. Net debt at December 31, 2007 was lower than anticipated by the Company as a result of increasing commodity prices in the fourth quarter of 2007.

Management intends to fund its 2008 capital program with a combination of funds generated from operations and its bank credit facility. The Company's credit facility is currently set at $33 million, which is not subject to review until April 2008.

The decrease in shareholder's equity at December 31, 2007 from December 31, 2006 can mostly be attributed to the write off of the goodwill balance of approximately $14.6 million partially offset by the financing completed in February 2007 for $9.4 million (net), as previously discussed.



CAPITAL EXPENDITURES
Additions to property, plant and equipment

Dollars in thousands

----------------------------------------------------------------------------
Year Ended December 31,
2007 2006
----------------------------------------------------------------------------
$ $
Land and rentals 2,581 6,462
Seismic 281 984
Drilling, completing and equipping 15,852 23,989
Pipelines and facilities 2,289 5,378
Other assets (77) 153
----------------------------------------------------------------------------
Total 20,926 36,966
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Capital expenditures for the year ended December 31, 2007 reflect drilling, completion and tie-in operations primarily in the Kakwa, Kakwa East, Wilder, Dawson and Chime areas. Included in the capital expenditures for 2007 is approximately $2.15 million relating to an acquisition which consolidated additional land interests and eliminated a gross overriding royalty effective June 20, 2007. In 2007, additional reserves were added through drilling and completion operations in the Kakwa, Kakwa East, Dawson and Chime areas.

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 2008 capital program is budgeted at $20.3 million with approximately $11.6 million allocated to capital activities at Dawson, British Columbia and approximately $8.7 million allocated to Alberta primarily in the Chime, Kakwa and Musreau areas.

BUSINESS RISKS AND RISK MANAGEMENT

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

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

The financial capability of the Company's partners can pose a risk to the Company, particularly during periods when access to capital is more challenging and prices are depressed. The Company mitigates the risk of collection by attempting to obtain the partners share of capital expenditures in advance of a project and by monitoring receivables regularly. The ability of the Company to implement its capital program when the financial wherewithal of a partner is challenged can be more difficult, although the Company attempts to mitigate the risk by cultivating multiple business relationships and obtaining new partners when needed and where possible.

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

The Company has selected the appropriate personnel to monitor operations and has automated field information where possible, so that difficulties and operational issues can be assessed and dealt with on a timely basis, and so that production can be maximized as much as possible. Not all operational issues; however, are within the Company's control. Management will address them nonetheless, and attempt to implement solutions, which may be by their nature longer term.

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

The Company anticipates making substantial capital expenditures in the future for the exploration, development, acquisition and production of oil and natural gas reserves. If the Company's revenues or reserves decline, it may have limited ability to expend the capital necessary to undertake or complete future drilling programs. There can be no assurance that debt or equity financing will be available. The Company mitigates this risk by monitoring expenditures, operations and results of operations in order to manage available capital effectively.

Attracting and retaining qualified individuals is crucial to the Company's success. The Company understands the importance of maintaining competitive compensation levels given 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 impact conditions, and many secondary roads and future oil and gas production sites are incapable of supporting the weight of heavy equipment until the roads are thoroughly dry. The duration of difficult conditions has a direct impact on the Company's activity levels and as a result can delay operations.

The Government of Alberta has announced its new proposed royalty framework, which the Company is thoroughly evaluating. Based on the information provided to date, it is difficult to comment on the total impact of these potential changes to the Company's future operations. Currently, the majority of Cinch's production is in Alberta but given the current proposed royalty changes, Cinch's 2008 capital budget reflects reduced spending in Alberta and increased spending in British Columbia where royalty rates are more favourable.

All phases of the oil and natural gas business present environmental risks and hazards and are subject to environmental regulation pursuant to a variety of federal, provincial and local laws and regulations. Compliance with such legislation can require significant expenditures and a breach may result in the imposition of fines and penalties, some of which may be material. Environmental legislation is evolving in a manner expected to result in stricter standards and enforcement, larger fines and liability and potentially increased capital expenditures and operating costs. In 2002, the Government of Canada ratified the Kyoto Protocol (the "Protocol"), which calls for Canada to reduce its greenhouse gas emissions to specified levels. There has been much public debate with respect to Canada's ability to meet these targets and the Government's strategy or alternative strategies with respect to climate change and the control of greenhouse gases. The Federal Government has introduced legislation aimed at reducing greenhouse gas emissions using an "intensity based" approach, the specifics of which have yet to be determined. Bill C-288, which is intended to ensure that Canada meets its global climate change obligations under the Kyoto Protocol, was passed by the House of Commons on February 14, 2007.

