Cinch Energy Corp.
TSX : CNH

Cinch Energy Corp.

November 02, 2006 23:59 ET

Cinch Energy Corp. Releases Third Quarter 2006 Results

CALGARY--(CCNMatthews - Nov. 2) - Cinch Energy Corp ("Cinch" or "the Company") is pleased to report on the Company's activities and financial results for the third quarter of 2006. Highlights are as follows:



-------------------------------------------------------------------------
HIGHLIGHTS Three Months Ended Nine Months Ended
September 30, September 30,
2006 2005 2006 2005
-------------------------------------------------------------------------
Petroleum and natural gas sales,
net of transportation ($000's) 4,487 7,207 14,379 19,090
Production per day
Natural gas (Mcf/d) 5,529 6,234 5,633 6,556
Natural gas liquids (Bbl/d) 214 223 197 222
Equivalence at 6:1 (BOE/d) 1,135 1,262 1,135 1,315
Sales Price
Natural gas ($/Mcf) 6.14 10.26 7.00 8.67
Natural gas liquids ($/Bbl) 69.25 64.60 67.34 58.95
Equivalence at 6:1 ($/BOE) 42.97 62.08 46.38 53.19

$ $ $ $
Funds from operations (000's)(1) 2,115 3,908 6,996 10,143
- per share, basic(1) 0.05 0.09 0.15 0.27
- per share, diluted(1) 0.04 0.09 0.14 0.26

Net income (000's) (576) 851 172 2,000
- per share, basic (0.01) 0.02 0.00 0.05
- per share, diluted (0.01) 0.02 0.00 0.05

Capital expenditures ($000's) 7,403 9,566 27,642 24,063

Basic weighted average shares
outstanding (000's) 47,813 43,225 47,813 37,429
Working capital (net debt)(2)
($000's)
- As at September 30, 2006 (17,307)
- As at December 31, 2005 3,490

As at
October 30, 2006
Common Shares and Special Warrants
outstanding 47,812,632
Options outstanding 4,104,000
- average exercise price 1.96
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Funds from operations is a non-GAAP measure and represents cash
provided by operating activities on the statement of cash flows less
the effect of changes in non-cash working capital related to
operating activities.
(2) Net debt is a non-GAAP measure and represents the sum of the working
capital (deficiency) and the outstanding credit facility balance.



President's Message

PRODUCTION, PRICES, AND COSTS

Cinch's production averaged 1,135 BOE/d for both the three and nine months ended September 30, 2006. The Company's production profile has been stable for the nine month period, which is typical for long life Deep Basin production, following initial declines. Cinch's production increased significantly with Resthaven commencing production subsequent to the end of the third quarter.

On October 22, 2006, the Resthaven 9-25-60-3W6 well, in which the Company has a 33.33% working interest, commenced production at a rate of approximately 6.5 mmcf/d, along with approximately 165 bbl/d of associated natural gas liquids. The Company is pleased with results from the well, which is producing from only one completed zone with another completed zone behind pipe.

Current production is approximately 1400 BOE/d. At Bigstone, one of the Company's wells recommenced production in October, 2006 at a rate of approximately 100 BOE/d net to Cinch, after having previously been shut-in since March of this year due to plant curtailments. Cinch has approximately 170 BOE/d behind pipe, which consists mainly of infrastructure restrictions at Musreau, and the Kakwa North 10-20 well, which has been delayed due to surface issues. At this time, Cinch is projecting an exit rate of approximately 1600 BOE/d for 2006.

Prices for the three and nine months in 2006 averaged $42.97 per BOE and $46.38 per BOE respectively, a decrease from more robust pricing at the start of the year. The Company's production base is heavily weighted towards natural gas. Natural gas markets have been volatile of late, reaching a low in early October of approximately $3.51/mcf at AECO and significantly recovering to approximately $7.20/mcf on October 31. The Company remains positive about the natural gas prices in the long term, notwithstanding the volatility experienced in prices during 2006.

