Cinch Energy Corp.
TSX : CNH

Cinch Energy Corp.

November 07, 2007 16:05 ET

Cinch Energy Corp. Releases Third Quarter 2007 Results

CALGARY, ALBERTA--(Marketwire - Nov. 7, 2007) - Cinch Energy Corp. (TSX:CNH) ("Cinch" or "the Company") is pleased to report on the Company's activities and financial results for the third quarter of 2007. Highlights are as follows:



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Three Months Ended Nine Months Ended
September 30, September 30,
2007 2006 2007 2006
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(Unaudited) (Unaudited) (Unaudited) (Unaudited)

Oil and gas sales, net of
transportation ($000's) 4,405 4,487 16,103 14,379

Sales volumes per day
Natural gas (Mcf/d) 6,050 5,529 6,329 5,633
Natural gas liquids (Bbl/d) 200 214 215 197
Equivalence at 6:1 (BOE/d) 1,208 1,135 1,270 1,135

Sales Price
Natural gas ($/Mcf) 5.56 6.14 7.15 7.00
Natural gas liquids ($/Bbl) 71.25 69.25 64.10 67.34
Equivalence at 6:1 ($/BOE) 39.63 42.97 46.45 46.38

$ $ $ $
Funds from operations
(000's)(1) 1,605 2,115 7,565 6,996
- per share, basic(1) 0.03 0.05 0.14 0.15
- per share, diluted(1) 0.03 0.04 0.14 0.14

Net income (loss) (000's)(3) (15,184) (576) (16,161) 172
- per share, basic (0.27) (0.01) (0.30) 0.00
- per share, diluted (0.27) (0.01) (0.30) 0.00

Capital expenditures
($000's) 7,851 7,403 18,009 27,642

Basic weighted average
shares and special warrants
outstanding (000's) 55,625 47,813 54,101 47,813

Working capital (net debt)
(2) ($000's)
- As at September 30, 2007 (24,987)
- As at December 31, 2006 (23,745)

As at November 5, 2007

Common shares outstanding 55,625,132
Options outstanding 5,090,500
- Weighted average exercise price 1.75
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(1) Funds from operations and funds from operations per share is not a
generally accepted accounting principle ("GAAP") 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 three and nine months ended September 30, 2007 includes
a goodwill writedown of $14,616,996.


President's Message

PRODUCTION, PRICES, AND COSTS

For the nine months ended September 30, 2007, Cinch's production averaged 1,270 BOE/d versus an average of 1,135 BOE/d in the first nine months of 2006 and 1,208 BOE/d in the third quarter of 2007. The increase over 2006 is attributable to new production adds in the Chime, Kakwa, and Resthaven areas. Production increased significantly averaging in excess of 1,800 BOE/d in the month of October as new wells were brought on stream in Musreau, Kakwa, and Chime. It is expected that production will increase again in January with the addition of our natural gas discovery in the Dawson area. The Musreau gas plant, which processes a majority of the Company's natural gas in the Chime area, will be shut down in order to be expanded from 115 mmcf/d to 190 mmcf/d, hence Cinch expects its production during the month of November to average approximately 550 BOE/d during this construction period. As projected earlier, the Company is still targeting 1900 BOE/d as its exit rate for 2007 when the Musreau plant resumes operations with its expanded capacity in December.

Prices for the first nine months of 2007 averaged $46.45 per BOE, which is up slightly from the 2006 nine month average of $46.38 per BOE. The price received in the third quarter of 2007 decreased substantially from the second quarter of $49.11 per BOE to $39.63. Natural gas prices in the third quarter of 2007 have softened considerably decreasing from $7.15 per mcf to $5.56 per mcf, as storage remains fairly full in comparison to prior years, however oil prices and natural gas liquids prices continue to strengthen under current market conditions. In addition to the high volumes of natural gas in storage the market was also being impacted with additional supplies of natural gas liquids being imported into the United States market.

Operating costs in the nine months of 2007 were $6.77 per BOE, as compared to $7.44 per BOE in the comparable period of 2006. In the three months ended September 30, 2007 operating costs increased to $7.90 per BOE due to property taxes incurred during the period and increased processing fees.

OPERATIONS

During the third quarter, Cinch participated in the drilling of two wells at Kakwa (operating one), and one well in Dawson.

At Chime, the Company drilled, completed, and tied in the Cutpick 9-36 gas well in which it has a 45% working interest. The well commenced production in October at 1.9 mmcf/d and is currently producing at approximately 1.0 mmcf/d. The results of this well were encouraging and it has given rise to a number of geophysically supported drilling locations for the Falher sands on the Chime acreage. An extension well, Cutpick 10-23 in which the Company has a 32.5% working interest, is expected to spud on November 15th. Two additional locations, Chime 13-28 and Smoky 14-26, are currently being proposed to partners for their management approval. If approved, these wells will be drilled in the fourth quarter.

Cinch has drilled the Kakwa 10-18 infill Dunvegan location in which it has a 100% working interest, and placed this well on production. This well commenced production in October at 3.7 mmcf/d and at month end was still producing at 3.3 mmcf/d. The Company also participated for its 12.5% working interest in the Kakwa 14-23 non operated well which has been completed and placed on production at rates in excess of 2 mmcf/d.

At Dawson, B.C., the 36% working interest Doe 1-32 Kiskatinaw test was completed and production tested as a new pool gas well. A number of potential development locations have been identified and an offset well to this discovery is expected to spud during the week of November 11th. Cinch will have a 36% working interest in this location. Currently the operator expects the discovery well to commence production in mid January.