On April 26, 2007, the Federal Government released its Action Plan to Reduce Greenhouse Gases and Air Pollution (the "Action Plan"), also known as ecoACTION which includes the Regulatory Framework for Air Emissions. This Action Plan covers not-only large industry, but regulates the fuel efficiency of vehicles and the strengthening of energy standards for a number of energy-using products. Given the evolving nature of the debate related to climate change and the control of greenhouse gases and resulting requirements, it is not currently possible to predict either the nature of those requirements or the impact on the Company and its operations and financial condition. The Company optimizes its operations with respect to compressor fuel usage and natural gas flaring so that a reduction in emissions is realized.

DISCLOSURE CONTROLS AND PROCEDURES

The Company has designed disclosure controls and procedures to provide reasonable assurance that material information relating to the Company required to be disclosed is recorded, processed, summarized and reported within the time periods specified by securities regulations and that information required to be disclosed is communicated to management on a timely basis. The Company's Chief Executive Officer and Chief Financial Officer have evaluated the effectiveness of these disclosure controls and procedures as of the end of the period covered by the annual filings and have concluded, based on such evaluation, that the Company's disclosure controls and procedures as of the end of such period are effective to provide reasonable assurance that material information relating to the Company is made known to them by others within the Company, particularly during the period in which the annual filings are being prepared.

INTERNAL CONTROLS OVER FINANCIAL REPORTING

The Company's Chief Executive Officer and Chief Financial Officer have designed, or caused to be designed under their supervision, internal controls over financial reporting relating to the Company to provide reasonable assurance regarding the reliability of the Company's financial reporting and the preparation of financial statements for external purposes in accordance with Canadian GAAP.

The Company's Chief Executive Officer and Chief Financial Officer are required to cause the Company to disclose any change in the Company's internal controls over financial reporting that occurred during the Company's most recent interim period that has materially affected, or is reasonably likely to materially affect, the Company's internal controls over financial reporting. No material changes in the Company's internal controls over financial reporting were identified during the three months ended December 31, 2007, that have materially affected, or are reasonably likely to affect, the Company's internal controls over financial reporting.

Based on their evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that the design of internal control over financial reporting was sufficiently effective as at December 31, 2007 to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with Canadian GAAP. The Chief Executive Officer and Chief Financial Officer have signed form 52-109F1- Certification of Annual Filings, which can be found on SEDAR at www.sedar.com.

CONTRACTUAL OBLIGATIONS, COMMITMENTS, AND GUARANTEES

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



Dollars in thousands
----------------------------------------------------------------------------
Payments
less greater
than than
Total 1 year 1-3 4-5 5
years years years
$ $ $ $ $
----------------------------------------------------------------------------
Operating lease 334 174 160 - -
----------------------------------------------------------------------------
334 174 160 - -
----------------------------------------------------------------------------
----------------------------------------------------------------------------


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. Management does not anticipate any difficulties in meeting this obligation.

CHANGES IN ACCOUNTING POLICIES

Effective January 1, 2007, the Company adopted the CICA Handbook Section 3855 "Financial Instruments - Recognition and Measurement", Section 3861 "Financial Instruments - Disclosure and Presentation", Section 3865 "Hedges", Section 1506 "Accounting Changes", Section 1530 "Comprehensive Income" and Section 3251 "Equity". The adoption of the new standards did not have a significant impact on the Company's financial statements due to the nature of the financial instruments recorded on the balance sheet as well as the nature of the contracts to which the Company is a party. The Company does not currently have any hedges in place and therefore the adoption of Section 3865 "Hedges" did not have any impact on the Company's financial statements. For more information on these policies, see note 3 of the Company's financial statements for the year ended December 31, 2007.

RECENT ACCOUNTING PRONOUNCEMENTS

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

On December 1, 2006, the CICA issued three new accounting standards: Handbook Section 1535, Capital Disclosures, Handbook Section 3862, Financial Instruments - Disclosures, and Handbook Section 3863, Financial Instruments - Presentation. These new standards are effective January 1, 2008. Section 1535 specifies the disclosure of (i) an entity's objectives, policies and processes for managing capital; (ii) quantitative data about what the entity regards as capital; (iii) whether the entity has complied with any capital requirements; and (iv) if it has not complied, the consequences of such non-compliance. The new Sections 3862 and 3863 replace Handbook Section 3861, Financial Instruments - Disclosure and Presentation, revising and enhancing its disclosure requirements, and carrying forward unchanged its presentation requirements. These new sections place increased emphasis on disclosures about the nature and extent of risks arising from financial instruments and how the entity manages those risks. The Company is currently assessing the impact of these new standards on its financial statements.

