Cinch Energy Corp.
TSX : CNH

Cinch Energy Corp.

August 09, 2006 23:59 ET

Cinch Energy Corp. Releases Second Quarter 2006 Results



CALGARY--(CCNMatthews - Aug. 9) - Cinch Energy Corp. ("Cinch" or "the Company") is pleased to report on the Company's activities and financial results during the second quarter of 2006. Highlights are as follows:



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Three Months Ended Six Months Ended
June 30, June 30,
2006 2005 2006 2005
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Petroleum and natural gas sales,
net of transportation ($000's) 4,692 5,821 9,892 11,883
Production per day
Natural gas (Mcf/d) 5,723 6,315 5,685 6,719
Natural gas liquids (Bbl/d) 175 211 182 222
Equivalence at 6:1 (BOE/d) 1,141 1,264 1,136 1,342

Sales Price
Natural gas ($/Mcf) 6.64 8.17 7.42 7.92
Natural gas liquids ($/Bbl) 72.62 58.59 66.21 56.06
Equivalence at 6:1 ($/BOE) 47.02 50.63 48.13 48.93

$ $ $ $
Funds from operations (000's)(1) 2,406 3,037 4,881 6,235
- per share, basic(1) 0.05 0.09 0.10 0.18
- per share, diluted(1) 0.05 0.08 0.10 0.17
Net income (000's) 879 537 748 1,149
- per share, basic 0.02 0.01 0.02 0.03
- per share, diluted 0.02 0.01 0.02 0.03

Capital expenditures ($000's) 13,542 8,116 20,238 14,497

Basic weighted average shares
outstanding (000's) 47,813 35,511 47,813 34,484
Working capital (net debt)(2)
($000's)
- As at June 30, 2006 (11,942)
- As at December 31, 2005 3,490

As at
August 4, 2006

Common Shares and Special Warrants outstanding 47,812,632
Options outstanding 3,202,334
- average exercise price 2.19
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(1) Funds from operations is a non-GAAP measure and represents net income
before depletion, depreciation, non-cash compensation, future taxes
and any other non-cash expenses related to the Company's operations.
(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, 2006, Cinch's production averaged 1,136 BOE/d and averaged 1,141 BOE/d in second quarter of 2006. Results are consistent with the Company's forecast, in which the Company was projecting production to remain fairly constant in the first six months of 2006 and increase in the third quarter as new production was added. High activity levels in the Musreau and Kakwa areas continue to place pressure on infrastructure in the area, and although additional capacity is expected to be added this year, the lack of available capacity has impacted new and existing well production. Our production at Bigstone was shut-in late in the first quarter as the plant is being fully utilized by operators with firm service at the plant. This has continued to be an issue and this production is now projected to recommence in November. Currently, the Company has approximately 630 BOE/d behind pipe, with over 50% of this production projected to come on stream in the third quarter. The Company anticipates that 2006 production should average 1,300 BOE/d and the exit rate is forecast to range between 1,600 and 1,800 BOE/d.

Prices for the first six months of 2006 averaged $48.13 per BOE and were $47.02 per BOE in the second quarter of 2006, which was down from $51.13 per BOE in the first quarter. Despite the weakness shown in the natural gas markets in the second quarter, the Company remains positive about the natural gas market in the long term. Most recently the natural gas markets have shown a slight strengthening due to a heat wave experienced in North America.

Operating costs were slightly lower in the second quarter of 2006 at $7.22 per BOE compared to $7.52 in the first quarter. We have generally experienced higher costs in 2006 as compared to 2005, in part as a result of the issues encountered with the production and related compression costs, the higher well count, and the higher number of employees that we now have.

OPERATIONS

During the second quarter, Cinch participated in two wells, both of which were cased as potential gas wells.

In the Musreau area, the Company participated in the drilling of Musreau 14-7 in which it has a 18.83% working interest. This well was cased as a potential gas well, with completion operations expected to commence in the third quarter.

At Kakwa, Cinch operated the drilling of the Kakwa 4-30 well in which the Company has a 50% working interest. This well was cased as a potential gas well and should be completed in the third quarter.

At the time of this release, the Company is operating the drilling of three wells, all being drilled to the Nikanassin zone at approximately 3,350 metres. Cinch has a 42.72% interest in the Chime 14-30 well, a 50% interest in the Kakwa 13-13 well, and a 45% interest in the Smoky 12-24 well, the latter located on our Chime East acreage. After the completion of the drilling of Kakwa 13-13, it is expected that the rig will move to the Chime 12-6 location, which is also being drilled as a Nikanassin test.

Management is pleased that rig availability in the industry has improved and that the Company has been able to commence drilling on several of its planned locations. The Company expects to be utilizing at least one drilling rig on its core properties throughout the year.

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, production estimates and expected production rates, timing of recommencement of operations after spring breakup, timing of bringing on additional productive capacity, timing of drilling, completion and tie-in of wells and the effect of delays in drilling, completing and tieing-in wells and the effects of third party compressor issues and other infrastructure issues, levels of decline rates and the effects thereof, expected royalty rates, forecasted unit metrics, general and administrative expenses and other expenses, effects of the results of successful wells, level of capital expenditures and the method of funding of capital expenditures, the ability to incur qualifying expenditures renounceable to purchasers of flow-through shares and the expected levels of activities, the effects of the acquisitions by the Company and results of operations of the Company 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, loss of markets, volatility of commodity prices, imprecision of reserve estimates, environmental risks, competition from other producers, inability to retain drilling rigs and other services, 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. 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 reserves and volumes contained herein 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 4, 2006

The following management's discussion and analysis ("MD&A") is provided by management as of, and is dated, August 4, 2006. It should be read in conjunction with the unaudited interim financial statements and related notes for the three and six month period ended June 30, 2006 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, 2005. 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's determination of funds from operations may not be comparable to that reported by other companies. The reconciliation between net income and funds from operations can be found in the Statements of Cash Flows included in the financial statements noted above. 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 Company considers funds from operations to be a key measure that demonstrates ability to generate funds for future growth through capital investment.