NEW ALBERTA ROYALTY PROGRAM

The Company has reviewed the New Royalty Framework announced by the Government of Alberta and believes that the new royalty rates, which will become effective January 1, 2009, could increase the Company's royalty rate from the current rate of 21%, to approximately 23%, assuming that natural gas prices remain in the $6/mcf range, and that the Company's production decline rate is accurately projected. The royalty rate will increase with either a price increase or a production rate increase, and is also producing zone depth sensitive.

Cinch is evaluating how the new royalty rates will affect the economics of deep gas drilling in the Company's core Chime area, but believes that the economics under the new program have been severely impaired. The removal of the initial deep gas royalty holiday relief, and the implementation of a new royalty rate, (which is both producing zone depth and price sensitive,) has significantly increased the recovery period for capital costs incurred and hence reduces the Company's required internal rate of return for deeper gas prospects commencing in 2009. The Company will be making representation to its CAPP association and government officials advising them of the adverse affects of the royalty program for the deeper type prospects. The new program is in its early stages and is still being reviewed by the Company as economic models have not yet been adjusted to reflect the complex nature of the royalty calculations being applied in 2009.

The Company has prospects in British Columbia and will most likely put a greater emphasis on capital expenditures in other regions to mitigate the effects of the new Alberta royalty program on the Company. The economics of natural gas prospects is significantly enhanced in British Columbia as the maximum royalty rate is currently set at 27%.

NEW STAFF APPOINTMENT

The Company also announces that Denise Ramage, the Chief Financial Officer, has resigned to pursue other interests. On behalf of our Chairman John W. Elick, who started the Company with Denise in 2001, we wish to thank Denise for her dedication and tireless effort on behalf of the Company. Sarah Tait, a Chartered Accountant, who has been with the Company since May of 2005 in the position of Controller, has been promoted to the position of Chief Financial Officer.

George Ongyerth

President

Forward Looking Statements

Statements throughout this release that are not historical facts may be considered to be "forward looking statements". These forward looking statements sometimes include words to the effect that management believes or expects a stated condition or result. All estimates and statements that describe the Company's objectives, goals, or future plans, including management's assessment of future plans and operations, anticipated commodity prices and their impact, timing of expenditures and renunciation of flow-through expenditures, budgeted capital expenditures and the method of funding thereof, partner risk, 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, 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 release and the Company does not undertake any obligation to update publicly or to revise any of the included forward-looking statements, whether as a result of new information, future events or otherwise, except as may be required by applicable securities laws.

Barrel of Oil Equivalency

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

MANAGEMENT'S DISCUSSION AND ANALYSIS

November 5, 2007

The following management's discussion and analysis ("MD&A") should be read in conjunction with the unaudited interim financial statements and related notes for the three and nine month periods ended September 30, 2007 and the audited financial statements and related management discussion and analysis of Cinch Energy Corp. ("Cinch" or the "Company") for the year ended December 31, 2006. Additional information relating to Cinch, including Cinch's Annual Information Form, is available on SEDAR at www.sedar.com.

Non-GAAP Measures

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

The Company's production for the third quarter of 2007 was approximately 1,208 BOE/d, a slight decrease from the second quarter production of 1,249 BOE/d, attributable to natural declines. The Company was active in drilling, completing and tieing-in multiple locations in the third quarter of 2007 and subsequent to quarter end, the Company brought on 4 new wells producing at an initial combined flush rate of over 900 BOE/d (net).

The Company anticipates tieing-in another location in early January 2008, which was drilled and completed in the third quarter. In the fourth quarter of 2007, the Company plans to drill, complete and tie-in locations primarily in the Chime and Dawson areas.

We were recently informed that the Musreau gas plant, through which a substantial amount of our gas is processed, will be shut-in for approximately three weeks in November 2007 for further expansion. The shut-in is expected to reduce the Company's production to approximately 550 BOE/d for the month of November 2007. Although this results in a temporary disruption of production to the Company in the quarter, we look forward to expanded processing capacity in the Kakwa, Chime and Musreau areas.

The Company incurred $7.9 million of capital expenditures in the three months ended September 30, 2007 and exited the quarter with net debt of $25 million, $17.4 million of which is drawn on its $33 million demand bank credit facility.

The oil and gas market has experienced weak natural gas prices in 2007, particularly in the third quarter, and that, combined with the 2006 federal announcement relating to the taxation of income trusts and the uncertainty and apprehension surrounding the proposed Alberta royalty changes, has created difficult market conditions, and impacted valuations for natural gas producers. As it is not apparent at what point such conditions will reverse, management concluded that the goodwill balance of $14,616,996 was impaired and therefore wrote off the balance during the third quarter of 2007. The goodwill write off has no impact on the value of the Company's oil and gas properties.

IMPACT OF ALBERTA NEW ROYALTY FRAMEWORK

Management of the Company has reviewed the new proposed Alberta royalty framework. 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 2000 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 2300 to over 3000 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, although we are waiting for further clarification. Based on the information provided, we believe that 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 impossible 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 these proposed royalty changes will negatively impact the economics of the Company's deep gas drilling program in Alberta after January 1, 2009. The result of increased royalty rates and changes in the deep gas royalty program will challenge the economics of a number of our planned drilling locations in Alberta for 2008 and as such we will be revising our preliminary budgets to reflect such. We anticipate that, under the most recently proposed royalty changes, Cinch's expected allocation of exploration and development capital to the province of Alberta will be reduced as we expect that in many instances the Alberta regime currently proposed may no longer be economical for mid-depth and many multi-zone deep basin producers, especially at higher production rates. The Company currently has several prospects in British Columbia which could be pursued.