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 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 which must be addressed. The impact of these new standards on our financial statements is currently being assessed.

CRITICAL ACCOUNTING ESTIMATES

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

Reserves

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

Revenue Estimates

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

Cost Estimates

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

Asset Retirement Obligations

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

Income taxes

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

TREND ANALYSIS

In 2007, the Company continued to focus on drilling and completion operations, as well as tieing in production. Some of the challenges encountered in 2006 such as rig availability were alleviated with the continued softening of the oil and gas market experienced in the latter part of 2006 and throughout 2007.

The Company's production for the year ended December 31, 2007 increased compared to the same period of 2006 as a result of new wells coming on production. In the fourth quarter of 2007, there were 4 new wells which came on production at an initial combined rate of over 700 BOE/d (net).

The Company has made strides on building a stable production base and continues to work on achieving growth, exiting the year at a rate of approximately 1,900 BOE/d. Consistent with other exploration companies, there will be periods of higher production growth, periods with high Initial production on new wells which is then anticipated to decline and stabilize in future periods, with some periods experiencing less growth than others.

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 impacts the revenues and cash flows generated by the Company. In late 2005, the market experienced high commodity prices resulting in increased activity and strong equity valuations. In 2006, we started seeing a softening of the natural gas market and large decreases in prices when compared to the previous year. The decrease in commodity prices impacts the Company by reducing cash flows available for exploration and challenges the economics of potential capital projects. The volatility we have seen in the market also makes the long term price versus short term price assessment more challenging. Although in 2007, we did see a decline in some service and operating costs due to the reduced activity when compared to late 2005 and early 2006, they have not decreased at the same rate as natural gas prices from the highs in the last half of 2005. The natural gas market continued to soften throughout 2007 until the fourth quarter when natural gas prices strengthened while entering the winter months, but not to the same levels observed in late 2006. The natural gas prices realized in the fourth quarter of 2007 and year ended December 31, 2007 were 12% and 2% lower, respectively, than those realized in the same periods in 2006. The decreasing natural gas prices for the first nine months of 2007 directly impacted revenues and cash flows generated, as well as an overall decrease in industry capital activity was observed. Revenues and cash flows for the fourth quarter of 2007 increased over the third quarter due to increased production, as well as increasing natural gas prices.

The softening market impacted the Company's capital spending for 2007 which was only approximately 60% of its 2006 capital spending. We continue to face challenges as partner willingness to participate in projects has been reduced or delayed as access to capital becomes more difficult. The Company continually monitors capital spending and assesses the risk of each individual project to ensure that funds are prioritized appropriately.



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

Q1 Q2 Q3 Q4 Annual
----------------------------------------------------------------------------
2007 $ $ $ $ $
----------------------------------------------------------------------------
Petroleum and natural gas sales,
net of transportation and before
royalties 6,116 5,582 4,405 6,588 22,691
Funds from operations 3,371 2,589 1,605 3,217 10,782
Per share - basic 0.06 0.05 0.03 0.06 0.20
- diluted 0.06 0.05 0.03 0.06 0.20
Net income (loss) (268) (709) (15,184) 466 (15,695)
Per share - basic (0.01) (0.01) (0.27) 0.01 (0.29)
- diluted (0.01) (0.01) (0.27) 0.01 (0.29)
Capital expenditures 6,228 3,930 7,851 2,917 20,926
Acquisition - - - - -
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 (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
Acquisition - - - - -
Total assets 113,356 121,861 125,894 136,983 136,983
Working capital (net debt) (1) (820) (11,942) (17,307) (23,745) (23,745)
----------------------------------------------------------------------------
Production (BOE/d) 1,130 1,141 1,135 1,320 1,182
----------------------------------------------------------------------------
2005 $ $ $ $ $
----------------------------------------------------------------------------
Petroleum and natural gas sales,
net of transportation and before
royalties 6,062 5,821 7,207 8,323 27,413
Funds from operations 3,198 3,037 3,908 4,899 15,042
Per share - basic 0.10 0.09 0.09 0.10 0.38
- diluted 0.09 0.08 0.09 0.10 0.36
Net income (loss) 612 537 851 1,364 3,364
Per share - basic 0.02 0.01 0.02 0.03 0.08
- diluted 0.02 0.01 0.02 0.03 0.08
Capital expenditures 6,381 8,116 9,566 11,982 36,045
Acquisition - - 1,220 (15) 1,205
Total assets 80,706 89,047 112,178 113,620 113,620
Working capital (net debt) (1) (16,621) (3,670) 10,629 3,490 3,490
----------------------------------------------------------------------------
Production (BOE/d) 1,421 1,264 1,262 1,245 1,297
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Note: numbers may not cross-add due to rounding
(1) Working capital (net debt) excludes the long term financial liabilities
which consists of the long term portion of the capital lease obligation
(December 31, 2007 - $0, December 31, 2006 - $276,806, December 31, 2005
- $420,988).