The Company's balance sheet remains strong, exiting the third quarter of 2006 with net debt of $17.3 million and a total credit facility of $33 million.

OPERATIONS

During and subsequent to the third quarter of 2006, Cinch has been very active in operating the drilling and completing of wells in its core areas of Chime and Kakwa, located approximately 105 kilometers south of Grande Prairie, Alberta.

The Kakwa 13-13-61-5W6 well, in which the Company has a 50% working interest, is currently being flow tested from the first zone of a two zone completion program. Assuming encouraging flow rates, it is anticipated that this well could commence production during the first freeze up period, which is expected to be during December. The Kakwa 4-30-61-4W6 well, in which the Company has a 50% working interest, was completed with uneconomic flow rates, however further completion work is being considered for this well.

At Chime, the Company is drilling the 12-6-60-5W6 well, in which it has a 50% working interest. This well, which will evaluate a three zone prospect, is projected to reach total depth of 3850m in approximately three weeks. The Chime 14-30-60-5W6 well, in which the Company had a 42.72% working interest, was drilled and abandoned. This well was the first in a multi-well program with Cinch's new joint venture partner in the area. The Company is in the initial planning stages for an additional three well program in Chime.

At Musreau, the Company elected to go penalty on the completion program for the non-operated Musreau 2-34-61-6W6 well, in which Cinch has a 30% working interest. The Musreau 14-7-62-5W6 well, in which Cinch has a 18.83% working interest, has been completed with low flow rates. Further completion work is being considered for this well.

At Chime East, the Smoky 12-24-60-4W6 well, in which Cinch has a 45% working interest, was cased as a potential multi-zone gas well. It is anticipated that completion operations will commence in three weeks.

In the Pouce Coupe area, located approximately 25 kilometres north east of the Company's Dawson acreage, Cinch is participating in a 2500m Golata test. The Company is paying 50% of the drilling and completion costs to earn a 40% working interest in the spacing unit that the well is located on and a 50% working interest in the 4 sections of land offsetting this drill site. This well is expected to spud this week and should reach total depth in three weeks.

OUTLOOK

Cinch's core area of Chime and Kakwa within the Deep Basin area remains very active, with industry bringing on new production facilities and adding significant production volumes during 2006. Cinch remains very positive about the exploration potential in its core area and also continues to pursue growth opportunities elsewhere.



FOR FURTHER INFORMATION, PLEASE CONTACT:

John W. Elick George Ongyerth
Chief Executive Officer President
Tel: (403) 693-0090 Tel: (403) 693-0090
elickj@cinchenergy.com ongyerthg@cinchenergy.com

Or visit our website at www.cinchenergy.com



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 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 infrastructure issues and plant turnarounds, expected royalty rates and expenses related thereto, 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, 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, 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.

Non-GAAP Measures

This release 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.

This release 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.

MANAGEMENT'S DISCUSSION AND ANALYSIS

October 30, 2006

The following management's discussion and analysis ("MD&A") is provided by management as of, and is dated, October 30, 2006. It should be read in conjunction with the unaudited interim financial statements and related notes for the three and nine month period ended September 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.

OPERATIONAL UPDATE

The Company's program for the third quarter of 2006 consisted of drilling new wells and completing and tieing-in wells drilled in the second quarter of 2006, primarily in the Kakwa, Chime and Chime East areas. The Company was successful in obtaining drilling rigs in the third quarter. This was facilitated by the use of a rig which the Company contracted for a one year term in the second quarter of 2006.

Production levels remained stable in the third quarter of 2006, with minimal declines in the Company's existing production base. Two additional wells were tied in during the third quarter of 2006. Two wells, tied-in late in the second quarter, produced throughout the third quarter and compensated for reduced production on non-operated wells due to the ongoing infrastructure issues in the Musreau area. The well and plant operators continue to work on solutions to alleviate the situation but we anticipate similar issues in the fourth quarter of 2006. There was also a plant turnaround in September, resulting in curtailed and shut in production on some the Company's non-operated wells for up to two weeks.