PRODUCTION

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Three Months Ended Nine Months Ended
September 30, September 30,
2007 2006 Change 2007 2006 Change
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Sales volumes % %
Natural gas (mcf/d) 6,050 5,529 9 6,329 5,633 12
Liquids (bbl/d) 200 214 (6) 215 197 9
Equivalence (BOE/d) 1,208 1,135 6 1,270 1,135 12

Sales prices $ $ % $ $ %
Natural gas 5.56 6.14 (9) 7.15 7.00 2
Liquids 71.25 69.25 3 64.10 67.34 (5)
Equivalence 39.63 42.97 (8) 46.45 46.38 0
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Sales volumes for the three and nine months ended September 30, 2007, increased over the same periods of 2006 due to four additional wells brought on production since September 2006.

Natural gas prices were 9% lower and 2% higher for the three and nine months ended September 30, 2007, respectively, compared to the same periods of 2006. Natural gas prices for the three months ended September 30, 2007 were 28% lower than the second quarter of 2007 and continued to remain weak subsequent to the quarter end. The Company's natural gas production continues to be unhedged and is marketed in the Alberta spot market.

Natural gas liquids pricing was 3% higher and 5% lower for the three and nine months ended September 30, 2007, respectively, compared to the same periods of 2006. Natural gas liquids represent approximately 23% of the Company's oil and gas production. The Company has not hedged any of its liquids production.



REVENUES

Dollars in thousands, except per unit amounts
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Three Months Ended Nine Months Ended
September 30, September 30,
2007 2006 Change 2007 2006 Change
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$ $ % $ $ %
Oil and gas sales, net
of transportation 4,405 4,487 (2) 16,103 14,379 12
Per BOE 39.63 42.97 (8) 46.45 46.38 0
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Revenues for the three months ended September 30, 2007 were 2% lower than the same period of 2006 due to lower natural gas prices partially offset by slightly higher production. Revenues for the nine months ended September 30, 2007 were 12% higher than the same period of 2006 due to higher production, and slightly higher natural gas prices partially offset by lower natural gas liquids pricing. Transportation expenses increased by approximately $0.24 per BOE in the first nine months of 2007 compared to the same period of 2006 as a result of rate increases.

Revenues for the three months ended September 30, 2007 have decreased from the second quarter of 2007, as a result of lower natural gas prices, as well as slightly lower production.



ROYALTIES

Dollars in thousands, except per unit amounts
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Three Months Ended Nine Months Ended
September 30, September 30,
2007 2006 Change 2007 2006 Change
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$ $ % $ $ %
Royalties, net of ARTC 1,111 948 17 3,508 2,985 18
Per BOE 10.00 9.08 10 10.12 9.63 5
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Royalty expense increased in the nine months ended September 30, 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, and due to higher revenues. Royalty expense also increased in the three and nine months ended September 30, 2007, due to the expiration of royalty holidays on higher producing wells.

Royalty expense for third quarter of 2007 decreased over the second quarter of 2007 due to lower revenues. The royalty rate for the third quarter of 2007 (royalties as a percentage of oil and gas sales), is consistent with the second quarter at approximately 25%. This rate is comprised of both crown royalties and gross overriding royalties.

Looking forward into 2008, management expects a similar royalty rate as the rate experienced in the first nine months of 2007. Management expects an increase in the royalty rate effective January 1, 2009 should the proposed new Alberta royalty framework be implemented.



OPERATING EXPENSES

Dollars in thousands, except per unit amounts
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Three Months Ended Nine Months Ended
September 30, September 30,
2007 2006 Change 2007 2006 Change
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$ $ % $ $ %
Operating 878 791 11 2,347 2,306 2
Per BOE 7.90 7.57 4 6.77 7.44 (9)
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Total operating expenses for three months ended September 30, 2007 were higher than the same period of 2006 due to an increase in gas processing fees, as well as an increase in property taxes. Operating expenses per BOE also increased due to higher total operating expenses.

Total operating expenses for the nine months ended September 30, 2007 were slightly higher than the same period of 2006 due to higher processing fees, as well as higher operator overhead charges due to fewer operated projects partially offset by lower compressor maintenance and repairs. Operating expenses per BOE decreased due to the increased production in 2007.

Total operating expenses for the third quarter of 2007 were higher than the second quarter due to increased processing fees as well as property taxes paid in the third quarter of 2007.

Operating expenses are not expected to exceed $7.00 per BOE in 2007. 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
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Three Months Ended Nine Months Ended
September 30, September 30,
2007 2006 Change 2007 2006 Change
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$ $ % $ $ %
General and
administrative 851 759 12 2,872 2,616 10
Per BOE 7.66 7.27 5 8.28 8.44 (2)
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Total general and administrative expenses increased for the three and nine months ended September 30, 2007 compared to the same periods of 2006 due to higher salaries and related compensation, most of which relates to higher stock based compensation expense (5,100,500 options at September 30, 2007 compared to 4,217,334 options at September 30, 2006). The Company does not capitalize indirect general and administrative expenses. General and administrative expenses also increased due to higher insurance costs, as well as lower overhead recoveries due to a change in the mix of operated versus non-operated activities.

General and administrative expenses per BOE were higher in the third quarter of 2007 compared to the same period of 2006 due to higher total general and administrative expenses.