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

For the first half of 2006, the Company focused on its capital program primarily in the Chime, Kakwa and Musreau areas. Our planned program for the second quarter of 2006 consisted of drilling new locations and completing and tieing in locations drilled in the first quarter of 2006, working around spring break-up. During the second quarter of 2006, the Company contracted a drilling rig for one year to assist in minimizing issues experienced in the past with rig availability. In addition, with the softening of natural gas prices, industry activity levels have declined and an increased number of rigs are now available, which the Company anticipates will allow it to execute its planned drilling program in the upcoming quarter, weather permitting.

Production levels remained stable in the second quarter of 2006 with minimal declines in the Company's existing production base. Two additional wells were tied in during the second quarter of 2006 and commenced production in the last week of the quarter.

Plant capacity at Bigstone continues to be fully utilized by other parties and production processed at the plant on an interruptible basis is still shut in. Our Bigstone production of approximately 140 BOE/d was shut in for the entire second quarter. We had originally anticipated that this production would re-commence in the third quarter; however most recent communications from the plant operator indicate that our production is now anticipated to re-commence late in the fourth quarter. The Company is also anticipating infrastructure issues related to plant capacities in the third quarter of 2006 on our non-operated wells in the Musreau/Kakwa areas, which could impact their production rates in that period. The well and plant operators are working on solutions to alleviate the situation.

The impact to Cinch production from the above noted Bigstone production shut-ins was partially offset by two acquisitions completed in April 2006. The Company acquired additional working interests in 7 producing natural gas wells in the Chime area for approximately $7.75 million (net) after selling the undeveloped land thereon, providing approximately 145 BOE/d of production for the second quarter of 2006.

Although increased activity levels in the areas in which the Company is active has placed pressure on infrastructure and ultimately resulted in ongoing operational issues for the Company, steps are being taken to alleviate these issues by infrastructure operators.

The remainder of the Company's 2006 planned drilling program is anticipated to be funded with a combination of funds generated from operations as well as from its $33 million credit facility.



PRODUCTION
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Three Months Ended Six Months Ended
June 30, June 30,
2006 2005 Change 2006 2005 Change
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Sales volumes $ $ % $ $ %
Natural gas (mcf/d) 5,723 6,315 (9) 5,685 6,719 (15)
Liquids (bbl/d) 175 211 (17) 182 222 (18)
Equivalence (BOE/d) 1,141 1,264 (10) 1,136 1,342 (15)

Sales prices $ $ % $ $ %
Natural gas 6.64 8.17 (19) 7.42 7.92 (6)
Liquids 72.62 58.59 24 66.21 56.06 18
Equivalence 47.02 50.63 (7) 48.13 48.93 (2)
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Sales volumes for the three months and six months ended June 30, 2006 versus the comparable periods in 2005 are down as the first six months of 2005 included flush production from wells coming on in late 2004, with the most significant being the Kakwa 16-13 well, averaging 180 BOE/d more in the first six months of 2005 versus the same period of 2006. This high decline in the first year of production is expected of deep, tight gas wells, with the production rate stabilizing over time, providing for a strong production base.

The Company experienced minimal declines in the second quarter of 2006, as decline rates on the Company's existing production base are stabilizing. In the second quarter, Cinch's production at Bigstone of approximately 140 BOE/d was shut in. Two wells tied-in the last week of the second quarter of 2006 will improve production rates in the upcoming quarter; however, this is forecast to be offset by additional anticipated shut-ins on non-operated wells in the Musreau/Kakwa area.

Natural gas prices have continued to decline in the second quarter of 2006 with natural gas prices 19% lower than both the first quarter of 2006 and the comparable period of 2005. The Company's production continues to be unhedged and is marketed in the Alberta spot market.

Natural gas liquids pricing has increased over the prior quarter and has also increased over the comparable period of 2005. The increase in natural gas liquids pricing, although positive, impacts only 15% of our production. The Company has not hedged any of its liquids production.



REVENUES

Dollars in thousands, except per unit amounts
-------------------------------------------------------------------------
Three Months Ended Six Months Ended
June 30, June 30,
2006 2005 Change 2006 2005 Change
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$ $ % $ $ %
Oil and gas sales,
net of transportation 4,692 5,821 (19) 9,892 11,883 (17)
Per BOE 47.02 50.63 (7) 48.13 48.93 (2)
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Revenues during the three and six months ended June 30, 2006 have decreased, compared to the same periods of 2005, as a result of lower production as well as lower natural gas prices, as discussed above.

Revenues for the three months ended June 30, 2006, have also decreased compared to the first quarter of 2006 due to lower natural gas prices offset by slightly higher production.



ROYALTIES

Dollars in thousands, except per unit amounts
-------------------------------------------------------------------------
Three Months Ended Six Months Ended
June 30, June 30,
2006 2005 Change 2006 2005 Change
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$ $ % $ $ %
Royalties, net of ARTC 744 1,273 (42) 2,037 3,032 (33)
Per BOE 7.16 11.07 (35) 9.91 12.49 (21)
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Royalty expense, net of Alberta Royalty Tax Credit ("ARTC"), decreased in the three and six months ended June 30, 2006 compared to the same periods of 2005 as a result of lower production levels and lower commodity prices, and also because a larger percentage of wells are eligible for the Crown Deep Gas Royalty Holiday. Two wells also paid out in the second and third quarters of 2005; hence the Company no longer pays gross overriding royalties on these wells.

The decrease in royalty expense from the first quarter of 2006 is attributable to lower commodity prices, as well as a gas cost allowance adjustment received in the second quarter.