Our plant capacity at Bigstone is interruptible, resulting in our Bigstone production of approximately 140 BOE/d being shut in for the entire third quarter. Subsequent to the end of the third quarter, one of the Company's Bigstone wells was brought back on production. This well, producing at rates of approximately 100 BOE/d (net) recommenced production approximately one month earlier than we had anticipated. The remaining three wells are anticipated to be brought back on production in November 2006, but we anticipate that the wells may produce sporadically until all infrastructure expansions are complete. The Bigstone production that was shut-in during the third quarter was offset by two acquisitions completed in April 2006. The Company acquired additional working interests in 7 producing natural gas wells in the Chime area at that time for approximately $7.75 million (net) after selling the undeveloped land thereon, providing approximately 145 BOE/d of production for the second and third quarters of 2006.



PRODUCTION
-------------------------------------------------------------------------
Three Months Ended Nine Months Ended
September 30, September 30,
2006 2005 Change 2006 2005 Change
-------------------------------------------------------------------------
Sales volumes % %
Natural gas (Mcf/d) 5,529 6,234 (11) 5,633 6,556 (14)
Liquids (Bbl/d) 214 223 (4) 197 222 (11)
Equivalence (BOE/d) 1,135 1,262 (10) 1,135 1,315 (14)

Sales prices $ $ % $ $ %
Natural gas ($/Mcf) 6.14 10.26 (40) 7.00 8.67 (19)
Liquids($/Bbl) 69.25 64.60 7 67.34 58.95 14
Equivalence ($/BOE) 42.97 62.08 (31) 46.38 53.19 (13)
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Sales volumes for the three and nine months ended September 30, 2006 have decreased compared to the same periods of 2005 as the first nine months of 2005 included flush production from wells coming on in late 2004. Deep, tight gas wells provide a strong production base after a period of high initial declines.

The Company experienced minimal production declines in the third quarter of 2006 and 2 wells were tied-in, one of which began production at the end of September.

The Company's production volumes in 2006 have been impacted by infrastructure issues. For the third quarter of 2006, Bigstone production was shut-in leaving approximately 140 BOE/d behind pipe. At Musreau, there was a plant turnaround in September 2006, resulting in curtailed and shut-in production on non-operated wells for up to two weeks. Some of the Company's operated wells were also shut in sporadically throughout the quarter due to issues at the Musreau plant. In the first nine months of 2006, the Company has tied in 7 wells which have partially offset volume decreases previously discussed.

Natural gas prices have continued to decline in the third quarter of 2006 with natural gas prices dropping 40% over the same period of 2005 and 8% over the second quarter of 2006. The Company's production continues to be unhedged and is marketed in the Alberta spot market.

Natural gas liquids pricing has slightly decreased over the prior quarter but has increased over the comparable period of 2005. The increase in natural gas liquids pricing is positive and impacts 17% of our production. The Company has not hedged any of its liquids production.



REVENUES

Dollars in thousands, except per unit amounts
-------------------------------------------------------------------------
Three Months Ended Nine Months Ended
September 30, September 30,
2006 2005 Change 2006 2005 Change
-------------------------------------------------------------------------
$ $ % $ $ %
Oil and gas sales,
net of transportation 4,487 7,207 (38) 14,379 19,090 (25)
Per BOE 42.97 62.08 (31) 46.38 53.19 (13)
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Revenues during the three and nine months ended September 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 September 30, 2006, have also marginally decreased compared to the second quarter of 2006 due to lower natural gas prices as well as slightly lower production.



ROYALTIES

Dollars in thousands, except per unit amounts
-------------------------------------------------------------------------
Three Months Ended Nine Months Ended
September 30, September 30,
2006 2005 Change 2006 2005 Change
-------------------------------------------------------------------------
$ $ % $ $ %
Royalties, net of ARTC 948 2,072 (54) 2,985 5,104 (42)
Per BOE 9.08 17.86 (49) 9.63 14.22 (32)
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Royalty expense, net of Alberta Royalty Tax Credit ("ARTC"), decreased in the three and nine months ended September 30, 2006 compared to the same periods of 2005 as a result of lower commodity prices and lower production levels. 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 increase in royalty expense from the second quarter of 2006 is due to the fact that the Company used all of the benefits from the ARTC in the first half of the year, and due to a gas cost allowance adjustment received in the second quarter of 2006, which reduced crown expense for the second quarter.