General and administrative expenses per BOE were lower for the nine months ended September 30, 2007 compared to the same period of 2006 due to higher production partially offset by higher total general and administrative expenses.

Total general and administrative expenses decreased in the third quarter by approximately $99 thousand compared to the second quarter due to increased overhead recoveries, which directly offsets general and administrative expenses.



INTEREST EXPENSE

Dollars in thousands, except per unit amounts
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Three Months Ended Nine Months Ended
September 30, September 30,
2007 2006 Change 2007 2006 Change
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$ $ % $ $ %
Interest expense 234 73 221 660 211 213
Per BOE 2.11 0.70 201 1.90 0.68 179
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Interest expense increased in the three and nine months ended September 30, 2007 compared to the same periods of 2006 due to higher draws on the Company's bank credit facility in 2007, exiting the quarter with an outstanding credit facility balance of $17.4 million. In 2006, the Company did not draw on its operating line until April 2006 and exited the third quarter of 2006 with an amount outstanding under its credit facility of $11.3 million.



ACCRETION OF ASSET RETIREMENT OBLIGATIONS EXPENSE

Dollars in thousands, except per unit amounts
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Three Months Ended Nine Months Ended
September 30, September 30,
2007 2006 Change 2007 2006 Change
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$ $ % $ $ %
Accretion expense 46 20 130 132 48 175
Per BOE 0.42 0.20 110 0.38 0.16 138
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Accretion expense increased in the three and nine months ended September 30, 2007 compared to the same periods of 2006 due to 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
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Three Months Ended Nine Months Ended
September 30, September 30,
2007 2006 Change 2007 2006 Change
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$ $ % $ $ %
Depletion and
depreciation 2,628 2,658 (1) 9,123 7,654 19
Per BOE 23.64 25.45 (7) 26.32 24.69 7
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Total depletion and depreciation expense as well as depletion per BOE for the three months ended September 30, 2007 decreased compared to the same period of 2006 due to positive drilling results in the third quarter of 2007 resulting in reserve additions. Total depletion and depreciation expense, as well as depletion per BOE for the nine months ended September 30, 2007 increased compared to the same period of 2006 mostly due to a larger capital base being depleted, as well as increased production, with most reserve additions occurring in the third quarter.

The depletion and depreciation expense in the third quarter of 2007 decreased compared to the second quarter by approximately $560 thousand or $4.41/BOE due to reserve additions.



TAXES

Dollars in thousands, except per unit amounts
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Three Months Ended Nine Months Ended
September 30, September 30,
2007 2006 Change 2007 2006 Change
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$ $ % $ $ %
Future income tax
recoveries (751) (170) 342 (934) (1,490) (37)
Per BOE (6.75) (1.63) 314 (2.69) (4.81) (44)
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A future income tax recovery was recorded in the third quarter of 2007 commensurate with the net loss experienced in the quarter as well as due to a change in estimate of the future tax rate expected to be in effect at the time the future tax liability begins to reduce. The first nine months of 2006 were also impacted by stock compensation expense, and by the partial non-deductibility of crown charges, elimination of Alberta Royalty Tax Credit 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 and 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 nine months ended September 30, 2006 balance.

On October 30, 2007, the Federal Government announced its intent to reduce corporate tax rates starting in 2008 through to 2012. The Company will reflect the impact of these changes in its financial statements once these laws become substantively enacted.



Tax pools at September 30:

In thousands
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2007 2006
$ $
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COGPE 13,531 12,728
CDE 25,227 19,705
CEE 28,470 16,609
UCC 19,485 19,670
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86,713 68,712
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The Company's tax pools increased by 26% since September 30, 2006 as a result of capital expenditures which were higher than the tax pools 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. The Company will renounce $10 million of Canadian exploration expenditures to the flow through investors effective December 31, 2007. The Company anticipates no difficulties in meeting this obligation.



NET INCOME (LOSS) AND FUNDS FROM OPERATIONS

In thousands, except per share figures
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Three Months Ended Nine Months Ended
September 30, September 30,
2007 2006 Change 2007 2006 Change
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$ $ % $ $ %
Net income (loss) (15,184) (576) 2536 (16,161) 172 (9496)
per basic share (0.27) (0.01) 2164 (0.30) 0.00 (8415)
per diluted share (0.27) (0.01) 2245 (0.30) 0.00 (8631)
Funds from operations 1,605 2,115 (24) 7,565 6,996 8
per basic share 0.03 0.05 (40) 0.14 0.15 (4)
per diluted share 0.03 0.04 (25) 0.14 0.14 (2)
Weighted average
shares & special
warrants outstanding 55,625 47,813 16 54,101 47,813 13
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For the nine months ended September 30, 2007, the Company incurred a net loss, attributable to a goodwill writedown in the third quarter of $14.6 million, as well as higher royalties, general and administrative expenses, operating expenses, depletion and depreciation and interest expense partially offset by higher revenues.

The Company's funds from operations decreased by 24% and increased by 8% over the three and nine months ended September 30, 2006, respectively. For the three months ended September 30, 2007, funds from operations are lower due to lower revenues, higher royalties, higher operating and general and administrative expenses, as well as higher interest expense. For the nine months ended September 30, 2007, funds from operations are higher primarily due to increased revenues due to higher production levels.