The Company's royalty rate (royalties net of ARTC as a percentage of oil and gas sales) is typically lower in the first half of each year compared to the full year, as ARTC is normally earned in the first and/or second quarters which reduces royalty expense in that period. The royalty rate is expected to increase in the second half of the year now that the maximum ARTC has been earned. The Company anticipates that its royalty rate in 2006 will be slightly lower than that of 2005; however, royalty rates can change 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
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Three Months Ended Six Months Ended
June 30, June 30,
2006 2005 Change 2006 2005 Change
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$ $ % $ $ %
Operating 750 718 4 1,515 1,329 14
Per BOE 7.22 6.24 16 7.37 5.47 35
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Total operating expenses increased in the three and six months ended June 30, 2006, compared to the same period of 2005, due to an additional 16 producing wells and due to increased expenses incurred on compressor maintenance and repairs, chemical and condensate treating costs, wireline services and increased contractor costs associated with the increased activity.

Operating expenses are higher on a per BOE basis in the three and six months ended June 30, 2006 compared to the same period of 2005 as a result of increased costs associated with the increased number of producing wells combined with lower production. For the first six months of 2006, third party gas gathering and processing fees are higher by approximately $0.65/BOE compared to the same period of 2005.

There was minimal variance in operating costs per BOE in the second quarter of 2006 compared to the first quarter of 2006.



GENERAL AND ADMINISTRATIVE EXPENSES

Dollars in thousands, except per unit amounts
-------------------------------------------------------------------------
Three Months Ended Six Months Ended
June 30, June 30,
2006 2005 Change 2006 2005 Change
-------------------------------------------------------------------------
$ $ % $ $ %
General and administrative 995 774 29 1,857 1,213 53
Per BOE 9.59 6.73 42 9.03 5.00 81
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Total general and administrative costs increased in the three and six months ended June 30, 2006 compared to the same period of 2005 due to the hiring of additional employees (4 additional employees in the second quarter of 2006 compared to 2005) and the increased use of contractors and consultants to handle operations, administration and exploration. The Company has expanded its exploration department in order to continue to focus on and accelerate future growth. The Company does not capitalize general and administrative costs. Due to the increased number of employees and the need to remain competitive in the marketplace, salaries and related compensation increased approximately $445 thousand for the six months ended June 30, 2006. This amount includes the increase in non-cash stock based compensation expense of $169 thousand attributable to an increased number of stock options outstanding (2,199,000 options in 2005 to 3,364,000 options in 2006). As at August 4, 2006, the Company has 3,202,334 options outstanding amounting to approximately 6.7% of outstanding shares and special warrants. Operator overhead recoveries were also approximately $55 thousand lower in the first six months of 2006 compared to the same period of 2005 due to delays in drilling activities. Public company related expenses such as annual reports, corporate governance compliance, audit fees, and reserve reports have also increased in 2006. Insurance costs have also increased over the past year which is consistent throughout the industry.

General and administrative expenses per BOE have increased in the three and six months ended June 30, 2006 compared to the same period in 2005 as the higher expense was calculated over lower production, as previously noted.

The increase in total general and administrative costs for the second quarter of 2006 compared to the first quarter is largely due to an increase in stock based compensation of approximately $86,000 relating to options granted in late March 2006, resulting in an increase of $0.83/BOE over the second quarter. Press release costs, filing fees, and charges relating to corporate governance matters were also higher in the second quarter, as were public company related expenses.

The cash costs per BOE for the remainder of 2006 are not expected to exceed $6.00 per BOE. The non-cash stock based compensation expense is expected to average approximately $2.00 per BOE for all of 2006.



INTEREST EXPENSE

Dollars in thousands, except per unit amounts
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Three Months Ended Six Months Ended
June 30, June 30,
2006 2005 Change 2006 2005 Change
-------------------------------------------------------------------------
$ $ % $ $ %
Interest expense 133 163 (18) 138 275 (50)
Per BOE 1.28 1.42 (10) 0.67 1.13 (41)
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Interest expense decreased in the three and six months ended June 30, 2006 when compared to the same periods of 2005, as the Company had lower draws on its bank credit facility in 2006. The Company did not draw on its $33 million bank line until the second quarter of 2006 and exited the quarter with an outstanding credit facility balance of $6,379,432.



ACCRETION OF ASSET RETIREMENT OBLIGATIONS EXPENSE

Dollars in thousands, except per unit amounts
-------------------------------------------------------------------------
Three Months Ended Six Months Ended
June 30, June 30,
2006 2005 Change 2006 2005 Change
-------------------------------------------------------------------------
$ $ % $ $ %
Accretion expense 19 39 (51) 28 71 (61)
Per BOE 0.18 0.34 (47) 0.14 0.29 (52)
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Accretion expense decreased in the three and six months ended June 30, 2006 compared to the same periods of 2005 as a result of an extension of the abandonment dates of the wells. The economic lives of the wells were assessed and determined to be longer than originally estimated and as such the liability is being accrued over a longer period of time. The decrease is partially offset by the accretion recorded associated with new wells completed during the first six months of 2006 and with the two acquisitions completed in April 2006.



DEPLETION AND DEPRECIATION EXPENSE

Dollars in thousands, except per unit amounts
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Three Months Ended Six Months Ended
June 30, June 30,
2006 2005 Change 2006 2005 Change
-------------------------------------------------------------------------
$ $ % $ $ %
Depletion and
depreciation 2,490 2,105 18 4,996 4,316 16
Per BOE 23.98 18.30 31 24.31 17.77 37
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Depletion and depreciation expense and depletion per BOE for the three and six months ended June 30, 2006 increased compared to the same period of 2005 due to a larger capital asset balance being depleted partially offset by lower production.

Depletion per BOE decreased marginally in the second quarter of 2006 compared to the first quarter of 2006 due to 3.3 Bcf of reserve additions estimated for the acquisitions completed during the second quarter of 2006 and on drilling success.



