Cinch Energy Corp.
TSX : CNH

Cinch Energy Corp.

August 08, 2007 23:59 ET

Cinch Energy Corp. Releases Second Quarter 2007 Results

CALGARY, ALBERTA--(Marketwire - Aug. 8, 2007) - Cinch Energy Corp (TSX:CNH) ("Cinch" or "the Company") is pleased to report on the Company's activities and financial results for the second quarter of 2007. Highlights are as follows:



-------------------------------------------------------------------------
Three Months Ended Six Months Ended
June 30, June 30,
2007 2006 2007 2006
-------------------------------------------------------------------------
(Unaudited) (Unaudited) (Unaudited) (Unaudited)

Oil and gas sales, net
of transportation ($000's) 5,582 4,692 11,698 9,892

Sales volumes per day
Natural gas (Mcf/d) 6,157 5,723 6,472 5,685
Natural gas liquids (Bbl/d) 223 187 222 188
Equivalence at 6:1 (BOE/d) 1,249 1,141 1,301 1,136

Sales Price
Natural gas ($/Mcf) 7.75 6.64 7.90 7.42
Natural gas liquids ($/Bbl) 61.15 72.30 60.84 66.25
Equivalence at 6:1 ($/BOE) 49.11 45.19 49.68 48.12

$ $ $ $
Funds from operations
(000's)(1) 2,589 2,406 5,960 4,881
- per share, basic(1) 0.05 0.05 0.11 0.10
- per share, diluted(1) 0.05 0.05 0.11 0.10
Net income (loss) (000's) (709) 879 (978) 748
- per share, basic (0.01) 0.02 (0.02) 0.02
- per share, diluted (0.01) 0.02 (0.02) 0.02

Capital expenditures ($000's) 3,930 13,542 10,158 20,238

Basic weighted average
shares and special
warrants outstanding
(000's) 55,570 47,813 53,326 47,813
Working capital
(net debt)(2) ($000's) $
- As at June 30, 2007 (18,673)
- As at December 31, 2006 (23,745)

As at August 3, 2007

Common shares outstanding 55,625,132
Options outstanding 5,110,500
- Weighted average exercise price 1.76
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(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.




President's Message

PRODUCTION, PRICES, AND COSTS

For the six months ended June 30, 2007, Cinch's production averaged 1,301 BOE/d versus an average of 1,136 BOE/d in the first six months of 2006 and 1,249 BOE/d in the second quarter of 2007. The increase over 2006 is attributable to new production adds in the Chime, Kakwa, and the Resthaven areas. Production in the Bigstone area continued to be curtailed since March 2007, however additional firm processing capacity has now been made available by the operator commencing in August, which should alleviate the restrictions. The Company anticipates that production in the second half of 2007 should increase as new wells are brought on stream in Musreau, Kakwa, Chime, and Dawson.

Prices for the first six months of 2007 averaged $49.68 per BOE, which is up slightly from the 2006 first half average of $48.12 per BOE. The price received in the second quarter of 2007 decreased slightly from the first quarter to $49.11 per BOE. Natural gas prices in the third quarter of 2007 have softened considerably 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. The company does not have any hedges in place and remains positive about the future natural gas market.

Operating costs in the first half of 2007 were $6.24 per BOE, as compared to $7.37 per BOE in the comparable period of 2007, and down slightly from $6.30 per BOE in the second quarter of 2007. These decreases in operating costs are primarily due to additional production volumes coming on stream.

OPERATIONS

During the second quarter, Cinch operated the drilling of one well at Chime, Alberta.

At Chime, the Company drilled and cased subsequent to quarter end the Chime 9-36 well as a potential gas well. Cinch has a 45% working interest in this well, and has commenced completion operations in three zones, which is expected to take approximately three weeks. A number of follow up locations have been identified and have been surveyed in preparation for future development drilling, which is dependent upon completion results and also securing partner participation.

In the Musreau area, the Company participated in the recompletion operations of Musreau 14-7. The Musreau 14-7 well, in which Cinch has a 50% working interest, was completed as a dual zone gas well and is expected to commence production in early September at a rate of 600 mcf/d.

At Wilder, British Columbia, Cinch had operated the drilling of the Wilder 11-36 well and also the completion of the Wilder A06-5 well in the first quarter. Results from the drilling and completion operations were evaluated in the second quarter and resulted in uneconomic gas rates and the Company has now elected to abandoned the Wilder 11-36 well and not proceed with the drilling option.

At Kakwa, Cinch has drilled the Kakwa 10-18 infill Dunvegan location in which it has a 100% working interest, and cased this well as a potential gas well. This well is expected to commence production in September. The Company is also participating for its 12.5% working interest in the Kakwa 14-23 well which has commenced drilling.

At Kakwa East, the tie in operations of the Kakwa 15-12 oil discovery has now been delayed until January of 2008, which is anticipated to significantly reduce the Company's share of tie in costs, as the length of the pipeline will be reduced and costs will now be shared with offsetting operators. This will also delay the drilling of two budgeted development wells into the 2008 year.