LIQUIDITY AND CAPITAL RESOURCES

In thousands
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September 30, December 31,
2007 2006 Change
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$ $ %
Working capital deficiency 7,614 6,441 18
Credit facility 17,373 17,304 0
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Net debt 24,987 23,745 5
Long-term capital lease obligation 71 277 (74)
Shareholders' equity 84,332 90,551 (7)
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At September 30, 2007, the Company had net debt of $25.0 million, comprised of a working capital deficiency of $7.6 million and an amount outstanding on its credit facility of $17.4 million. The $1.2 million increase in net debt from December 31, 2006 can be attributed to capital expenditures of $18.0 million and capital lease payments of $200 thousand partially 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 nine months ended September 30, 2007 of $7.6 million.

Management currently intends to fund the remainder of its 2007 capital program with a combination of funds generated from operations and its bank credit facility. Management monitors and updates its forecast to incorporate changes in capital, actual results and changes in commodity market pricing, and despite the weakness in natural gas pricing, has forecast that it has sufficient access to capital to carry out the planned 2007 program. At September 30, 2007, the Company had draws of $17.4 million on its $33.0 million demand bank credit facility.

The decrease in shareholder's equity at September 30, 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, as previously discussed.



CAPITAL EXPENDITURES
Additions to property, plant and equipment

In thousands
----------------------------------------------------------------------------
Nine months ended September 30,
2007 2006
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$ $
Land and rentals 2,118 6,209
Seismic 272 639
Drilling, completing and equipping 13,497 16,618
Pipelines and facilities 2,054 3,907
Other assets 68 269
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Total 18,009 27,642
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The capital additions for the nine months ended September 30, 2007 include approximately $2.0 million relating to an acquisition which consolidated additional land interests and eliminated a gross overriding royalty effective June 20, 2007. The remainder of the capital expenditures was incurred primarily on drilling, completing as well as tieing-in locations in the Kakwa, Kakwa East, Wilder, Dawson and Chime areas. At September 30, 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 where considered strategic.

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 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 this increasingly 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 the Company does have several prospects in British Columbia which could be pursued. We do, however, expect that the Alberta government will take the necessary time to understand the potential impact that the current proposed changes to the royalty system will have on activity levels and investor confidence before they finalize their decision.

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.

In Alberta, the reduction emission guidelines outlined the Climate Change and Emissions Management Amendment Act (the "Act") came into effect July 1, 2007. Alberta facilities emitting more than 100,000 tonnes of greenhouse gases a year must reduce their emissions intensity by 12 per cent. Industries have three options to choose from in order to meet the reduction requirements outlined in the Act, and these are: (a) by making improvement to operations that result in reductions; (b) by purchasing emission credits from other sectors or facilities that have emissions below the 100,000 tonne threshold and are voluntarily reducing their emissions; or (c) by contributing to the Climate Change and Emissions Management Fund. Industries can either choose one of these options or a combination thereof. 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 intends to optimize its operations with respect to compressor fuel usage and natural gas flaring so that a significant 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.

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 for the Company in order 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 September 30, 2007, that have materially affected, or are reasonably likely to affect, the Company's internal controls over financial reporting.

The Chief Executive Officer and Chief Financial Officer have signed form 52-109F2- Certification of interim 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
greater
less than 1-3 4-5 than
Total 1 year years years 5 years
----------------------------------------------------------------------------

Capital lease obligation 355 284 71 - -
Operating lease 377 174 203 - -
----------------------------------------------------------------------------
732 458 274 - -
----------------------------------------------------------------------------
----------------------------------------------------------------------------


On February 21, 2007, the Company issued 7,812,500 flow through common shares for gross proceeds of $10 million. The Company will renounce $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 2 of the Company's financial statements for the three and nine months ended September 30, 2007.

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.

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

The Company is largely 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 have seen 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. To date in 2007, the natural gas market has softened from the beginning of the year and we continue to see the impact on revenues and cash flows generated, as well as a decrease in industry capital activity. The natural gas prices realized in the third quarters of 2007 were 31% and 28% lower than those realized in the first and second quarters of 2007, respectively. The softening market, anticipated to continue at least in the near term, has also impacted the Company's capital spending for the first nine months of 2007, which is only approximately two thirds of what it was for the same period in 2006. 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.

For the fourth quarter of 2007, natural gas prices are expected to remain weak with a slight increase toward the end of the year as winter demand increases. The weakened prices could make access to capital through internal and external sources increasingly challenging. The Company does anticipate the natural gas liquids pricing to remain strong for the remainder of 2007, which will partially offset the impact of lower natural gas prices.



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

Q1 Q2 Q3 Q4 Annual
----------------------------------------------------------------------------
2007 $ $ $ $ $
----------------------------------------------------------------------------
Oil and gas sales, net of
transportation and
before royalties 6,116 5,582 4,405
Funds from operations 3,371 2,589 1,605
Per share - basic 0.07 0.05 0.03
- diluted 0.06 0.05 0.03
Net income (loss) (268) (709) (15,184)
Per share - basic (0.01) (0.01) (0.27)
- diluted (0.01) (0.01) (0.27)
Capital expenditures 6,228 3,930 7,851
Total assets 136,520 134,834 125,730
Working capital (net
debt) 1 (17,264) (18,673) (24,987)
----------------------------------------------------------------------------
Production (BOE/d) 1,354 1,249 1,208
----------------------------------------------------------------------------
2006 $ $ $ $ $
----------------------------------------------------------------------------
Oil and gas sales, net of
transportation and
before royalties 5,200 4,692 4,487 5,733 20,112
Funds from operations 2,475 2,406 2,115 2,970 9,966
Per share - basic 0.05 0.05 0.05 0.06 0.21
- diluted 0.05 0.05 0.04 0.06 0.20
Net income (loss) (131) 879 (576) (488) (317)
Per share - basic (0.00) 0.02 (0.01) (0.01) (0.01)
- diluted (0.00) 0.02 (0.01) (0.01) (0.01)
Capital expenditures 6,696 13,542 7,403 9,324 36,966
Total assets 113,356 121,861 125,894 136,983 136,983
Working capital (net
debt) 1 (820) (11,942) (17,307) (23,745) (23,745)
----------------------------------------------------------------------------
Production (BOE/d) 1,130 1,141 1,135 1,320 1,182
----------------------------------------------------------------------------
2005 $ $ $ $ $
----------------------------------------------------------------------------
Oil and 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 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
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
(September 30, 2007 - $71,028, December 31, 2006 - $276,806, December
31, 2005 - $420,988, December 31, 2004 - $620,764).