TAXES

Dollars in thousands, except per unit amounts
-------------------------------------------------------------------------
Three Months Ended Six Months Ended
June 30, June 30,
2006 2005 Change 2006 2005 Change
-------------------------------------------------------------------------
$ $ % $ $ %
Current (20) 17 (218) - 29 (100)
Future income taxes
(recovery) (1,239) 196 (732) (1,320) 470 (381)
Per BOE (12.13) 1.85 (756) (6.42) 2.05 (413)
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In the three months ended June 30, 2006, current taxes have been reduced to nil to reflect the 2006 Canadian federal budget changes eliminating large corporation taxes effective January 1, 2006, becoming law on June 22, 2006.

The future income tax recovery in the second quarter of 2006 reflects the reduction in future tax rates as legislated by the federal government on June 22, 2006. The future tax liability previously recognized by the Company has been recalculated to reflect these lower rates, and the difference between the original estimate of the future tax liability and the current estimate at lower tax rates resulted in a large future tax recovery being recorded in the quarter.



Tax pools at June 30:
Dollars in thousands
-------------------------------------------------------------------------
2006 2005
$ $
-------------------------------------------------------------------------
COGPE 12,220 4,573
CDE 19,006 16,231
CEE 12,185 9,984
UCC 19,842 12,237
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63,253 43,025
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The Company's tax pools increased significantly since June 30, 2005 as a result of capital expenditures which were higher than the tax pools needed to eliminate taxable income. An equity financing completed in September, 2005 included flow through common shares of $10 million. This amount has been deducted from the above noted tax pools as the flow through expenditures were renounced in February, 2006. As at June 30, 2006, approximately $9.5 million of the required expenditures had been incurred. The Company anticipates no difficulties incurring the remaining $500,000 of expenditures in the remainder of 2006.



NET INCOME AND FUNDS FROM OPERATIONS

In thousands, except per share figures
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Three Months Ended Six Months Ended
June 30, June 30,
2006 2005 Change 2006 2005 Change
-------------------------------------------------------------------------
$ $ % $ $ %
Net income 879 537 64 748 1,149 (35)
per basic share 0.02 0.01 23 0.02 0.03 (53)
per diluted share 0.02 0.01 25 0.02 0.03 (52)
Funds from operations 2,406 3,037 (21) 4,881 6,235 (22)
per basic share 0.05 0.09 (44) 0.10 0.18 (45)
per diluted share 0.05 0.08 (38) 0.10 0.17 (42)
Weighted average shares
& special warrants
outstanding 47,813 35,511 19 47,813 34,484 19
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The Company generated net income for the three and six months ended June 30, 2006, which is attributable to the future tax recovery. The Company did incur a loss before taxes for the three and six months ended June 30, 2006, attributable to lower natural gas pricing as well as higher general and administrative costs, higher operating costs and higher depletion expense compared to the same periods of 2005, as previously discussed. The Company is obviously affected by the recent decline in commodity prices; however, the Company anticipates pricing to increase in the fourth quarter of 2006. The Company also anticipates higher production levels in the third and fourth quarters of 2006, with new wells coming on production as well as production re-commencing in the fourth quarter from wells that are currently shut in due to capacity restrictions.

The Company's funds from operations for the three and six month periods ended June 30, 2006 decreased from the same periods of 2005 primarily due to lower production and lower natural gas prices.



LIQUIDITY AND CAPITAL RESOURCES

Dollars in thousands
-------------------------------------------------------------------------
June December
30, 31,
2006 2005 Change
-------------------------------------------------------------------------
$ $ %
Working capital (deficiency) (5,562) 3,490 (259)
Credit facility (6,379) - (100)
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Net debt (11,942) 3,490 (442)
Capital lease obligation (415) (421) (1)
Shareholders' equity (91,167)(93,400) (2)
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At June 30, 2006, the Company had net debt of $11.9 million, primarily as a result of capital expenditures incurred in the first six months of 2006 including acquisitions of additional working interests in producing wells totaling approximately $7.75 million (net) after the sale of unproven lands thereon.

Management expects to fund the remaining of its 2006 capital budget with a combination of funds generated from operations and its $33 million credit facility.

The decrease in shareholder's equity at June 30, 2006 from December 31, 2005 is due to the tax effect of $10 million in flow through share expenditures renounced in the first quarter of 2006 on flow through shares issued in 2005.



CAPITAL EXPENDITURES
Additions to property, plant and equipment

Dollars in thousands
-------------------------------------------------------------------------
Six months ended June,
2006 2005
-------------------------------------------------------------------------
$ $
Land and rentals 5,315 669
Seismic 608 354
Drilling, completing and equipping 10,336 10,679
Pipelines and facilities 3,852 2,714
Other assets 127 81
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Total 20,238 14,497
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Capital expenditures for the six month period ended June 30, 2006 includes the April 2006 acquisitions of additional working interests in 7 producing gas wells as well as undeveloped land in the Chime area for a total of $10.75 million. The undeveloped land from these acquisitions was subsequently sold to a new joint venture partner for $3 million, thereby reducing the Company's acquisition costs to $7.75 million (net), which is included in the above total.

Drilling activities were primarily focused in the Kakwa, and Musreau areas, and the remainder of total expenditures, or approximately 29% of total additions, were incurred on completions and tie-ins. At June 30, 2006, the Company had twelve wells at various stages of drilling and completion for which reserves could not yet be assessed.

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.

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 operations 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.

SEASONALITY OF OPERATIONS

The Company's ability to move heavy equipment in the oil and natural gas fields 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.

FUTURE PROSPECTS

Management continues to be optimistic about the growth of the Company, despite the challenges encountered in 2005 and the first half of 2006. Cinch continues to increase its land base in northern Alberta and British Columbia and has assembled contiguous blocks of land which are still relatively unexplored. With prudent risk management, careful evaluation of results, continued development of the lands as well as expansion into new and existing areas, management believes that the Company will continue to be successful.