At Dawson, B.C., the Doe 1-32 Kiskatinaw test, in which the Company has a 36% working interest, has been cased as a potential gas well. A number of potential development locations have been identified on this prospect.

The Company is currently estimating that its capital program will total approximately $27 million, down from the previous forecast of $30 million. Industry partners remain uncertain on natural gas prices and costs and therefore previous projected drilling plans have been delayed until the economic climate for natural gas improves. The Company has plans for 5 more wells prior to year end in its core area.

With the current drilling results, the Company remains confident that its projected 1900 BOE/d exit rate will be achieved.

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, timing of expenditures and renunciation of flow-through expenditures, budgeted capital expenditures and the method of funding thereof, partner risk, expected royalty rates and 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

August 3, 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 six month periods ended June 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 Cinc

PRODUCTION, PRICES, AND COSTS

For the six months ended June 30, 2007, Cinch's production averaged 1,301 BOE/d versus an average of 1,136 BOE/d in the first six months of 2006 and 1,249 BOE/d in the second quarter of 2007. The increase over 2006 is attributable to new production adds in the Chime, Kakwa, and the Resthaven areas. Production in the Bigstone area continued to be curtailed since March 2007, however additional firm processing capacity has now been made available by the operator commencing in August, which should alleviate the restrictions. The Company anticipates that production in the second half of 2007 should increase as new wells are brought on stream in Musreau, Kakwa, Chime, and Dawson West.

Prices for the first six months of 2007 averaged $49.68 per BOE, which is up slightly from the 2006 first half average of $48.12 per BOE. The price received in the second quarter of 2007 decreased slightly from the first quarter to $49.11 per BOE. Natural gas prices in the third quarter of 2007 have softened considerably 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. The company does not have any hedges in place and remains positive about the future natural gas market.

Operating costs in the first half of 2007 were $6.24 per BOE, as compared to $7.37 per BOE in the comparable period of 2007, and down slightly from $6.30 per BOE in the second quarter of 2007. These decreases in operating costs are primarily due to additional production volumes coming on stream.

OPERATIONS

During the second quarter, Cinch operated the drilling of one well at Chime, Alberta.

At Chime, the Company drilled and cased subsequent to quarter end the Chime 9-36 well as a potential gas well. Cinch has a 45% working interest in this well, and has commenced completion operations in three zones, which is expected to take approximately three weeks. A number of follow up locations have been identified and have been surveyed in preparation for future development drilling, which is dependent upon completion results and also securing partner participation.

In the Musreau area, the Company participated in the recompletion operations of Musreau 14-7 The Musreau 14-7 well, in which Cinch has a 50% working interest, was completed as a dual zone gas well and is expected to commence production in early September at a rate of 600 mcf/d.

At Wilder, British Columbia, Cinch had operated the drilling of the Wilder 11-36 well and also the completion of the Wilder A06-5 well in the first quarter. Results from the drilling and completion operations were evaluated in the second quarter and resulted in uneconomic gas rates and the Company has now elected to abandoned the Wilder 11-36 well and not proceed with the drilling option.



At Kakwa, Cinch has drilled the Kakwa 10-18 infill Dunvegan location in which it has a 100% working interest, and cased this well as a potential gas well. This well is expected to commence production in September. The Company is also participating for its 12.5% working interest in the Kakwa 14-23 well which has commenced drilling.

At Kakwa East, the tie in operations of the Kakwa 15-12 oil discovery has now been delayed until January of 2008 which is anticipated to significantly reduce the Company's share of tie in costs, as the length of the pipeline will be reduced and costs will now be shared with offsetting operators. This will also delay the drilling of two budgeted development wells into the 2008 year.

At Dawson, B.C., the Doe 1-32 Kiskatinaw test, in which the Company has a 36% working interest, has been cased as a potential gas well. A number of potential development locations have been identified on this prospect.

The Company is currently estimating that its capital program will total approximately $27 million, down from the previous forecast of $30 million. Industry partners remain uncertain on natural gas prices and costs and therefore previous projected drilling plans have been delayed until the economic climate for natural gas improves. The Company has plans for 5 more wells prior to year end in its core area.

With the current drilling results, the Company remains confident that its projected 1900 BOE/d exit rate will be achieved.

George Ongyerth

President h'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 second quarter of 2007 was approximately 1,249 BOE/d, resulting in an average of 1,301 BOE/d for the first six months of 2007, an increase of 165 BOE/d over the same period of 2006. The decrease in production from the first quarter of 2007 is due to additional production of approximately 70 BOE/d being shut-in due to plant capacity issues. There were also declines in production from 3 wells that came on production late in 2006, producing at rates of approximately 60 BOE/d lower in the second quarter of 2007 compared to the first quarter. These reductions were partially offset by production from a well at Resthaven, which increased by approximately 40 BOE/d over the first quarter as a result of having less down-time in the quarter.

Due to an extended spring break up, the Company re-commenced drilling activities in June with the Cutpick 9-36 well. The Wilder test well, which had been drilled late in the first quarter, was assessed in the second quarter as uneconomic.