The Alberta government has announced that it plans to eliminate the ARTC effective January 1, 2007, which is expected to increase the Company's royalty expense by $500 thousand in 2007.

The Company's royalty rate (royalties net of ARTC as a percentage of oil and gas sales) was marginally higher in the third quarter of 2006 compared to the first half of 2006, as ARTC was earned in the first and second quarters of 2006 which reduced the royalty rate for those periods. The royalty rate for the fourth quarter of 2006 is expected to remain consistent with the rate experienced in the third quarter of 2006. The Company anticipates that its royalty rate in 2006 will be 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
-------------------------------------------------------------------------
Three Months Ended Nine Months Ended
September 30, September 30,
2006 2005 Change 2006 2005 Change
-------------------------------------------------------------------------
$ $ % $ $ %
Operating 791 760 4 2,306 2,089 10
Per BOE 7.57 6.54 16 7.44 5.82 28
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Total operating expenses increased in the three and nine months ended September 30, 2006 compared to the same periods of 2005, due to an additional 14 producing wells and due to increased expenses incurred on compressor maintenance and repairs and compressor oil, chemical and condensate treating costs, as well as methanol costs, property taxes and increased contractor costs associated with the increased activity.

Operating expenses per BOE were higher in the three and nine months ended September 30, 2006 compared to the same periods of 2005 as a result of increased costs associated with the increased number of producing wells, as previously discussed, over lower production. Gas gathering and processing fees are also approximately $0.50/BOE higher for the first nine months of 2006 compared to the same period of 2005.

Total operating costs as well as operating costs per BOE were higher in the third quarter of 2006 compared to the second quarter primarily due to property taxes expensed in the third quarter.



GENERAL AND ADMINISTRATIVE EXPENSES

Dollars in thousands, except per unit amounts
-------------------------------------------------------------------------
Three Months Ended Nine Months Ended
September 30, September 30,
2006 2005 Change 2006 2005 Change
-------------------------------------------------------------------------
$ $ % $ $ %
General and administrative 759 624 22 2,616 1,837 42
Per BOE 7.27 5.37 35 8.44 5.12 65
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Total general and administrative costs increased in the three and nine months ended September 30, 2006 compared to the same periods of 2005 due to the hiring of additional employees (2 additional employees at the end of the third quarter of 2006 compared to the same period of 2005) and the increased use of contractors and consultants to handle operation, administration and exploration activities. 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 $590 thousand for the nine months ended September 30, 2006. This amount includes the increase in non-cash stock based compensation expense of $198 thousand attributable to an increased number of stock options outstanding (4,217,334 options at September 30, 2006 compared to 2,353,000 options at September 30, 2005). As at October 30, 2006, the Company has 4,104,000 options outstanding, amounting to approximately 8.6% of outstanding common shares and special warrants. Public company related expenses such as annual reports, corporate governance compliance, audit fees, and reserve reports have also increased approximately $65 thousand for the nine months ended September 2006 compared to the same period of 2005. Insurance costs have also increased $40 thousand over the past year with increases consistent throughout the industry.

General and administrative expenses per BOE have increased in the three and nine months ended September 30, 2006 compared to the same periods in 2005 as the higher expenses were calculated over lower production, as previously noted.

Total general and administrative costs decreased in the third quarter of 2006 compared to the second quarter of 2006 largely due to decreased stock based compensation costs due to the cancellation of options in the third quarter. By canceling the options, there is no longer a stock based compensation expense recorded associated to those options. Public company related expenses such as press release costs, filing fees, fees relating to audit and reserve reports as well as charges relating to corporate governance matters were also higher in the second quarter of 2006.