Financial Statements

Cinch Energy Corp.

September 30, 2007
(unaudited)


CINCH ENERGY CORP.

BALANCE SHEETS

(unaudited)

September 30, December 31,
As at 2007 2006
$ $
----------------------------------------------------------------------------

ASSETS (notes 5 and 6)

Current
Accounts receivable 3,511,915 9,107,635
Prepaid expenses and deposits 674,042 957,338
----------------------------------------------------------------------------
4,185,957 10,064,973

Property, plant and equipment (note 3) 121,544,353 112,301,421

Goodwill (note 4) - 14,616,996
----------------------------------------------------------------------------

125,730,310 136,983,390
----------------------------------------------------------------------------
----------------------------------------------------------------------------

LIABILITIES AND SHAREHOLDERS' EQUITY

Current
Accounts payable and accrued liabilities 11,515,779 16,229,842
Credit facility (note 5) 17,373,193 17,304,333
Current portion of capital lease obligation
(note 6) 284,112 275,789
----------------------------------------------------------------------------

29,173,084 33,809,964
----------------------------------------------------------------------------

Capital lease obligation (note 6) 71,028 276,806

Asset retirement obligations (note 7) 3,423,008 2,934,899

Future income taxes (note 8) 8,307,500 9,410,600
----------------------------------------------------------------------------

40,974,620 46,432,269
----------------------------------------------------------------------------

Commitments (notes 9 and 10)

Shareholders' equity
Share capital (note 9) 99,195,734 89,618,546
Contributed surplus (note 9) 2,933,306 2,144,649
Deficit (17,373,350) (1,212,074)
----------------------------------------------------------------------------
84,755,690 90,551,121
----------------------------------------------------------------------------
125,730,310 136,983,390
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying notes


CINCH ENERGY CORP.

STATEMENTS OF OPERATIONS, COMPREHENSIVE INCOME (LOSS) AND DEFICIT

(unaudited)

Three months ended Nine months ended
September 30, September 30,

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

$ $ $ $

Revenue
Oil and gas sales 4,622,990 4,692,773 16,818,957 14,960,809
Transportation (218,196) (205,702) (716,044) (581,754)
Royalties (1,111,273) (948,096) (3,507,627) (2,985,248)
Other income 26,571 15,504 59,881 123,000
----------------------------------------------------------------------------
3,320,092 3,554,479 12,655,167 11,516,807
----------------------------------------------------------------------------

Expenses
Operating 877,927 790,652 2,346,670 2,305,718
General and
administrative (note 9) 850,997 759,119 2,871,742 2,615,840
Interest on credit facility 226,870 65,493 638,346 191,045
Interest on capital lease
(note 6) 7,413 7,267 21,946 20,073
Accretion of asset
retirement obligations
(note 7) 46,240 20,422 131,524 48,498
Depletion and
depreciation 2,628,113 2,657,673 9,123,019 7,653,564
Goodwill Impairment
(note 4) 14,616,996 - 14,616,996 -
----------------------------------------------------------------------------
19,254,556 4,300,626 29,750,243 12,834,738
----------------------------------------------------------------------------

Loss before income taxes (15,934,464) (746,147) (17,095,076) (1,317,931)
----------------------------------------------------------------------------

Taxes (note 8)
Future income tax
recovery (750,700) (169,800) (933,800) (1,489,700)
----------------------------------------------------------------------------

Net income (loss) and
comprehensive income
(loss) for the period
(note 2) (15,183,764) (576,347) (16,161,276) 171,769

Deficit, beginning of
period (2,189,586) (147,423) (1,212,074) (895,539)
----------------------------------------------------------------------------

Deficit, end of period (17,373,350) (723,770) (17,373,350) (723,770)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Net income (loss) and
comprehensive income
(loss) for the period
per share (note 9)

Basic and diluted (0.27) (0.01) (0.30) 0.00
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying notes


CINCH ENERGY CORP.