CINCH ENERGY CORP.

BALANCE SHEETS

As at December 31, 2007 2006
$ $
----------------------------------------------------------------------------

ASSETS (notes 7 and 8)

Current
Accounts receivable (note 4) 4,150,650 9,107,635
Prepaid expenses and deposits 859,335 957,338
----------------------------------------------------------------------------
5,009,985 10,064,973

Property, plant and equipment (note 5) 120,672,360 112,301,421

Goodwill (note 6) - 14,616,996
----------------------------------------------------------------------------

125,682,345 136,983,390
----------------------------------------------------------------------------
----------------------------------------------------------------------------

LIABILITIES AND SHAREHOLDERS' EQUITY

Current
Accounts payable and accrued liabilities 8,894,185 16,229,842
Credit facility (note 7) 20,589,362 17,304,333
Current portion of capital lease obligation
(note 8) 284,112 275,789
----------------------------------------------------------------------------
29,767,659 33,809,964

Capital lease obligation (note 8) - 276,806

Asset retirement obligations (note 9) 3,448,714 2,934,899

Future income taxes (note 10) 7,150,800 9,410,600
----------------------------------------------------------------------------

40,367,173 46,432,269
----------------------------------------------------------------------------
Commitments (notes 11 and 12)

Shareholders' equity

Share capital (note 11) 99,175,434 89,618,546
Contributed surplus (note 11) 3,046,632 2,144,649
Deficit (16,906,894) (1,212,074)
----------------------------------------------------------------------------
85,315,172 90,551,121
----------------------------------------------------------------------------

125,682,345 136,983,390
----------------------------------------------------------------------------

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

See accompanying notes


CINCH ENERGY CORP.

STATEMENTS OF OPERATIONS AND DEFICIT

For the years ended December 31, 2007 2006
$ $
----------------------------------------------------------------------------

Revenue
Oil and gas sales 23,711,341 20,900,612
Transportation (1,020,548) (788,794)
Royalties (4,765,175) (4,110,930)
Other income 85,178 145,124
----------------------------------------------------------------------------
18,010,796 16,146,012
----------------------------------------------------------------------------

Expenses
Operating 3,183,424 3,064,713
General and administrative (note 11) 3,985,397 3,547,742
Interest on credit facility 932,309 433,677
Interest on capital lease (note 8) 29,505 27,339
Accretion of asset retirement obligations (note 9) 178,504 62,659
Depletion and depreciation 12,890,281 10,896,817
Goodwill impairment (note 6) 14,616,996 -
----------------------------------------------------------------------------
35,816,416 18,032,947
----------------------------------------------------------------------------

Loss before income taxes (17,805,620) (1,886,935)

Taxes (note 10)
Future income tax recovery (2,110,800) (1,570,400)
----------------------------------------------------------------------------

Net loss and comprehensive loss for the year (15,694,820) (316,535)

Deficit, beginning of year (1,212,074) (895,539)
----------------------------------------------------------------------------

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

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

Basic and diluted (0.29) (0.01)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

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

See accompanying notes


CINCH ENERGY CORP.

STATEMENTS OF CASH FLOWS

For the years ended December 31, 2007 2006
$ $
----------------------------------------------------------------------------

Operating activities
Net loss for the year (15,694,820) (316,535)
Add non--cash items:
Depletion and depreciation 12,890,281 10,896,817
Accretion of asset retirement obligations 178,504 62,659
Non-cash compensation expense (note 11) 901,983 893,807
Goodwill Impairment 14,616,996 -
Future income tax recovery (2,110,800) (1,570,400)
----------------------------------------------------------------------------
10,782,144 9,966,348
Net change in non-cash working capital 430,137 680,757
----------------------------------------------------------------------------
Cash provided by operating activities 11,212,281 10,647,105
----------------------------------------------------------------------------

Investing activities
Additions to property, plant and equipment (20,925,909) (36,965,708)
Net change in non-cash working capital (2,794,646) 3,616,069
----------------------------------------------------------------------------
Cash used in investing activities (23,720,555) (33,349,639)
----------------------------------------------------------------------------

Financing activities
Increase in credit facility 3,285,029 17,304,333
Issue of common shares, net of issue costs 9,407,888 (91,858)
Payments on capital lease (268,483) (78,400)
Net change in non-cash working capital 83,840 (86,135)
----------------------------------------------------------------------------
Cash provided by financing activities 12,508,274 17,047,940
----------------------------------------------------------------------------

Decrease in cash - (5,654,594)

Cash and cash equivalents, beginning of year - 5,654,594
----------------------------------------------------------------------------

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

Supplemental information:
Cash taxes paid - -
Cash interest paid 961,813 411,271
----------------------------------------------------------------------------
----------------------------------------------------------------------------

See accompanying notes


CINCH ENERGY CORP.