CONTRACTUAL OBLIGATIONS, COMMITMENTS, AND GUARANTEES

The Company has various 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) 1-3 4-5 than)
Total 1 year years years 5 years
-------------------------------------------------------------------------
Net debt 11,942 11,942 - - -
Long term portion of capital
lease obligation 415 - 415 - -
Operating lease 590 169 421
Asset retirement obligations 2,762 163 279 39 2,281
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15,709 12,274 1,115 39 2,281
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The Company is also committed to a one year contract (200 drilling days) on a drilling rig which commenced in the second quarter of 2006. The contract provides for a penalty charge if the rig is not utilized for the 200 drilling days. Based on the Company's capital program for 2006, management believes that the rig will be used to its capacity and any potential penalties would not be material to the Company's financial position.

CHANGES IN ACCOUNTING POLICIES

No new accounting policies were adopted in the three and six months ended June 30, 2006.

RECENT ACCOUNTING PRONOUNCEMENTS

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

Comprehensive Income, Financial Instruments and Hedges

The CICA issued new standards in early 2005 for Comprehensive Income (CICA 1530), Financial Instruments (CICA 3855) and Hedges (CICA 3865), which will be effective for the reporting year-end 2007. The new standards will bring Canadian rules in line with current rules in the US. The standards will introduce the concept of "Comprehensive Income" to Canadian GAAP and will require that an enterprise (a) classify items of comprehensive income by their nature in a financial statement and (b) display the accumulated balance of comprehensive income separately from retained earnings and additional paid-in capital in the equity section of a statement of financial position. Derivative contracts will be carried on the balance sheet at their mark-to-market value, with the change in value flowing to either net income or comprehensive income. Gains and losses on instruments that are identified as hedges will flow initially to comprehensive income and be brought into net income at the time the underlying hedged item is settled. Any instruments that do not qualify for hedge accounting will be marked-to-market with the adjustment (tax effected) flowing through the income statement. The Company does not currently have any hedges in place so the impact would not be significant based on the current positions.

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

Throughout the first and second quarters of 2006, the Company has been focused on drilling and completing wells, as well as tieing in production. In the first quarter, drilling activities were delayed due to lack of rig availability. The Company alleviated the problem in the second quarter by entering into a one year contract on a drilling rig which is anticipated to facilitate the execution of the Company's summer and winter drilling program, weather permitting.

The Company has made strides on building a stable production base and continues to work on achieving growth. Consistent with other exploration companies, there will be periods of higher production growth, periods with flush production on new wells which is then anticipated to decline and stabilize in future periods, with some periods experiencing less growth than others.

The Company's production for the second quarter of 2006 decreased compared to the same period of 2005 as a result of the Kakwa 16-13 well which came on production in late 2004 at higher rates and subsequently experienced declines as 2005 progressed. These declines are typical with deep, tight gas wells until decline rates stabilize. Declines in production were partially offset by production additions. In the second quarter of 2006, all of the Bigstone production was shut in due to limited plant capacity. These shut-ins are expected to continue until the proper infrastructure is designed to accommodate the additional activity in these areas. The decrease in commodity prices in the second quarter of 2006 compared to the same period in 2005 further compounded the impact of the decreased production on cash flows. The Company is affected by price variations in the short term while working on efforts to increase production.

Commodity prices continued to drop in the second quarter compared to the first quarter of 2006 and significantly dropped compared to the last quarter of 2005 resulting in lower revenues for the second quarter of 2006. The Company experienced stable production in the second quarter by partially offsetting the shut-in production with two acquisitions which occurred in April 2006.



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

Q1 Q2 Q3 Q4 Annual
-------------------------------------------------------------------------
2006 $ $ $ $ $
-------------------------------------------------------------------------
Petroleum and natural gas sales,
net of transportation and
before royalties 5,200 4,692
Funds from operations 2,475 2,406
Per share - basic 0.05 0.05
- diluted 0.05 0.05
Net income (131) 879
Per share - basic (0.00) 0.02
- diluted (0.00) 0.02
Capital expenditures 6,696 13,542
Acquisition - -
Total assets 113,356 121,861
Working capital (net debt) (820) (11,942)
-------------------------------------------------------------------------
Production (BOE/d) 1,130 1,141
-------------------------------------------------------------------------
2005 $ $ $ $ $
-------------------------------------------------------------------------
Petroleum and natural gas sales,
net of transportation and
before royalties 6,062 5,821 7,207 8,323 27,413
Funds from operations 3,198 3,037 3,908 4,899 15,042
Per share - basic 0.10 0.09 0.09 0.10 0.38
- diluted 0.09 0.08 0.09 0.10 0.36
Net income 612 537 851 1,364 3,364
Per share - basic 0.02 0.01 0.02 0.03 0.08
- diluted 0.02 0.01 0.02 0.03 0.08
Capital expenditures 6,381 8,116 9,566 11,982 36,045
Acquisition - - 1,220 (15) 1,205
Total assets 80,706 89,047 112,178 113,620 113,620
Working capital (net debt) (16,621) (3,670) 10,629 3,490 3,490
-------------------------------------------------------------------------
Production (BOE/d) 1,421 1,264 1,262 1,245 1,297
-------------------------------------------------------------------------
2004 $ $ $ $ $
-------------------------------------------------------------------------
Petroleum and natural gas
sales, net of
transportation and before
royalties 733 873 2,577 4,033 8,215
Funds from operations 190 329 1,314 1,924 3,757
Per share - basic 0.02 0.03 0.06 0.06 0.19
- diluted 0.02 0.03 0.06 0.05 0.17
Net income (loss) (231) 11 131 189 99
Per share - basic (0.02) (0.00) 0.01 0.01 0.00
- diluted (0.02) (0.00) 0.01 0.01 0.00
Capital expenditures 1,726 1,492 1,446 11,385 16,049
Acquisition - - 48,625 79 48,704
Total assets 13,548 54,995 66,060 77,560 77,560
Working capital (net debt) 990 109 (6,011) (14,759) (14,759)
-------------------------------------------------------------------------
Production (BOE/d) 204 216 691 981 525
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Note: numbers may not cross-add due to rounding

Financial Statements

Cinch Energy Corp.
June 30, 2006
(unaudited)


CINCH ENERGY CORP.