The Company incurred $3.9 million of capital expenditures in the three months ended June 30, 2007, of which $2.0 million was incurred on an acquisition and the balance on drilling, completion and seismic expenditures, primarily in June. The acquisition, in the Company's core Chime area, consolidated additional land interests and additional working interests in two producing wells, as well as eliminated a gross overriding royalty effective June 20, 2007.

In the third quarter of 2007, the Company plans to drill, complete and tie-in multiple locations primarily in the Chime, Kakwa and Dawson areas, including the Cutpick 9-36 well.

The Company's funds from operations and funds from operations per share for the first six months of 2007 exceeded that of the same period of 2006, as a result of the higher production and higher prices.

PRODUCTION



-------------------------------------------------------------------------
Three Months Ended June 30, Six Months Ended June 30,
2007 2006 Change 2007 2006 Change
-------------------------------------------------------------------------
Sales volumes % %
Natural gas (mcf/d) 6,157 5,723 8 6,472 5,685 14
Liquids (bbl/d) 223 187 19 222 182 18
Equivalence (BOE/d) 1,249 1,141 9 1,301 1,136 15

Sales prices $ $ % $ $ %
Natural gas 7.75 6.64 17 7.90 7.42 6
Liquids 61.15 72.30 (15) 60.84 66.25 (8)
Equivalence 49.11 45.19 9 49.68 48.12 3
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Sales volumes for the three and six months ended June 30, 2007, increased over the same periods of 2006 due to six additional wells brought on production since June 2006, partially offset by declines. The most significant well, which commenced production subsequent to June 30, 2006, was the Resthaven 9-25 well, averaging approximately 180 BOE/d and 160 BOE/d for the three and six months ended June 30, 2007, respectively.

Natural gas prices were 17% higher and 6% higher for the three and six months ended June 30, 2007, respectively, compared to the same periods of 2006. Natural gas prices for the three months ended June 30, 2007 were 3% lower than the first quarter of 2007. Natural gas pricing continued to weaken 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 15% lower and 8% lower for the three and six months ended June 30, 2007, respectively, compared to the same periods of 2006. Natural gas liquids pricing was 1% higher in the second quarter compared to the first quarter of 2007. Natural gas liquids represent approximately 18% 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
-------------------------------------------------------------------------
Three Months Ended June 30, Six Months Ended June 30,
2007 2006 Change 2007 2006 Change
-------------------------------------------------------------------------
$ $ % $ $ %

Oil and gas sales,
net of
transportation 5,582 4,692 19 11,698 9,892 18
Per BOE 49.11 45.19 9 49.68 48.12 3
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Revenues for the three and six months ended June 30, 2007 were 19% and 18% higher, respectively, than the same periods of 2006 due to higher production as well as higher natural gas prices partially offset by lower natural gas liquids prices, as previously discussed. Transportation expenses increased by approximately $0.28 per BOE in the first six months of 2007 compared to the same period of 2006 as a result of rate increases.

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

ROYALTIES



Dollars in thousands, except per unit amounts
-------------------------------------------------------------------------
Three Months Ended June 30, Six Months Ended June 30,
2007 2006 Change 2007 2006 Change
-------------------------------------------------------------------------
$ $ % $ $ %

Royalties, net of
ARTC 1,397 744 88 2,396 2,037 18
Per BOE 12.30 7.16 72 10.18 9.91 3
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Royalty expense increased in the three and six months ended June 30, 2007 compared to the same periods of 2006 due to the elimination of the Alberta royalty tax credit effective January 1, 2007. The benefit received for the three and six months ended June 30, 2006 was $160 thousand and $500 thousand, respectively, which directly offset crown royalty expense in 2006. The royalty expense is also higher in 2007 because oil and gas sales are higher and because of the expiration of royalty holidays.

Royalty expense for the second quarter of 2007 increased over the first quarter of 2007 due to the exhaustion of royalty holidays on two of the Company's more significant producing wells. The royalty rate for the remainder of 2007 (royalties as a percentage of oil and gas sales), is not expected to change substantially from the royalty rate experienced in the second quarter. Royalty rates can vary from expectations, 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 June 30, Six Months Ended June 30,
2007 2006 Change 2007 2006 Change
-------------------------------------------------------------------------
$ $ % $ $ %

Operating 716 750 (5) 1,469 1,515 (3)
Per BOE 6.30 7.22 (13) 6.24 7.37 (15)
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Total operating expenses for the three and six months ended June 30, 2007 were slightly lower than operating expenses for the same periods of 2006. Operating expenses per BOE decreased compared to the same periods of 2006 due to slightly lower operating expenses over higher production.

Total operating expenses for the second quarter of 2007 were slightly lower than the first quarter of 2007, with decreases in gas gathering and processing fees due to lower production, as well as decreased compressor maintenance and repairs and contractor services, partially offset by increased EUB administrative charges, property taxes and chemical treating costs. Operating expenses per BOE are slightly higher than those experienced in the first quarter of 2007 at $6.18/BOE due to lower production levels in the second quarter.