NOTES TO FINANCIAL STATEMENTS

December 31, 2007 and 2006

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.

Cash and cash equivalents

Term deposits with initial maturities less than three months are considered to be cash equivalents and are recorded at cost, which approximates market value.

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 unproductive, 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 impairment against 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 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 which 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. Any difference between the related costs incurred and the recorded liability is recorded as a gain or loss in the statements of operations in the period in which the settlement occurs.

Measurement Uncertainty

The amounts recorded for depletion and depreciation of petroleum and natural gas properties and other assets, 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.

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 finances a portion of its exploration and development activities through the issuance of flow through shares. Under the terms of a flow through share issue, 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 11. The Company has adopted the fair value based method of accounting for stock options. Stock option expense is recorded as a general and administrative expense for all options with a corresponding increase recorded to contributed surplus. The fair value of options granted is estimated at the date of grant using the Black-Scholes valuation model. Consideration paid by optionholders 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, 2007, the Company adopted six new accounting standards issued by the Canadian Institute of Chartered Accountants ("CICA"): Handbook Section 3855 "Financial Instruments - Recognition and Measurement", Section 3861 "Financial Instruments - Disclosure and Presentation", Section 3865 "Hedges", Section 1506 "Accounting Changes", Section 1530 "Comprehensive Income" and Section 3251 "Equity".

Impact upon adoption of Sections 3855, 3861, 3865, 1506, 1530 and 3251

The adoption of the new standards did not have a significant impact on the Company's financial statements due to the nature of the financial instruments recorded on the balance sheet and the contracts to which the Company is a party.

Financial instruments - recognition and measurement

Section 3855 establishes standards for recognizing and measuring financial assets, financial liabilities, and non-financial derivatives. It requires that financial assets and financial liabilities, including derivatives, be recognized on the balance sheet when the Company becomes a party to the contractual provisions of the financial instrument or non-financial derivative contract. Under this standard, all financial instruments are required to be measured at fair value upon initial recognition except for certain related party transactions. Measurement in subsequent periods depends on whether the financial instrument has been classified as held-for-trading, available-for sale, held-to-maturity, loans or receivables, or other financial liabilities. Financial assets and financial liabilities held-for-trading are measured at fair value with changes in those fair values recognized in net earnings. Financial assets held-to-maturity, loans and receivables, and other financial liabilities are measured at amortized cost using the effective interest method of amortization. Investments in equity instruments classified as available-for-sale that do not have a quoted market price in an active market are measured at cost.

Derivative instruments are recorded on the balance sheet at fair value, including those derivatives that are embedded in financial or non-financial contracts that are not closely related to the host contracts. Changes in the fair values of derivative instruments are recognized in net earnings, with the exception of derivatives designated as effective cash flow hedges and hedges of the foreign currency exposure of a net investment in a self-sustaining foreign operation, which are recognized in other comprehensive income.

In addition, Section 3855 requires that an entity must select an accounting policy of either expensing debt issue costs as incurred or applying them against the carrying value of the related asset or liability.

The financial instruments recognized on Cinch's balance sheet are deemed to approximate their estimated fair values therefore no further adjustments were required upon adoption of the new sections. There were no financial assets on the balance sheet which were designated as held-for-trading, held-to-maturity or available-for-sale. All financial assets were classified as loans or receivables and are accounted for on an amortized cost basis. All financial liabilities were classified as other liabilities.

Hedges

Section 3865 provides alternative treatments to Section 3855 for entities which choose to designate qualifying transactions as hedges for accounting purposes. It replaces and expands on Accounting Guideline 13 "Hedging Relationships", and the hedging guidance in Section 1650 "Foreign Currency Translation" by specifying how hedge accounting is applied and what disclosures are necessary when it is applied.

The Company does not currently have any hedges in place and therefore the adoption of Section 3865 "Hedges" did not have any impact on the Company's financial statements.

Accounting changes

Section 1506 provides expanded disclosures for changes in accounting policies, accounting estimates and corrections of errors. Under the new standard, accounting changes should be applied retrospectively unless otherwise permitted or where impracticable to determine. As well, voluntary changes in an accounting policy are to be made only when required by a primary source of GAAP or the change results in more relevant and reliable information.