General and administrative cash costs per BOE for all of 2006 are not expected to exceed $6.50 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
-------------------------------------------------------------------------
Three Months Ended Nine Months Ended
September 30, September 30,
2006 2005 Change 2006 2005 Change
-------------------------------------------------------------------------
$ $ % $ $ %
Interest expense 73 18 306 211 293 (28)
Per BOE 0.70 0.15 367 0.68 0.82 (17)
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Interest expense increased in the three months ended September 30, 2006 compared to the same period of 2005 as the Company had higher draws on its bank credit facility in the third quarter of 2006. Interest expense decreased in the nine months ended September 30, 2006 compared to the same period of 2005, as the Company had lower draws on its bank credit facility in the first nine months of 2006. The Company did not draw on its $33 million bank line until the second quarter of 2006 and exited the third quarter with an amount outstanding under its credit facility of $11.3 million.



ACCRETION OF ASSET RETIREMENT OBLIGATIONS EXPENSE

Dollars in thousands, except per unit amounts
-------------------------------------------------------------------------
Three Months Ended Nine Months Ended
September 30, September 30,
2006 2005 Change 2006 2005 Change
-------------------------------------------------------------------------
$ $ % $ $ %
Accretion expense 20 42 (52) 48 112 (57)
Per BOE 0.20 0.36 (44) 0.16 0.31 (48)
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Accretion expense decreased in the three and nine months ended September 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 nine months of 2006 and with the two acquisitions completed in April 2006.



DEPLETION AND DEPRECIATION EXPENSE

Dollars in thousands, except per unit amounts
-------------------------------------------------------------------------
Three Months Ended Nine Months Ended
September 30, September 30,
2006 2005 Change 2006 2005 Change
-------------------------------------------------------------------------
$ $ % $ $ %
Depletion and
depreciation 2,658 2,244 18 7,654 6,560 17
Per BOE 25.45 19.33 32 24.69 18.28 35
-------------------------------------------------------------------------
-------------------------------------------------------------------------



Total depletion and depreciation expense as well as depletion per BOE for the three and nine months ended September 30, 2006 increased compared to the same periods of 2005 due to a larger capital asset balance being depleted, partially offset by lower production.

Depletion per BOE increased slightly in the third quarter of 2006 compared to the second quarter due to a higher ratio of capital spending per BOE added to reserves than in the past. The Company is experiencing overall higher capital costs.



TAXES

Dollars in thousands, except per unit amounts
-------------------------------------------------------------------------
Three Months Ended Nine Months Ended
September 30, September 30,
2006 2005 Change 2006 2005 Change
-------------------------------------------------------------------------
$ $ % $ $ %
Current - 51 (100) - 80 (100)
Future income taxes
(recovery) (170) 603 (128) (1,490) 1,073 (239)
Per BOE (1.63) 5.63 (129) (4.81) 3.21 (250)
-------------------------------------------------------------------------
-------------------------------------------------------------------------


There were no current taxes recorded in the three months ended September 30, 2006. Current taxes were reduced to nil in the second quarter of 2006, to reflect the elimination of large corporation taxes effective January 1, 2006, which became law on June 22, 2006.

Future income taxes for the three months ended September 30, 2006 decreased commensurate with the change in income experienced during the quarter.

The future income tax recovery recorded for the nine months ended September 30, 2006 reflects the reduction in future tax rates as legislated by the federal government on June 22, 2006. In the second quarter of 2006, the future tax liability previously recognized by the Company was recalculated to reflect these lower rates, and the difference between the original estimate of the future tax liability and the June 30, 2006 estimate at lower tax rates resulted in a large future tax recovery recorded in the second quarter.



Tax pools at September 30:
Dollars in thousands
-------------------------------------------------------------------------
2006 2005
$ $
-------------------------------------------------------------------------
COGPE 12,728 4,974
CDE 19,705 18,059
CEE 16,609 13,714
UCC 19,670 13,120
-------------------------------------------------------------------------
68,712 49,867
-------------------------------------------------------------------------
-------------------------------------------------------------------------


The Company's tax pools increased significantly since September 30, 2005 as a result of capital expenditures which were higher than the tax deductions 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 September 30, 2006, all of the required expenditures had been incurred.