Operating expenses are not expected to exceed $6.50 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
-------------------------------------------------------------------------
Three Months Ended June 30, Six Months Ended June 30,
2007 2006 Change 2007 2006 Change
-------------------------------------------------------------------------
$ $ % $ $ %

General and
administrative 950 995 (5) 2,021 1,857 9
Per BOE 8.36 9.59 (13) 8.58 9.03 (5)
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Total general and administrative expenses decreased for the three months ended June 30, 2007 compared to the same period of 2006 due to decreased contractor and consultant fees, as well as lower expenses relating to corporate governance. Overhead recoveries were also higher due to a change in the mix of operated versus non-operated activities. The decreases are partially offset by a slight increase in salaries and related compensation ($30 thousand). The Company does not capitalize indirect general and administrative expenses. General and administrative expenses per BOE were lower in the second quarter of 2007 compared to the prior year due to lower general and administrative expenses over higher production in 2007.

Total general and administrative expenses for the six months ended June 30, 2007 increased over the same period of 2006 due to increased salaries and related compensation. This amount includes an increase in non-cash stock based compensation expense of $110 thousand, attributable to a greater number of stock options outstanding (5,110,500 options at June 30, 2007 compared to 3,364,000 options at June 30, 2006). Overhead recoveries were also $32 thousand lower in 2007 due to reduced operated activity from 2006.

Total general and administrative expenses decreased approximately $121 thousand in the second quarter of 2007 compared to the first quarter of 2007 mostly due to increased overhead recoveries ($45k), as well as lower stock based compensation expense. General and administrative expenses per BOE were lower in the second quarter of 2007 compared to the first quarter at $8.79/BOE due to lower expenses partially offset by lower production in the second quarter.

INTEREST EXPENSE



Dollars in thousands, except per unit amounts
-------------------------------------------------------------------------
Three Months Ended June 30, Six Months Ended June 30,
2007 2006 Change 2007 2006 Change
-------------------------------------------------------------------------
$ $ % $ $ %

Interest expense 196 133 47 426 138 209
Per BOE 1.73 1.28 35 1.81 0.67 170
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Interest expense increased in the three and six months ended June 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 $14.2 million. In 2006, the Company did not draw on its operating line until April 2006 and exited the quarter with an amount outstanding under its credit facility of $6.4 million.

ACCRETION OF ASSET RETIREMENT OBLIGATIONS EXPENSE



Dollars in thousands, except per unit amounts
-------------------------------------------------------------------------
Three Months Ended June 30, Six Months Ended June 30,
2007 2006 Change 2007 2006 Change
-------------------------------------------------------------------------
$ $ % $ $ %

Accretion expense 44 19 132 85 28 204
Per BOE 0.39 0.18 117 0.36 0.14 157
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Accretion expense increased in the three and six months ended June 30, 2007 compared to the same periods of 2006 due to an increase in the number of wells with asset retirement obligations as a result of drilling operations and due to 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 June 30, Six Months Ended June 30,
2007 2006 Change 2007 2006 Change
-------------------------------------------------------------------------
$ $ % $ $ %

Depletion and
depreciation 3,189 2,490 28 6,495 4,996 30
Per BOE 28.05 23.98 17 27.58 24.31 13
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Total depletion and depreciation expense as well as depletion per BOE for the three and six months ended June 30, 2007 increased compared to the same periods of 2006 due to a larger capital asset balance being depleted, partially offset by reserve additions since June 30, 2006. The Company has internally assessed reserve additions to June 30, 2007 and, given the capital expended, this has resulted in a higher depletion rate in the six months ended June 30, 2007 at $27.58 versus the fourth quarter of 2006 at $26.71. The variance is largely attributable to the $2.6 million Wilder exploration test in British Columbia, which was unsuccessful and resulted in no reserve additions.

TAXES



Dollars in thousands, except per unit amounts
-------------------------------------------------------------------------
Three Months Ended June 30, Six Months Ended June 30,
2007 2006 Change 2007 2006 Change
-------------------------------------------------------------------------
$ $ % $ $ %

Current - (20) (100) - - -
Future income tax
recoveries (192) (1,239) (85) (183) (1,320) (86)
Per BOE (1.69) (12.13) (86) (0.78) (6.42) (88)
-------------------------------------------------------------------------
-------------------------------------------------------------------------


There was no large corporations tax paid in the three months ended June 30, 2007, consistent with the elimination of the large corporations tax effective January 1, 2006, which became law on June 22, 2006. The second quarter of 2006 reflected a reversal of large corporations taxes previously recorded after the legislation eliminating the tax became law.

A future income tax recovery was recorded in the second quarter of 2007 because the Company experienced a net loss. Stock compensation expense recorded in the quarter is not included in calculating the future tax recovery as this expense is non-taxable. The second quarter of 2006 was 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. 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 being recorded in the quarter.