Comprehensive income (loss) and accumulated other comprehensive income (loss)

Section 1530 introduces comprehensive income, which consists of net earnings and other comprehensive income ("OCI"). OCI represents changes in shareholder's equity during a period arising from transactions and changes in prices, markets, interest rates, and exchange rates. OCI includes unrealized gains and losses on financial assets classified as available-for-sale, unrealized translation gains and losses arising from self-sustaining foreign operations net of hedging activities and changes in the fair value of the effective portion of cash flow hedging instruments.

The Company has not entered into any transactions which require any amounts to be recorded to other comprehensive income (loss) or accumulated other comprehensive income (loss).

Equity

Section 3251 establishes standards for the presentation of equity and changes in equity during the reporting period. The requirements under this Section has been presented in these annual financial statements.

Future accounting changes

On December 1, 2006, the CICA issued three new accounting standards: Handbook Section 1535, Capital Disclosures, Handbook Section 3862, Financial Instruments - Disclosures, and Handbook Section 3863, Financial Instruments - Presentation. These new standards are effective January 1, 2008. Section 1535 specifies the disclosure of (i) an entity's objectives, policies and processes for managing capital; (ii) quantitative data about what the entity regards as capital; (iii) whether the entity has complied with any capital requirements; and (iv) if it has not complied, the consequences of such non-compliance. The new Sections 3862 and 3863 replace Handbook Section 3861, Financial Instruments - Disclosure and Presentation, revising and enhancing its disclosure requirements, and carrying forward unchanged its presentation requirements. These new sections place increased emphasis on disclosures about the nature and extent of risks arising from financial instruments and how the entity manages those risks. We are currently assessing the impact of these new standards on our financial statements.

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 which must be addressed. The impact of these new standards on our financial statements is currently being assessed.

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, 2007, approximately 92% was owed from 4 customers (December 31, 2006 - 91% was owed from 6 customers).



5. PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment

December 31, 2007
----------------------------------------------------------------------------
Accumulated 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
----------------------------------------------------------------------------
----------------------------------------------------------------------------


December 31, 2006
----------------------------------------------------------------------------
Accumulated Net
Cost depreciation book value
$ $ $
----------------------------------------------------------------------------

Petroleum and natural gas
properties 141,281,753 (29,905,549) 111,376,204
Equipment under capital
lease 1,020,307 (188,179) 832,128
Office furniture and
equipment 240,570 (147,481) 93,089
----------------------------------------------------------------------------

142,542,630 (30,241,209) 112,301,421
----------------------------------------------------------------------------
----------------------------------------------------------------------------


For the years ended December 31, 2007 and 2006, no indirect general and administrative expenditures were capitalized.

As at December 31, 2007, $8,383,314 of costs related to undeveloped lands were excluded from costs subject to depletion (December 31, 2006 - $10,900,069). As at December 31, 2007, the depletion calculation included future development costs of $3,226,000 (December 31, 2006 - $3,264,000).

Acquisition

Effective April 1, 2007, the Company acquired additional working interests in producing gas wells, as well as provided payment for the elimination of a gross overriding royalty. The total cash consideration of the acquisition was $2.15 million, all of which was allocated to petroleum and natural gas properties. An additional asset retirement obligation of $11,792 was recorded on this acquisition. The additional revenues and expenses incurred relating to the acquired assets have been accounted for in the Company's income statement commencing June 20, 2007, which was the closing date of the transaction.

The Company has performed an impairment test as of December 31, 2007 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 as follows:



Natural Gas
Natural Gas Liquids
(Aeco) (Edmonton)

Cdn $/mmbtu Cdn $/bbl
----------------------------------------------------------------------------
2008 6.75 92.92
2009 7.55 88.84
2010 7.60 84.76
2011 7.60 82.72
2012 7.60 82.72
----------------------------------------------------------------------------
Each benchmark price increased on average approximately 2% from 2013 and
thereafter
----------------------------------------------------------------------------
----------------------------------------------------------------------------

There was no impairment at December 31, 2007.


6. GOODWILL

The Company tested the goodwill balance as at September 30, 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, which was initially recorded as part of the Rio Alto Resources International Inc. acquisition on August 12, 2004, was deemed to be impaired.



$
----------------------------------------------------------------------------

Goodwill balance, as at December 31, 2006 14,616,996
Goodwill impairment (14,616,996)
----------------------------------------------------------------------------

Goodwill balance, as at December 31, 2007 -
----------------------------------------------------------------------------
----------------------------------------------------------------------------


7. CREDIT FACILITY

As at December 31, 2007, the Company had a demand, bank credit facility through ATB Financial of $33,000,000 (December 31, 2006 - $33,000,000). The facility bears interest at the lender's prime rate. The effective interest rate for the year ended December 31, 2007 was 6.10% (December 31, 2006 - 6.09%) and as at December 31, 2007, there was $20,589,362 drawn on the credit facility (December 31, 2006 - $17,304,333). As collateral for the facility, the Company has provided a general security agreement with the lender constituting a first ranking security interest in all personal property and a first ranking floating charge on all real property of the Company subject only to a subordination agreement to another bank for the amount of, and as security for, a capital lease (see note 8).