STATEMENTS OF CASH FLOWS

(unaudited)

Three months ended Nine months ended
September 30, September 30,

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

$ $ $ $

Operating activities
Net income (loss) for
the period (15,183,764) (576,347) (16,161,276) 171,769
Add non-cash items:
Depletion and
depreciation 2,628,113 2,657,673 9,123,019 7,653,564
Goodwill Impairment 14,616,996 - 14,616,996 -
Accretion of asset
retirement obligations 46,240 20,422 131,524 48,498
Non-cash compensation
expense (note 9) 248,360 183,213 788,657 611,819
Future income tax
recovery (750,700) (169,800) (933,800) (1,489,700)
----------------------------------------------------------------------------

1,605,245 2,115,161 7,565,120 6,995,950

Net change in non-cash
working capital 477,526 554,571 1,431,740 (1,478,343)
----------------------------------------------------------------------------

Cash provided by
operating activities 2,082,771 2,669,732 8,996,860 5,517,607
----------------------------------------------------------------------------

Investing activities
Additions to property,
plant and equipment (7,851,047) (7,403,335) (18,009,366) (27,641,502)
Net change in non-cash
working capital 2,633,456 (70,282) (350,627) 5,236,591
----------------------------------------------------------------------------

Cash used in investing
activities (5,217,591) (7,473,617) (18,359,993) (22,404,911)
----------------------------------------------------------------------------

Financing activities
Increase in credit
facility 3,196,135 4,876,545 68,860 11,255,977
Issue of common shares,
net of issue costs - (8,180) 9,407,888 (76,571)
Payments on capital
lease (59,561) (68,947) (197,455) (9,453)

Net change in non-cash
working capital (1,754) 4,467 83,840 62,757
----------------------------------------------------------------------------

Cash provided by
financing activities 3,134,820 4,803,885 9,363,133 11,232,710
----------------------------------------------------------------------------

Decrease in cash - - - (5,654,594)

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

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

Supplemental
information:
Cash taxes paid - - - -
Cash interest paid 277,857 72,759 660,292 211,117
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying notes


CINCH ENERGY CORP.

NOTES TO FINANCIAL STATEMENTS

September 30, 2007 and 2006
(Unaudited)


1. SIGNIFICANT ACCOUNTING POLICIES

The unaudited interim financial statements of Cinch Energy Corp. have been prepared in accordance with Canadian generally accepted accounting principles, following the same accounting policies and methods of computation as the financial statements of the Company for the year ended December 31, 2006 except as disclosed in note 2 below. These unaudited financial statements do not include all disclosures required in the annual financial statements and should be read in conjunction with the Company's annual audited financial statements and notes thereto for the year ended December 31, 2006.

2. 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.

As discussed in this note, the Company adopted several new accounting policies effective January 1, 2007.

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).

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.



3. PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment

September 30, 2007
----------------------------------------------------------------------------
Accumulated
depletion and Net
Cost depreciation book value
$ $ $
----------------------------------------------------------------------------

Petroleum and natural gas
properties 159,581,658 (38,913,156) 120,668,502
Equipment under capital lease 1,021,073 (252,572) 768,501
Office furniture and equipment 305,850 (198,500) 107,350
----------------------------------------------------------------------------

160,908,581 (39,364,228) 121,544,353
----------------------------------------------------------------------------
----------------------------------------------------------------------------


December 31, 2006
----------------------------------------------------------------------------
Accumulated
depletion and 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 three and nine month period ended September 30, 2007 and for the year ended December 31, 2006, no indirect general and administrative expenditures were capitalized.

For the three months ended September 30, 2007, $10,525,878 of costs related to undeveloped lands were excluded from costs subject to depletion (December 31, 2006 - $10,900,069). For the three months ended September 30, 2007, the costs subject to depletion included future development costs of $4,068,000 (December 31, 2006 - $3,264,000).

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 as of June 20, 2007, which was the closing date of the transaction.

4. 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 recent oil and gas asset and corporate sale transactions. Based on the Company's assessment, it was determined that the goodwill balance 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 September 30, 2007 -
----------------------------------------------------------------------------
----------------------------------------------------------------------------


5. CREDIT FACILITY

As at September 30, 2007, the Company had a demand, bank credit facility 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 nine months ended September 30, 2007 was 6.11% (September 30, 2006 - 5.8%). The interest rate realized in the first nine months of 2007 is lower than the prime rate due to drawings on guaranteed notes, which bear interest at a lower rate. As at September 30, 2007, there was $17,373,193 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 Company 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 6).



6. CAPITAL LEASE OBLIGATION

The Company is committed to annual minimum payments under a capital lease
agreement as follows:

Years ending December 31, $
----------------------------------------------------------------------------
2007 78,514
2008 314,055
----------------------------------------------------------------------------

Total minimum lease payments 392,569

Less amounts representing interest at 5.12% (37,429)
----------------------------------------------------------------------------

Present value of minimum lease payments 355,140

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

Capital lease obligation at June 30, 2007 71,028
----------------------------------------------------------------------------
----------------------------------------------------------------------------


During the three and nine month periods ended September 30, 2007, there was $7,413 and $21,946, respectively, (2006 - $7,267 and $20,073, respectively) recorded in interest expense relating to capital leases. There is a first charge on the Company's assets as security for the capital lease obligation.

7. ASSET RETIREMENT OBLIGATIONS

The total future asset retirement obligations result from the Company's net ownership interest in wells and facilities. Management estimates the total undiscounted amount of future cash flows required to reclaim and abandon wells and facilities as at September 30, 2007 is approximately $6,015,000 to be incurred over the next 43 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 $3,423,008 at September 30, 2007 (December 31, 2006 - $2,934,899).