Tax pools at June 30:



In thousands
-------------------------------------------------------------------------
2007 2006
$ $
-------------------------------------------------------------------------
COGPE 13,773 12,220
CDE 21,101 19,006
CEE 25,471 12,185
UCC 19,840 19,842
-------------------------------------------------------------------------
80,185 63,253
-------------------------------------------------------------------------
-------------------------------------------------------------------------


The Company's tax pools increased by 26% since June 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
-------------------------------------------------------------------------
Three Months Ended June 30, Six Months Ended June 30,
2007 2006 Change 2007 2006 Change
-------------------------------------------------------------------------
$ $ % $ $ %

Net income (loss) (709) 879 (181) (978) 748 (231)
per basic share (0.01) 0.02 (150) (0.02) 0.02 (200)
per diluted share (0.01) 0.02 (150) (0.02) 0.02 (200)
Funds from
operations 2,589 2,406 8 5,960 4,881 22
per basic share 0.06 0.05 20 0.11 0.10 8
per diluted share 0.06 0.05 20 0.11 0.10 11
Weighted average
shares & special
warrants
outstanding 55,570 47,813 12 53,326 47,813 12
-------------------------------------------------------------------------
-------------------------------------------------------------------------


For the three and six months ended June 30, 2007, the Company incurred a net loss, attributable to higher royalties, as well as higher depletion and depreciation and interest expense partially offset by higher revenues and lower operating expenses.

The Company's funds from operations increased by 8% and 22% over the three and six months ended June 30, 2006, respectively. Funds from operations in 2007 are higher primarily due to increased revenues from higher production levels.

LIQUIDITY AND CAPITAL RESOURCES



In thousands
-------------------------------------------------------------------------
June 30, December 31,
2007 2006 Change
-------------------------------------------------------------------------
$ $ %

Working capital (deficiency) 4,496 6,441 (30)
Credit facility 14,177 17,304 (18)
-------------------------------------------------------------------------
Net debt 18,673 23,745 (21)
Long-term capital lease obligation 139 277 (50)
Shareholders' equity 99,700 90,551 10
-------------------------------------------------------------------------
-------------------------------------------------------------------------


At June 30, 2007, the Company had net debt of $18.7 million, comprised of a working capital deficiency of $4.5 million and an amount outstanding on its credit facility of $14.2 million. The $5.1 million reduction in net debt from December 31, 2006 can be attributed to 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 six months ended June 30, 2007 of $5.9 million, partially offset by capital expenditures incurred in the first half of 2007 of $10.2 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 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. The Company has reduced its previous capital forecast of $30 million to $27 million in consideration of the lower natural gas prices. At June 30, 2007, the Company had draws of $14.2 million on its $33.0 million demand bank credit facility, which was renewed during the second quarter with no changes in the facility terms.

The increase in shareholders' equity at June 30, 2007 from December 31, 2006 is due to the financing completed in February 2007, as previously discussed.

CAPITAL EXPENDITURES

Additions to property, plant and equipment



In thousands
-------------------------------------------------------------------------
Six months ended June 30,
2007 2006
-------------------------------------------------------------------------
$ $

Land and rentals 1,964 5,315
Seismic 267 608
Drilling, completing and equipping 6,847 10,336
Pipelines and facilities 992 3,852
Other assets 88 127
-------------------------------------------------------------------------
Total 10,158 20,238
-------------------------------------------------------------------------
-------------------------------------------------------------------------


The capital additions for the six months ended June 30, 2007 include approximately $2.0 million for an acquisition which consolidated additional land interests and eliminated a gross overriding royalty effective June 20, 2007. The remainder of the capital expenditures were incurred primarily on drilling and completing locations in the Kakwa East, Wilder, Musreau and Chime areas. As previously mentioned, a total of $2.6 million was expended on the Wilder test, a new prospect in British Columbia, however this did not prove successful. Additional reserves were added through drilling and completion operations at the Musreau and Kakwa East areas. The Chime (Cutpick 9-36-60-06W6) location was in progress at the end of the quarter. Subsequent to quarter end, the Company cased the Cutpick 9-36 well, in which it has a 45% working interest, and the well is currently being evaluated for a multiple zone completion. Currently, the Company has three wells at various stages of drilling and completion.

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.

On February 16, 2007, the Alberta Government announced that a review of the province's royalty and tax regime pertaining to oil and gas resources, including oil sands, conventional oil and gas and coalbed methane, will be conducted by a panel of experts, with the assistance of individual Albertans and key stakeholders. The review panel is to produce a final report that will be presented to the Minister of Finance by August 31, 2007.

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.

On March 8, 2007, the Alberta Government introduced Bill 3, the Climate Change and Emissions Management Amendment Act, which intends to reduce greenhouse gas emission intensity from large industries. 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.

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 statements 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 June 30, 2007, that have materially affected, or are reasonably likely to affect, the Company's design of the internal controls over financial reporting.