8. CAPITAL LEASE OBLIGATION

The Company is committed to annual minimum payments under a capital lease agreement which commenced in December, 2004, as follows:



Year ending December 31, $
----------------------------------------------------------------------------
----------------------------------------------------------------------------
2008 314,055
----------------------------------------------------------------------------

Total minimum lease payments 314,055

Less amounts representing interest at 5.12% (29,943)
----------------------------------------------------------------------------

Present value of minimum lease payments 284,112

Less current portion (284,112)
----------------------------------------------------------------------------

Long term portion of capital lease obligation at December 31, 2007 -
----------------------------------------------------------------------------
----------------------------------------------------------------------------


For the year ended December 31, 2007, there was $29,505 (2006 - $27,339) recorded in interest expense relating to capital leases. A first charge on the Company's assets has been provided as collateral for the capital lease obligation.

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, 2007 is approximately $5,870,000 with a weighted average abandonment date of 18 years (December 31, 2006 - $5,300,000). The Company used a credit adjusted, risk-free rate ranging from 5% to 7.5% and an inflation rate of 2% to arrive at the recorded liability of $3,448,714 at December 31, 2007 (December 31, 2006 - $2,934,899).



The Company's asset retirement obligations changed as follows:

December 31, 2007 December 31, 2006
$ $
----------------------------------------------------------------------------

Asset retirement obligations,
beginning of year 2,934,899 2,725,627
Adjustment to abandonment dates - (304,622)
Liabilities incurred 335,311 451,235
Accretion expense 178,504 62,659
----------------------------------------------------------------------------

Asset retirement obligations, end of
year 3,448,714 2,934,899
----------------------------------------------------------------------------
----------------------------------------------------------------------------


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:



2007 2006
----------------------------------------------------------------------------

Statutory income tax rate 32.12% 34.49%
$ $
Anticipated income tax recovery (5,719,165) (650,804)
Increase/(decrease) resulting from:
Goodwill impairment 4,694,979 -
Stock based compensation expense 289,717 308,274
Other 23,833 -
Resource allowance - (450,826)
Non-deductible crown royalties, net of ARTC - 274,700
Rate adjustment (1,400,164) (1,051,744)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Future income tax recovery (2,110,800) (1,570,400)
----------------------------------------------------------------------------


The future tax liability previously recognized by the Company was recalculated to reflect lower tax rates as legislated by the Federal Government in December, 2007. The difference between the original estimate of the future tax liability and the adjusted estimate at lower tax rates resulted in a large future tax recovery.

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,
2007 2006
$ $
----------------------------------------------------------------------------

Net book value of capital assets in excess
of tax pools (8,527,115) (11,051,577)
Share issue costs 421,141 649,182
Asset retirement obligations 871,145 886,339
Other 84,029 105,456
----------------------------------------------------------------------------

Future income taxes (7,150,800) (9,410,600)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

11. SHARE CAPITAL

Authorized - Unlimited number of common voting shares without par value

December 31, 2007 December 31, 2006
----------------------------------------------------------------------------
Issued Number $ Number $
----------------------------------------------------------------------------
Common shares
Balance, beginning of year 47,757,632 89,584,611 47,757,632 93,010,709
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
common share
renunciation (ii) - - - (3,362,000)
Issue costs, net of future
taxes of $149,000
(2006 - $27,760) - (443,112) - (64,098)
----------------------------------------------------------------------------
Balance, end of year 55,625,132 99,175,434 47,757,632 89,584,611
----------------------------------------------------------------------------
Special warrants
Balance at beginning and
end of year 55,000 33,935 55,000 33,935

Exercise of special
warrants (i) (55,000) (33,935) - -
----------------------------------------------------------------------------
Balance, as at end of the
year - - 55,000 33,935
----------------------------------------------------------------------------
Share capital, end of year 55,625,132 99,175,434 47,812,632 89,618,546
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Contributed surplus

Balance, beginning of year 2,144,649 1,250,842
Non cash compensation
expense (iii) 901,983 893,807
----------------------------------------------------------------------------
Contributed surplus, end
of year 3,046,632 2,144,649
----------------------------------------------------------------------------
----------------------------------------------------------------------------


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 a total of 55,000 common shares for no additional cash consideration. As at December 31, 2007, there are no special warrants outstanding.