NET INCOME AND FUNDS FROM OPERATIONS

In thousands, except per share figures
-------------------------------------------------------------------------
Three Months Ended Nine Months Ended
September 30, September 30,
2006 2005 Change 2006 2005 Change
-------------------------------------------------------------------------
$ $ % $ $ %
Net income (loss) (576) 851 (168) 172 2,000 (91)
per basic share (0.01) 0.02 (150) 0.00 0.05 (100)
per diluted share (0.01) 0.02 (150) 0.00 0.05 (100)
Funds from operations 2,115 3,908 (46) 6,996 10,143 (31)
per basic share 0.05 0.09 - 0.15 0.27 (45)
per diluted share 0.04 0.09 - 0.14 0.26 (46)
Weighted average shares
& special warrants
outstanding 47,813 43,225 11 47,813 37,429 28
-------------------------------------------------------------------------
-------------------------------------------------------------------------


For the nine months ended September 30, 2006, the Company generated net income, attributable to the future tax recovery, previously discussed. The Company did incur a loss before taxes 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 period of 2005. The Company incurred a net loss for the three months ended September 30, 2006 compared to the same period of 2005 due to the same factors as discussed above. 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 fourth quarter of 2006, with new wells commencing production late in the third quarter as well as in the fourth quarter.

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



LIQUIDITY AND CAPITAL RESOURCES

Dollars in thousands
-------------------------------------------------------------------------
September December
30, 2006 31, 2005 Change
-------------------------------------------------------------------------
$ $ %
Working capital (deficiency), excluding
credit facility (6,051) 3,490 (273)
Credit facility (11,256) - (100)
-------------------------------------------------------------------------
Net debt (17,307) 3,490 (596)
Capital lease obligation (346) (421) (18)
Shareholders' equity (90,768) (93,400) (3)
-------------------------------------------------------------------------
-------------------------------------------------------------------------


At September 30, 2006, the Company had net debt of $17.3 million, primarily as a result of $27.6 million in capital expenditures incurred in the first nine months of 2006.

Management is in a position to fund the remainder of its 2006 capital budget (approximately $9 million) with a combination of funds generated from operations and its $33 million credit facility.

The decrease in shareholder's equity at September 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
-------------------------------------------------------------------------
Nine months ended September 30,
2006 2005
-------------------------------------------------------------------------
$ $
Land and rentals 6,209 977
Seismic 639 531
Drilling, completing and equipping 16,618 19,170
Pipelines and facilities 3,907 3,298
Other assets 269 87
-------------------------------------------------------------------------
Total 27,642 24,063
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Capital expenditures for the nine months ended September 30, 2006 were incurred primarily on drilling activities in the Chime, Kakwa, and Musreau areas. In addition, the Company purchased land in 2006, focusing on the Kakwa, Chime and Dawson West areas, further increasing the Company's land base in its core areas as well as providing opportunities for further plays in the Dawson West area, which has become increasingly active.

Capital expenditures for 2006 include 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 joint venture partner for $3 million, thereby reducing the Company's acquisition costs for the production and reserves to $7.75 million (net), which is included in the above total.

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 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.

FUTURE PROSPECTS

Management continues to be optimistic about the growth of the Company, despite the challenges encountered in 2005 and the first nine months 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, some of which are offsetting proven lands explored by other companies. 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
-------------------------------------------------------------------------
less Payments greater
than 1-3 4-5 than
Total 1 year years years 5 years
-------------------------------------------------------------------------

Net debt 17,307 17,307 - - -
Long term portion of capital
lease obligation 346 - 346 - -
Operating lease 550 172 378 - -
Asset retirement obligations 2,926 164 370 40 2,352
-------------------------------------------------------------------------
21,129 17,643 1,094 40 2,352
-------------------------------------------------------------------------
-------------------------------------------------------------------------


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 2006 and 2007 capital programs, 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 nine months ended September 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 nine months of 2006, the Company has been focused on drilling and completing wells, as well as tieing-in production. In the first quarter of 2006, 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 has facilitated the execution of the Company's third quarter drilling program.