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 years 4-5 years 5 years
-------------------------------------------------------------------------

Capital lease
obligation 415 276 139 - -
Operating lease 421 174 247 - -
-------------------------------------------------------------------------
836 450 386 - -
-------------------------------------------------------------------------
-------------------------------------------------------------------------


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 six months ended June 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. We are currently assessing the impact of these new standards on our 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, and anticipates tieing-in production in the second half of 2007. Some of the challenges encountered in 2006 such as rig availability have been alleviated with the softening of the oil and gas market experienced in the latter part of 2006 and early 2007. The Company has not experienced problems obtaining rigs in 2007 and does not anticipate challenges in obtaining rigs for the remainder of 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, depending on individual views of what constitutes short term versus long term price variations. 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 commodity 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 softening market, anticipated to continue at least in the near term, has impacted the Company's capital spending as well, which is approximately half of what it was for the same period in 2006, as partner willingness to participate in projects is reduced or delayed and as access to capital becomes more challenging. The Company continually monitors capital spending and assesses the risk of each individual project to ensure that funds are prioritized appropriately.

For the third quarter of 2007, natural gas prices are expected to continue to remain weak, which could make access to capital through internal and external sources increasingly challenging. The natural gas prices in the fourth quarter are expected to strengthen as winter demands increase. 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.

Overall, management does believe in the long term strength of the natural gas market, despite what we consider to be short term fluctuations and volatility.



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
Funds from operations 3,371 2,589
Per share - basic 0.07 0.05
- diluted 0.06 0.05
Net income (loss) (268) (709)
Per share - basic (0.01) (0.01)
- diluted (0.01) (0.01)
Capital expenditures 6,228 3,930
Total assets 136,520 134,834
Working capital
(net debt)(1) (17,264) (18,673)
-------------------------------------------------------------------------
Production (BOE/d) 1,354 1,249
-------------------------------------------------------------------------
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 (June 30, 2007 - $138,911, December 31, 2006 -
$276,806, December 31, 2005 - $420,988, December 31, 2004 -
$620,764).



Financial Statements

Cinch Energy Corp.
June 30, 2007
(unaudited)



CINCH ENERGY CORP.

BALANCE SHEETS
(unaudited)

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

ASSETS (notes 4 and 5)

Current
Accounts receivable 3,193,732 9,107,635
Prepaid expenses and deposits 779,983 957,338
-------------------------------------------------------------------------
3,973,715 10,064,973

Property, plant and equipment (note 3) 116,243,671 112,301,421

Goodwill 14,616,996 14,616,996
-------------------------------------------------------------------------
134,834,382 136,983,390
-------------------------------------------------------------------------
-------------------------------------------------------------------------

LIABILITIES AND SHAREHOLDERS' EQUITY

Current
Accounts payable and accrued liabilities 8,194,310 16,229,842
Credit facility (note 4) 14,177,058 17,304,333
Current portion of capital lease
obligation (note 5) 275,789 275,789
-------------------------------------------------------------------------
22,647,157 33,809,964

Capital lease obligation (note 5) 138,911 276,806

Asset retirement obligations (note 6) 3,299,020 2,934,899

Future income taxes (note 7) 9,049,300 9,410,600
-------------------------------------------------------------------------
35,134,388 46,432,269
-------------------------------------------------------------------------

Commitments (notes 8 and 9)

Shareholders' equity
Share capital (note 8) 99,204,634 89,618,546
Contributed surplus (note 8) 2,684,946 2,144,649
Deficit (2,189,586) (1,212,074)
-------------------------------------------------------------------------
99,699,994 90,551,121
-------------------------------------------------------------------------

134,834,382 136,983,390
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes



CINCH ENERGY CORP.

STATEMENTS OF OPERATIONS, COMPREHENSIVE INCOME (LOSS) AND DEFICIT
(unaudited)

Three months ended Six months ended
June 30, June 30,

2007 2006 2007 2006
-------------------------------------------------------------------------
$ $ $ $
Revenue
Oil and gas sales 5,840,095 4,881,952 12,195,966 10,268,036
Transportation (258,326) (190,431) (497,847) (376,052)
Royalties (1,397,479) (743,594) (2,396,354) (2,037,152)
Other income 8,983 58,574 33,310 107,496
-------------------------------------------------------------------------
4,193,273 4,006,501 9,335,075 7,962,328
-------------------------------------------------------------------------

Expenses
Operating 715,679 749,842 1,468,743 1,515,066
General and
administrative (note 8) 950,230 995,249 2,020,745 1,856,721
Interest on credit
facility 188,952 125,509 411,476 125,552
Interest on capital
lease (note 5) 7,267 7,266 14,533 12,806
Accretion of asset
retirement obligations
(note 6) 43,816 18,873 85,284 28,076
Depletion and
depreciation 3,188,870 2,490,061 6,494,906 4,995,891
-------------------------------------------------------------------------
5,094,814 4,386,800 10,495,687 8,534,112
-------------------------------------------------------------------------

Loss before income
taxes (901,541) (380,299) (1,160,612) (571,784)
-------------------------------------------------------------------------

Taxes (note 7)
Current - (20,280) - -
Future income tax
recovery (192,200) (1,238,800) (183,100) (1,319,900)
-------------------------------------------------------------------------

(192,200) (1,259,080) (183,100) (1,319,900)
-------------------------------------------------------------------------

Net income (loss) and
comprehensive income
(loss) for the period
(note 2) (709,341) 878,781 (977,512) 748,116

Deficit, beginning
of period (1,480,245) (1,026,204) (1,212,074) (895,539)
-------------------------------------------------------------------------

Deficit, end of period (2,189,586) (147,423) (2,189,586) (147,423)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Net income (loss) and
comprehensive income
(loss) for the period
per share (note 8)
Basic and diluted (0.01) 0.02 (0.02) 0.02
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes



CINCH ENERGY CORP.