(ii) Private Placement

On February 21, 2007, the Company issued under private placement a total of 7,812,500 flow through common shares at $1.28 per share for proceeds of $10,000,000 before total issue costs of $592,112. In January 2008, the Company renounced $10,000,000 of Canadian exploration expenditures to the flow through investors effective December 31, 2007 and is required to incur such expenditures on or before December 31, 2008. The Company anticipates no difficulties in meeting this obligation.

In February 2006, the Company renounced expenditures of $9,999,999 relating to flow through shares issued on September 8, 2005 and the tax benefit in the amount of $3,362,000 was recorded on that date.

(iii) Exercise of options

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

Per share amounts

Per share amounts have been calculated using the weighted average number of common shares and special warrants outstanding during the year of 54,484,844 (2006 - 47,812,632). As at December 31, 2007 and 2006, all of the stock options are anti-dilutive and therefore not included in the determination of dilutive per share amounts.

Stock option plan

The Company has a stock option plan authorizing the grant of options to purchase shares to designated participants, being directors, officers, employees or consultants. Under the terms of the plan, the Company may grant options to purchase shares equal to a maximum of ten percent of the total issued and outstanding shares 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:

2007 2006
Number of Weighted Number of Weighted
Options Average Options Average
Exercise Exercise
Price Price
----------------------------------------------------------------------------
$ $
Stock options outstanding,
beginning of year 4,071,334 1.96 2,328,000 2.17
Granted 1,584,500 0.98 2,141,000 1.75
Exercised - - - -
Cancelled/Expired (290,000) 1.57 (397,666) 2.11
----------------------------------------------------------------------------

Stock options outstanding, end of
year 5,365,834 1.69 4,071,334 1.96
----------------------------------------------------------------------------
----------------------------------------------------------------------------


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

December 31, 2007 December 31, 2006
----------------------------------------------------------------------------
Exercisable options Exercisable options
------------------- -------------------
Weighted Weighted
Exercise Number of Number of average Exercise Number of Number of average
Price Options Options price Price Options Options price
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$ $ $ $
0.50-1.00 1,459,500 - - 0.50-1.00 - - -
1.00-1.50 838,334 293,332 1.24 1.00-1.50 895,000 - -
1.51-2.00 1,338,000 1,191,334 1.85 1.51-2.00 1,338,000 888,998 0.78
2.01-2.50 1,055,000 449,996 2.22 2.01-2.50 1,125,000 81,666 2.18
2.51-3.00 550,000 363,331 2.54 2.51-3.00 588,334 184,999 2.55
3.01-3.50 125,000 83,334 3.30 3.01-3.50 125,000 41,667 3.30
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1.69 5,365,834 2,381,327 2.00 1.96 4,071,334 1,197,330 1.24
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The options outstanding at December 31, 2007 have a weighted average remaining contractual life of 3.1 years (December 31, 2006 - 3.6 years).

The fair value of stock options granted to employees, directors and consultants during the year ended December 31, 2007 and 2006, 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 (2006 - zero percent), expected volatility of 51.62 percent (2006 - 47.95 percent), risk-free interest rate of 3.90 percent (2006 - 3.95 percent), and an expected life of four years (2006 - four years). Outstanding options granted during the year ended December 31, 2007 had an estimated weighted average fair value of $0.43 per option (December 31, 2006 - $0.73 per option), for a total estimated value of $681,465 (2006 - $1,556,600). For the year ending December 31, 2007, a total of $901,983 (2006 - $893,807) has been recognized as stock compensation expense in general and administrative expenses with an offsetting credit to contributed surplus.

12. COMMITMENTS

The Company has entered into an operating lease for office premises expiring on November 30, 2009, which requires minimum monthly payments of $14,520 for the remainder of the lease.

The Company has entered into a capital lease obligation, as more fully described in note 8.

13. FINANCIAL INSTRUMENTS

Fair value of financial instruments

Financial instruments recognized on the balance sheet consist of accounts receivable, deposits, accounts payable, credit facility and capital lease obligation. As at December 31, 2007 and 2006, there were no significant differences between the carrying amounts of these financial instruments reported on the balance sheet and their estimated fair values. It is management's opinion that the Company is not exposed to significant credit risk.

Interest rate risk

The Company is exposed to interest rate risk relating to increases in interest rates on its variable rate credit facility.

Commodity price risk management

As at December 31, 2007, the Company had no fixed price contracts associated with future production.

14. BASIS OF PRESENTATION

Certain of the comparative figures have been reclassified to conform to the presentation adopted in the current year.

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