Balance Sheets
(unaudited)

June 30, December 31,
2006 2005
$ $
-------------------------------------------------------------------------

ASSETS (notes 3 and 4)
Current
Cash and cash equivalents - 5,654,594
Accounts receivable 4,994,889 6,510,076
Prepaid expenses and deposits 912,123 752,551
-------------------------------------------------------------------------
5,907,012 12,917,221
Property, plant and equipment (note 2) 101,336,546 86,085,917
Goodwill 14,616,996 14,616,996
-------------------------------------------------------------------------
-------------------------------------------------------------------------

121,860,554 113,620,134
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Liabilities and Shareholders' Equity

Current
Accounts payable and accrued liabilities 11,193,439 9,216,805
Current portion of capital lease
obligation (note 3) 275,789 210,007
Credit facility (note 4) 6,379,432 -
-------------------------------------------------------------------------
17,848,660 9,426,812
Capital lease obligation (note 3) 414,700 420,988
Asset retirement obligations (note 5) 2,762,056 2,725,627
Future income taxes (note 6) 9,668,200 7,646,760
-------------------------------------------------------------------------
30,693,616 20,220,187
-------------------------------------------------------------------------

Commitments (note 8)
Shareholders' equity
Share capital (note 7) 89,634,913 93,044,644
Contributed surplus (note 7) 1,679,448 1,250,842
Deficit (147,423) (895,539)
-------------------------------------------------------------------------
91,166,938 93,399,947
-------------------------------------------------------------------------
121,860,554 113,620,134
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes


CINCH ENERGY CORP.

Statements of Operations and Deficit
(unaudited)

Three Months Ended Six Months Ended
June 30, June 30,
2006 2005 2006 2005
-------------------------------------------------------------------------
$ $ $ $
Revenue
Oil and gas sales 4,881,952 6,020,074 10,268,036 12,283,100
Transportation (190,431) (198,840) (376,052) (399,603)
Royalties, net of
Alberta Royalty
Tax Credit (743,594) (1,273,235) (2,037,152) (3,031,562)
Other income 58,574 - 107,496 35
-------------------------------------------------------------------------
4,006,501 4,547,999 7,962,328 8,851,970
-------------------------------------------------------------------------

Expenses
Operating 749,842 717,839 1,515,066 1,329,253
General and
administrative (note 7) 995,249 774,084 1,856,721 1,213,463
Interest on credit
facility 125,509 157,741 125,552 263,978
Interest on capital
lease 7,266 5,452 12,806 11,224
Accretion of asset
retirement
obligations (note 5) 18,873 38,548 28,076 70,784
Depletion and
depreciation 2,490,061 2,104,640 4,995,891 4,315,628
-------------------------------------------------------------------------
4,386,800 3,798,304 8,534,112 7,204,330
-------------------------------------------------------------------------

Income (loss) before
taxes (380,299) 749,695 (571,784) 1,647,640
-------------------------------------------------------------------------

Taxes (note 6)
Current (20,280) 16,500 - 29,000
Future income tax
expense (recovery) (1,238,800) 196,224 (1,319,900) 469,925
-------------------------------------------------------------------------
(1,259,080) 212,724 (1,319,900) 498,925
-------------------------------------------------------------------------

Net income for the
period 878,781 536,971 748,116 1,148,715
Deficit, beginning
of period (1,026,204) (3,647,712) (895,539) (4,259,456)
-------------------------------------------------------------------------

Deficit, end of
period (147,423) (3,110,741) (147,423) (3,110,741)
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Net income for the
period per share (note 7)
Basic and diluted 0.02 0.01 0.02 0.03
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Weighted average
number of shares
outstanding (note 7)
Basic 47,812,632 35,511,441 47,812,632 34,483,583
Diluted 49,511,163 37,347,048 49,414,355 36,319,190
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes


CINCH ENERGY CORP.

Statements of Cash Flows
(unaudited)

Three Months Ended Six Months Ended
June 30, June 30,
2006 2005 2006 2005
-------------------------------------------------------------------------
Operating activities $ $ $ $
Net income for the
period 878,781 536,971 748,116 1,148,715
Add non-cash items:
Depletion and
depreciation 2,490,061 2,104,640 4,995,891 4,315,628
Accretion of asset
retirement
obligations 18,873 38,548 28,076 70,784
Stock compensation
expense (note 7) 257,120 160,783 428,606 229,951
Future income tax
expense (recovery) (1,238,800) 196,224 (1,319,900) 469,925
-------------------------------------------------------------------------
2,406,035 3,037,166 4,880,789 6,235,003
Net change in
non-cash working
capital (2,351,128) 125,910 (2,032,914) (1,123,012)
-------------------------------------------------------------------------
Cash provided by
operating activities 54,907 3,163,076 2,847,875 5,111,991
-------------------------------------------------------------------------
Investing activities
Additions to
property, plant and
equipment (13,541,975) (8,116,025) (20,238,167) (14,497,049)
Net change in
non-cash working
capital 5,705,326 4,722,272 5,306,873 1,807,272
-------------------------------------------------------------------------
Cash used in
investing
activities (7,836,649) (3,393,753) (14,931,294) (12,689,777)
-------------------------------------------------------------------------
Financing activities
Change in credit
facility 6,379,432 (16,033,754) 6,379,432 (9,963,616)
Issue of common shares,
net of issue costs (32,092) 18,081,501 (68,391) 19,454,455
Proceeds from (payments
on) capital lease 112,056 (51,731) 59,494 (103,461)
Net change in non-cash
working capital 29,073 (20,074) 58,290 (64,327)
-------------------------------------------------------------------------
Cash provided by
financing activities 6,488,469 1,975,942 6,428,825 9,323,051
-------------------------------------------------------------------------
Increase (decrease) in
cash and cash
equivalents (1,293,273) 1,745,265 (5,654,594) 1,745,265
Cash and cash
equivalents,
beginning of period 1,293,273 - 5,654,594 -
-------------------------------------------------------------------------
Cash and cash
equivalents,
end of period - 1,745,265 - 1,745,265
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Supplemental
information:
Cash taxes paid (40,676) - - 34,000
Cash interest paid 132,775 - 138,358 275,774
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes

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, 2005. 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 financial statements and
notes thereto for the year ended December 31, 2005.