STATEMENTS OF CASH FLOWS
(unaudited)

Three months ended Six months ended
June 30, June 30,

2007 2006 2007 2006
-------------------------------------------------------------------------
$ $ $ $
Operating activities
Net income (loss) for
the period (709,341) 878,781 (977,512) 748,116
Add non-cash items:
Depletion and
depreciation 3,188,870 2,490,061 6,494,906 4,995,891
Accretion of asset
retirement
obligations 43,816 18,873 85,284 28,076
Non-cash compensation
expense (note 8) 258,136 257,120 540,297 428,606
Future income tax
recovery (192,200) (1,238,800) (183,100) (1,319,900)
-------------------------------------------------------------------------
2,589,281 2,406,035 5,959,875 4,880,789
Net change in non-cash
working capital 811,220 (2,351,128) 954,214 (2,032,914)
-------------------------------------------------------------------------
Cash provided by
operating activities 3,400,501 54,907 6,914,089 2,847,875
-------------------------------------------------------------------------

Investing activities
Additions to property,
plant and equipment (3,930,092) (13,541,975) (10,158,319) (20,238,167)
Net change in non-cash
working capital (716,282) 5,705,326 (2,984,083) 5,306,873
-------------------------------------------------------------------------
Cash used in investing
activities (4,646,374) (7,836,649) (13,142,402) (14,931,294)
-------------------------------------------------------------------------

Financing activities
Increase (decrease) in
credit facility 1,393,406 6,379,432 (3,127,275) 6,379,432
Issue of common shares,
net of issue costs - (32,092) 9,407,888 (68,391)
Proceeds from (payments
on) capital lease (68,947) 112,056 (137,894) 59,494
Net change in non-cash
working capital (78,586) 29,073 85,594 58,290
-------------------------------------------------------------------------
Cash provided by (used
in) financing
activities 1,245,873 6,488,469 6,228,313 6,428,825
-------------------------------------------------------------------------

Decrease in cash - (1,293,273) - (5,654,594)

Cash and cash equivalents,
beginning of period - 1,293,273 - 5,654,594
-------------------------------------------------------------------------

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

Supplemental information:
Cash taxes paid - (40,676) - -
Cash interest paid 190,194 132,775 382,435 138,358
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes



CINCH ENERGY CORP.

NOTES TO FINANCIAL STATEMENTS

June 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 shareholders' 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

June 30, 2007
-------------------------------------------------------------------------
Accumulated
depletion and Net book
Cost depreciation value
$ $ $
-------------------------------------------------------------------------
Petroleum and natural gas
properties 151,653,629 (36,317,784) 115,335,845
Equipment under capital lease 1,020,307 (238,944) 781,363
Office furniture and equipment 305,850 (179,387) 126,463
-------------------------------------------------------------------------

152,979,786 (36,736,115) 116,243,671
-------------------------------------------------------------------------
-------------------------------------------------------------------------


December 31, 2006
-------------------------------------------------------------------------
Accumulated
depletion and Net book
Cost depreciation 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 six month period ended June 30, 2007 and for the year
ended December 31, 2006, no indirect general and administrative
expenditures were capitalized.

As at June 30, 2007, $11,493,322 of costs related to undeveloped lands
were excluded from costs subject to depletion (December 31, 2006 -
$10,900,069). For the three months ended June 30, 2007, the depletion
calculation included future development costs of $1,861,500 (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. CREDIT FACILITY

As at June 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 at
June 30, 2007 was 5.7% (June 30, 2006 - 5.9%). The interest rate realized
in the first half of 2007 is lower than the prime rate due to drawings on
guaranteed notes, which bear a lower interest rate. As at June 30, 2007,
there was $14,177,058 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 5).

5. CAPITAL LEASE OBLIGATION

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

Years ending December 31, $
-------------------------------------------------------------------------
2007 152,427
2008 304,855
-------------------------------------------------------------------------

Total minimum lease payments 457,282

Less amounts representing interest at 5.12% (42,582)
-------------------------------------------------------------------------

Present value of minimum lease payments 414,700

Less current portion (275,789)
-------------------------------------------------------------------------

Capital lease obligation at June 30, 2007 138,911
-------------------------------------------------------------------------
-------------------------------------------------------------------------

During the three and six month periods ended June 30, 2007, there was
$7,267 and $14,533, respectively, (2006 - $7,266 and $12,806,
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.