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 nine months ended September 30, 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 with production subsequently declining toward the end of 2005 and stabilizing in 2006. These declines are typical with deep, tight gas wells until decline rates stabilize. Declines in production were partially offset by production additions for 2006.

In the third quarter of 2006, all of the Bigstone production continued to be shut in since the beginning of second quarter due to limited plant capacity. These shut-ins are expected to continue sporadically until the proper infrastructure is designed to accommodate the additional activity in these areas. The Company was able to offset the impact of the shut-in production with two acquisitions which occurred in April 2006.

Commodity prices continued to drop in the third quarter of 2006 compared to the first half of 2006 and significantly dropped compared to the last quarter of 2005, resulting in lower revenues for the third quarter of 2006. The decrease in commodity prices in the third quarter of 2006 compared to the same period in 2005 further compounded the impact of the decreased production on cash flows. The Company is largely impacted by price variations in the short term. Management believes in the long term strength of the natural gas market, despite short term fluctuations and volatility.



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 4,487
Funds from operations 2,475 2,406 2,115
Per share - basic 0.05 0.05 0.05
- diluted 0.05 0.05 0.04
Net income (131) 879 (576)
Per share - basic (0.00) 0.02 (0.01)
- diluted (0.00) 0.02 (0.01)
Capital expenditures 6,696 13,542 7,403
Acquisition - - -
Total assets 113,356 121,861 125,894
Working capital (net debt) (820) (11,942) (17,307)
-------------------------------------------------------------------------
Production (BOE/d) 1,130 1,141 1,135
-------------------------------------------------------------------------
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.
September 30, 2006
(unaudited)


CINCH ENERGY CORP.

BALANCE SHEETS
(unaudited)

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

ASSETS (notes 3 and 4)

Current
Cash and cash equivalents - 5,654,594
Accounts receivable 4,277,374 6,510,076
Prepaid expenses and deposits 774,271 752,551
-------------------------------------------------------------------------

5,051,645 12,917,221

Property, plant and equipment (note 2) 106,225,518 86,085,917

Goodwill 14,616,996 14,616,996
-------------------------------------------------------------------------

125,894,159 113,620,134
-------------------------------------------------------------------------
-------------------------------------------------------------------------

LIABILITIES AND SHAREHOLDERS' EQUITY

Current
Accounts payable and accrued liabilities 10,826,828 9,216,805
Current portion of capital lease
obligation (note 3) 275,789 210,007
Credit facility (note 4) 11,255,977 -
-------------------------------------------------------------------------

22,358,594 9,426,812

Capital lease obligation (note 3) 345,753 420,988

Asset retirement obligations (note 5) 2,925,788 2,725,627

Future income taxes (note 6) 9,495,900 7,646,760
-------------------------------------------------------------------------

35,126,035 20,220,187
-------------------------------------------------------------------------

Commitments (note 8)

Shareholders' equity
Share capital (note 7) 89,629,233 93,044,644
Contributed surplus (note 7) 1,862,661 1,250,842
Deficit (723,770) (895,539)
-------------------------------------------------------------------------

90,768,124 93,399,947
-------------------------------------------------------------------------

125,894,159 113,620,134
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes

On behalf of the Board:

"John W. Elick" "William D. Robertson"
Director Director



CINCH ENERGY CORP.