2. PROPERTY, PLANT AND EQUIPMENT

June 30, 2006
-------------------------------------------------------------------------
Accumulated Net
Cost depletion and book value
depreciation
$ $ $
-------------------------------------------------------------------------
Petroleum and natural gas
properties 124,421,855 (24,070,267) 100,351,588
Equipment under capital lease 1,020,307 (147,461) 872,846
Office furniture and equipment 234,667 (122,555) 112,112
-------------------------------------------------------------------------

125,676,829 (24,340,283) 101,336,546
-------------------------------------------------------------------------
-------------------------------------------------------------------------

December 31, 2005
-------------------------------------------------------------------------
Accumulated Net
Cost depletion and book value
depreciation
$ $ $
-------------------------------------------------------------------------
Petroleum and natural gas
properties 104,375,911 (19,153,951) 85,221,960
Equipment under capital lease 839,303 (95,777) 743,526
Office furniture and equipment 215,095 (94,664) 120,431
-------------------------------------------------------------------------
-------------------------------------------------------------------------

105,430,309 (19,344,392) 86,085,917
-------------------------------------------------------------------------
-------------------------------------------------------------------------

For the three and six month periods ended June 30, 2006 and 2005, no
indirect general and administrative expenditures were capitalized.

Effective April 1, 2006, the Company acquired additional working
interests in 7 producing gas wells and in 35,200 gross acres of
undeveloped land in the Chime area for a total of $10.75 million, which
was allocated to petroleum and natural gas properties. The undeveloped
land from this acquisition was subsequently sold to a joint venture
partner for $3 million, thereby reducing the Company's acquisition costs
to $7.75 million (net).

As at June 30, 2006, $16,237,182 (June 30, 2005 - $13,784,408) of costs
related to undeveloped lands were excluded from costs subject to
depletion.

3. CAPITAL LEASE OBLIGATION

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

Years ending December 31, $
-------------------------------------------------------------------------
2006 152,427
2007 304,855
2008 304,855
-------------------------------------------------------------------------
Total minimum lease payments 762,137
Less amounts representing interest at 5.12% 71,648
-------------------------------------------------------------------------
Present value of minimum lease payments 690,489
Less current portion 275,789
-------------------------------------------------------------------------
Capital lease obligation at June 30, 2006 414,700
-------------------------------------------------------------------------
-------------------------------------------------------------------------

During the three and six month periods ended June 30, 2006, interest
expense of $7,266 and $12,806, respectively (2005 - $5,452 and $11,224,
respectively) relating to capital leases was recorded. A first charge on
the Company's assets has been provided as security for the capital lease
obligation.

4. CREDIT FACILITY

As at June 30, 2006, the Company had a demand bank credit facility
through ATB Financial of $33,000,000 (December 31, 2005 - $26,500,000).
The facility bears interest at the lender's prime rate. As at June 30,
2006, there was $6,379,432 drawn on the credit facility (December 31,
2005 - nil). As collateral for the facility, the Company has provided a
general security agreement with the lender constituting a first ranking
security interest in all personal property and a first ranking floating
charge on all real property of the Company subject only to a
subordination agreement to another bank for the amount of, and as
security for, a capital lease (see note 3).

5. 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, 2006 is approximately
$6,814,300, to be incurred over the next 34 years. The Company used a
credit adjusted, risk-free rate of 5% and an inflation rate of 2% to
arrive at the recorded liability of $2,762,056 at June 30, 2006. The
June 30, 2006 balance reflects adjustments recorded in the first quarter
of 2006 to the estimated abandonment dates of some of the wells. The
estimated dates were revised and extended to better reflect the economic
life of the wells, effectively reducing the present value of the
liability when compared to December 31, 2005, offset by the additions for
the six month period ended June 30, 2006.

During the first six months of 2006, the Company's asset retirement
obligations changed as follows:

$
-------------------------------------------------------------------------
Asset retirement obligations as at December 31, 2005 2,725,627
Adjustment to abandonment dates (77,374)
Liabilities incurred 85,727
Accretion expense 28,076
-------------------------------------------------------------------------
Asset retirement obligations as at June 30, 2006 2,762,056
-------------------------------------------------------------------------

6. FUTURE INCOME TAXES

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

Three Months Ended Six Months Ended
June 30, June 30,
2006 2005 2006 2005
-------------------------------------------------------------------------
Statutory income tax
rate 34.49% 37.62% 34.49% 37.62%
$ $ $ $
Anticipated income tax
expense (recovery) (129,002) 282,035 (197,209) 619,842
Increase/(decrease)
resulting from:
Resource allowance (96,093) (278,314) (216,860) (596,334)
Non-deductible
crown royalties,
net of ARTC (3,149) 162,520 39,551 421,407
Non-deductible
items 1,971 827 1,971 2,045
Rate adjustment (1,099,270) (31,331) (1,095,179) (63,543)
Stock based
compensation
expense 86,743 60,487 147,826 86,508
-------------------------------------------------------------------------

Future income tax
expense (recovery) (1,238,800) 196,224 (1,319,900) 469,925
-------------------------------------------------------------------------

Large corporations
tax (recovery) (20,280) 16,500 - 29,000
-------------------------------------------------------------------------
-------------------------------------------------------------------------

On June 22, 2006, the Canadian federal budget proposal eliminated the
large corporations tax effective January 1, 2006 and hence the Company
has reversed the estimates previously recorded.