The Company's asset retirement obligations changed as follows:

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

Asset retirement obligations, as at December 31, 2006 2,934,899
Liabilities incurred 356,585
Accretion expense 131,524
----------------------------------------------------------------------------

Asset retirement obligations, as at September 30, 2007 3,423,008
----------------------------------------------------------------------------
----------------------------------------------------------------------------


8. FUTURE INCOME TAXES

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



Three months ended Nine months ended
September 30, September 30,

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

Statutory income tax rate 32.12% 34.49% 32.12% 34.49%
$ $ $ $
Anticipated income tax
recovery (5,118,150) (257,346) (5,490,938) (454,554)
Increase/(decrease)
resulting from:
Goodwill impairment 4,694,979 - 4,694,979 -
Stock based compensation
expense 79,773 63,190 253,317 211,016
Other 25,203 2,034 23,833 4,005
Resource allowance - (99,095) - (315,955)
Non-deductible crown
royalties, net of ARTC - 96,774 - 136,325
Rate adjustment (432,505) 24,643 (414,991) (1,070,537)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Future income tax
recovery (750,700) (169,800) (933,800) (1,489,700)
----------------------------------------------------------------------------


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:



September 30, December 31,
2007 2006
$ $
----------------------------------------------------------------------------

Net book value of capital assets in excess of
tax pools (9,929,957) (11,051,577)
Share issue costs 556,057 649,182
Asset retirement obligations 982,403 886,339
Other 83,997 105,456
----------------------------------------------------------------------------

Future income tax liability (8,307,500) (9,410,600)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


9. SHARE CAPITAL

Authorized - Unlimited number of common voting shares without par value

----------------------------------------------------------------------------
Issued Number $
----------------------------------------------------------------------------
Common shares
Balance, as at December 31, 2006 47,757,632 89,584,611
Issued for cash on flow through private placement
(i) 7,812,500 10,000,000
Exercise of special warrants (ii) 55,000 33,935
Issue costs, net of future income taxes (i) - (422,812)
----------------------------------------------------------------------------
Balance, as at September 30, 2007 55,625,132 99,195,734
----------------------------------------------------------------------------
Special warrants
Balance at beginning and end of period 55,000 33,935
Exercise of special warrants (ii) (55,000) (33,935)
----------------------------------------------------------------------------
Balance, as at September 30, 2007 - -
----------------------------------------------------------------------------
Share capital, as at September 30, 2007 55,625,132 99,195,734
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Contributed surplus
Balance, as at December 31, 2006 2,144,649
Non cash compensation expense (iii) 788,657
----------------------------------------------------------------------------
Contributed surplus, as at September 30, 2007 2,933,306
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Common Shares

(i) 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. The Company will renounce $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.

(ii) Exercise of special warrants

During the nine months ended September 30, 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 September 30, 2007, there are no special warrants outstanding.

(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

Basic per share amounts have been calculated using the weighted average number of common shares and special warrants outstanding during the three and nine months ended September 30, 2007 of 55,625,132 and 54,100,572, respectively. (September 30, 2006- 47,812,632 and 47,812,632, respectively). As at September 30, 2007, 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 fair value of the shares at the date of grant and may not exceed a ten year term. The vesting for options granted occurs over a three year period, with one third of the number granted vesting on each of the first, second, and third anniversary dates of the grant unless otherwise specified by the Board of Directors at the time of grant.



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

September 30, 2007 September 30, 2006
Weighted Weighted
Average Average
Number of Exercise Number of Exercise
Options Price Options Price
----------------------------------------------------------------------------
$ $
Stock options outstanding,
beginning of period 4,071,334 1.96 2,328,000 2.17
Granted 1,072,500 1.01 2,141,000 1.75
Cancelled (43,334) 2.03 (251,666) 2.16
----------------------------------------------------------------------------

Stock options outstanding,
end of period 5,100,500 1.76 4,217,334 1.96
----------------------------------------------------------------------------
----------------------------------------------------------------------------


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

September 30, 2007 September 30, 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
----------------------------------------------------------------------------
$ $ $ $
1.00-1.50 1,954,167 294,998 1.24 1.00-1.50 905,000 - -
1.51-2.00 1,338,000 1,153,000 1.85 1.51-2.00 1,431,334 993,999 1.87
2.01-2.50 1,106,667 451,663 2.22 2.01-2.50 1,131,000 101,666 2.22
2.51-3.00 576,666 361,664 2.54 2.51-3.00 625,000 201,666 2.54
3.01-3.50 125,000 83,334 3.30 3.01-3.50 125,000 41,667 3.30
----------------------------------------------------------------------------

1.76 5,100,500 2,344,659 2.00 1.96 4,217,334 1,338,998 2.04
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The options outstanding at September 30, 2007 have a weighted average remaining contractual life of 3.2 years (September 30, 2006 - 3.8 years).

The fair value of stock options granted to employees, directors and consultants during the nine month periods ended September 30, 2006 and 2007, was estimated on the date of grant using the Black Scholes option pricing model with the following weighted average assumptions: dividend yield of zero% (2006 - zero%), expected volatility of 50% (2006 - 48%), risk-free interest rate of 3.93% (2006 - 3.95%), and an expected life of four years (2006 - four years). Outstanding options granted during the nine month period ended September 30, 2007 had an estimated weighted average fair value of $0.44 per option (2006 - $0.73 per option), for a total estimated value of $466,425 (2006 - $1,556,600). For the three and nine month periods ended September 30, 2007, a total of $248,360 and $788,657, respectively, (2006 - $183,213 and $611,819, respectively,) has been recognized as stock compensation expense in general and administrative expenses with an offsetting credit to contributed surplus.

10. 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 6.

11. 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 obligations. As at September 30, 2007, there was no significant difference 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 September 30, 2007, the Company had no fixed price contracts associated with future production.

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