6. 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 June 30, 2007 is approximately
$5,690,000 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 $3,299,020 at June 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 278,837
Accretion expense 85,284
-------------------------------------------------------------------------

Asset retirement obligations, as at June 30, 2007 3,299,020
-------------------------------------------------------------------------
-------------------------------------------------------------------------

7. 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 Six months ended
June 30, June 30,
2007 2006 2007 2006
-------------------------------------------------------------------------

Statutory income tax rate 32.12% 34.49% 32.12% 34.49%

$ $ $ $
Anticipated income
tax recovery (289,575) (129,002) (372,789) (197,209)
Increase/(decrease)
resulting from:
Resource allowance - (96,093) - (216,860)
Non-deductible crown
royalties, net of ARTC - (3,149) - 39,551
Rate adjustment 15,830 (1,099,270) 17,514 (1,095,179)
Stock based
compensation expense 82,913 86,743 173,543 147,826
Other (1,368) 1,971 (1,368) 1,971
-------------------------------------------------------------------------

Future income tax recovery (192,200) (1,238,800) (183,100) (1,319,900)
-------------------------------------------------------------------------

Large corporations tax
(recovery) - (20,280) - -
-------------------------------------------------------------------------
-------------------------------------------------------------------------

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:

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

Net book value of capital assets
in excess of tax pools (10,821,660) (11,051,577)
Share issue costs 666,811 649,182
Asset retirement obligations 996,304 886,339
Other 109,245 105,456
-------------------------------------------------------------------------

Future income tax liability (9,049,300) (9,410,600)
-------------------------------------------------------------------------
-------------------------------------------------------------------------

8. 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) - (413,912)
-------------------------------------------------------------------------
Balance, as at June 30, 2007 55,625,132 99,204,634
-------------------------------------------------------------------------
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 June 30, 2007 - -
-------------------------------------------------------------------------
Share capital, as at June 30, 2007 55,625,132 99,204,634
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Contributed surplus
Balance, as at December 31, 2006 2,144,649
Non cash compensation expense (iii) 540,297
-------------------------------------------------------------------------
Contributed surplus, as at June 30, 2007 2,684,946
-------------------------------------------------------------------------
-------------------------------------------------------------------------

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 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.

(ii) Exercise of special warrants

During the six months ended June 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
June 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 six months ended June 30, 2007 of 55,570,132 and 53,325,657,
respectively. (June 30, 2006 - 47,812,632 and 47,812,632, respectively).
As at June 30, 2007, all of the stock options are anti-dilutive and
therefore not included in the determination of dilutive per share
amounts. Per share amounts that are anti-dilutive are based on
3,178,000 outstanding, out-of-the-money options and
4,063,000 outstanding, out-of-the-money options for the three and six
months ended June 30, 2007, respectively.

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:

June 30, 2007 June 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 1,036,000 2.24
Cancelled (33,334) 2.05 - -
-------------------------------------------------------------------------
Stock options outstanding,
end of period 5,110,500 1.76 3,364,000 2.19
-------------------------------------------------------------------------
-------------------------------------------------------------------------

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

June 30, 2007
-------------------------------------------------------------------------
Exercisable options
-------------------
Weighted
Exercise Number of Number of average
Price Options Options price
-------------------------------------------------------------------------
$ $

1.00-1.50 1,957,500 - -
1.51-2.00 1,338,000 895,665 1.86
2.01-2.50 1,110,000 451,663 2.22
2.51-3.00 580,000 351,997 2.53
3.01-3.50 125,000 41,667 3.30
-------------------------------------------------------------------------
1.76 5,110,500 1,740,992 2.12
-------------------------------------------------------------------------
-------------------------------------------------------------------------


June 30, 2006
-------------------------------------------------------------------------
Exercisable options
-------------------

Weighted
Exercise Number of Number of average
Price Options Options price
-------------------------------------------------------------------------
$ $

1.00-1.50 - - -
1.51-2.00 1,328,000 710,000 1.87
2.01-2.50 1,231,000 101,666 2.22
2.51-3.00 680,000 185,332 2.52
3.01-3.50 125,000 - -
-------------------------------------------------------------------------
2.19 3,364,000 996,998 2.03
-------------------------------------------------------------------------
-------------------------------------------------------------------------

The options outstanding at June 30, 2007 have a weighted average
remaining contractual life of 3.4 years (June 30, 2006 - 3.7 years).

The fair value of stock options granted to employees, directors and
consultants during the six month periods ended June 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 - 46%), risk-free
interest rate of 3.93% (2006 - 4.05%), and an expected life of four years
(2006 - four years). Outstanding options granted during the six month
period ended June 30, 2007 had an estimated weighted average fair value
of $0.44 per option (2006 - $0.91 per option), for a total estimated
value of $466,425 (2006 - $944,950). For the three and six month periods
ended June 30, 2007, a total of $258,136 and $540,297, respectively,
(2006 - $257,120 and $428,606, respectively,) has been recognized as
stock compensation expense in general and administrative expenses with an
offsetting credit to contributed surplus.

9. 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 5.

10. 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 June 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 June 30, 2007, the Company had no fixed price contracts associated
with future production.

11. BASIS OF PRESENTATION

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


Contact Information