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,
2006 2005
$ $
-------------------------------------------------------------------------
Net book value of capital assets in
excess of tax pools (11,438,896) (9,663,114)
Share issue costs 803,941 1,047,675
Asset retirement obligations 834,141 916,356
Other 132,614 52,323
-------------------------------------------------------------------------
Future income taxes (9,668,200) (7,646,760)
-------------------------------------------------------------------------
-------------------------------------------------------------------------

7. SHARE CAPITAL

Authorized - Unlimited number of common voting shares without par value

-------------------------------------------------------------------------
Issued Number $
-------------------------------------------------------------------------
Common shares
Balance, as at January 1, 2006 47,757,632 93,010,709
Future taxes on flow through common shares (i) - (3,362,000)
Issue costs, net of future taxes - (47,731)
-------------------------------------------------------------------------
Balance, as at June 30, 2006 47,757,632 89,600,978
-------------------------------------------------------------------------

Special warrants
Balance at beginning and end of period 55,000 33,935
-------------------------------------------------------------------------
Share capital, as at June 30, 2006 47,812,632 89,634,913
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Contributed surplus
Balance, as at January 1, 2006 1,250,842
Non cash compensation expense (ii) 428,606
-------------------------------------------------------------------------
Contributed surplus, as at June 30, 2006 1,679,448
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Common Shares

(i) Private Placement

On September 8, 2005, the Company issued under private placement a
total of 2,352,941 flow through common shares at $4.25 per share
for proceeds of $9,999,999 and 3,676,472 common shares at $3.40
per share for proceeds of $12,500,005 before total issue costs of
$1,203,880. The tax benefit of the flow through shares was
renounced in its entirety in February, 2006.

(ii) 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 and included in general and administrative
expenses.

Per share amounts

Per share amounts have been calculated using the weighted average number
of common shares and special warrants outstanding for the three and six
month periods ended June 30, 2006 and 2005. The diluted per share amounts
are calculated assuming the exercise of outstanding, in the money
options, and future compensation costs to be incurred on outstanding
options. Per share calculations that are anti-dilutive are not presented
based on 2,051,000 outstanding, out of the money options.

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.

Stock option plan

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

Six months ended June 30, 2006 2005
-------------------------------------------------------------------------
Number of Weighted Number of Weighted
Options Average Options Average
Exercise Exercise
Price Price
-------------------------------------------------------------------------
$ $
Stock options
outstanding, beginning
of period 2,328,000 2.17 1,635,000 1.88
Granted 1,036,000 2.24 866,000 2.42
Exercised - - (100,334) 1.88
Expired - - (201,666) 1.84
-------------------------------------------------------------------------

Stock options
outstanding, end of
period 3,364,000 2.19 2,199,000 2.09
-------------------------------------------------------------------------
-------------------------------------------------------------------------

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

June 30, 2006 June 30, 2005
Number of Weighted Number of Weighted
Number of exercisable Average Number of exercisable Average
Options options Exercise Options options Exercise
Price Price
-------------------------------------------------------------------------
$ $
1,328,000 710,000 1.87-2.00 1,313,000 288,333 1.87-2.00
1,231,000 101,666 2.01-2.50 315,000 20,000 2.01-2.50
680,000 185,332 2.51-3.00 571,000 - 2.51-3.00
125,000 - 3.01-3.50 - - 3.01-3.50
-------------------------------------------------------------------------
3,364,000 996,998 2.19 2,199,000 308,333 2.09
-------------------------------------------------------------------------
-------------------------------------------------------------------------

The options outstanding at June 30, 2006 have a weighted average
remaining contractual life of 3.7 years (June 30, 2005 - 4.1 years). The
fair value of stock options granted to employees, directors and
consultants during the six month periods ended June 30, 2006 and 2005 was
estimated on the date of grant using the Black Scholes option pricing
model with the following weighted average assumptions: dividend yield of
zero percent (2005 - zero percent), expected volatility of 46 percent
(2005 - 32 percent), risk-free interest rate of 4.05 percent (2005 - 3.49
percent), and an expected life of four years (2005 - four years).
Outstanding options granted during the period ended June 30, 2006 had an
estimated weighted average fair value of $0.91 per option (2005 - $0.75
per option), for a total estimated value of $944,950 (2005 - $636,955).
For the three and six month periods ended June 30, 2006, a total of
$257,120 and $428,606, respectively, has been recognized as stock
compensation expense, which is included in general and administrative
expense in the statements of operations, with an offsetting credit to
contributed surplus (2005 - $160,783 and $229,951, respectively).

8. COMMITMENTS

The Company has entered into an operating lease for office premises
expiring on November 20, 2009 which requires minimum monthly payments of
$13,534 to November 30, 2006 and minimum monthly payments of $14,520
thereafter.

The Company has also entered into a one year contract (200 drilling days)
on a drilling rig which commenced in June 2006. The contract provides for
a penalty charge if the rig is not utilized for the 200 drilling days.
Based on the Company's capital program for 2006, management believes that
the rig will be used to its capacity and any potential penalties would
not be material.

9. 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, 2006 and 2005, there were no significant
differences between the carrying amounts of these financial instruments
reported on the balance sheet and their estimated fair values. It is
management's opinion that the Company is not exposed to significant
credit risk.

Interest rate risk

The Company is exposed to minimal interest rate risk relating to
investment income earned on term deposits and to increases in interest
rates on its variable rate credit facility.

Commodity price risk management

As at June 30, 2006, the Company had no fixed price contracts associated
with future production.

10. BASIS OF PRESENTATION

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

Contact Information