STATEMENTS OF OPERATIONS AND DEFICIT
(unaudited)

Three months ended Nine months ended
September 30, September 30,
2006 2005 2006 2005
-------------------------------------------------------------------------
$ $ $ $
Revenue
Oil and gas sales 4,692,773 7,415,880 14,960,809 19,698,980
Transportation (205,702) (209,276) (581,754) (608,879)
Royalties, net of
Alberta Royalty
Tax Credit (948,096) (2,072,318) (2,985,248) (5,103,880)
Other income 15,504 56,446 123,000 56,481
-------------------------------------------------------------------------

3,554,479 5,190,732 11,516,807 14,042,702
-------------------------------------------------------------------------

Expenses
Operating 790,652 759,560 2,305,718 2,088,813
General and
administrative (note 7) 759,119 623,572 2,615,840 1,837,035
Interest on credit
facility 65,493 12,292 191,045 276,270
Interest on capital
lease 7,267 5,510 20,073 16,734
Accretion of asset
retirement
obligations (note 5) 20,422 41,714 48,498 112,498
Depletion and
depreciation 2,657,673 2,243,888 7,653,564 6,559,516
-------------------------------------------------------------------------

4,300,626 3,686,536 12,834,738 10,890,866
-------------------------------------------------------------------------

Income (loss) before
taxes (746,147) 1,504,196 (1,317,931) 3,151,836
-------------------------------------------------------------------------

Taxes (note 6)
Current - 50,500 - 79,500
Future income tax
expense (recovery) (169,800) 602,662 (1,489,700) 1,072,587
-------------------------------------------------------------------------

(169,800) 653,162 (1,489,700) 1,152,087
-------------------------------------------------------------------------

Net income (loss)
for the period (576,347) 851,034 171,769 1,999,749

Deficit, beginning
of period (147,423) (3,110,741) (895,539) (4,259,456)
-------------------------------------------------------------------------

Deficit, end of period (723,770) (2,259,707) (723,770) (2,259,707)
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Net income (loss) for
the period per share
(note 7)
Basic and diluted (0.01) 0.02 0.00 0.05
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Weighted average number
of shares outstanding
(note 7)
Basic 47,812,632 43,225,096 47,812,632 37,429,440
Diluted 49,516,210 45,353,399 50,387,943 39,557,744
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes


CINCH ENERGY CORP.

STATEMENTS OF CASH FLOWS
(unaudited)

Three months ended Nine months ended
September 30, September 30,
2006 2005 2006 2005
-------------------------------------------------------------------------
$ $ $ $
Operating activities
Net income (loss)
for the period (576,347) 851,034 171,769 1,999,749
Add non-cash items:
Depletion and
depreciation 2,657,673 2,243,888 7,653,564 6,559,516
Accretion of asset
retirement
obligations 20,422 41,714 48,498 112,498
Stock compensation
expense (note 7) 183,213 168,820 611,819 398,771
Future income tax
expense (recovery) (169,800) 602,662 (1,489,700) 1,072,587
-------------------------------------------------------------------------
2,115,161 3,908,118 6,995,950 10,143,121
Net change in non-cash
working capital 554,571 579,957 (1,478,343) (543,055)
-------------------------------------------------------------------------
Cash provided by
operating activities 2,669,732 4,488,075 5,517,607 9,600,066
-------------------------------------------------------------------------

Investing activities
Additions to property,
plant and equipment (7,403,335) (9,565,807) (27,641,502) (24,062,856)
Acquisition - (1,220,030) - (1,220,030)
Net change in non-cash
working capital (70,282) (1,875,626) 5,236,591 (68,354)
-------------------------------------------------------------------------
Cash used in investing
activities (7,473,617) (12,661,463) (22,404,911) (25,351,240)
-------------------------------------------------------------------------

Financing activities
Change in credit
facility 4,876,545 - 11,255,977 (9,963,616)
Issue of common shares,
net of issue costs (8,180) 21,284,195 (76,571) 40,738,650
Payments on capital
lease (68,947) (52,285) (9,453) (155,746)
Net change in non-cash
working capital 4,467 51,030 62,757 (13,297)
-------------------------------------------------------------------------
Cash provided by
financing activities 4,803,885 21,282,940 11,232,710 30,605,991
-------------------------------------------------------------------------
Increase (decrease)
in cash and cash
equivalents - 13,109,552 (5,654,594) 14,854,817

Cash and cash
equivalents,
beginning of period - 1,745,265 5,654,594 -
-------------------------------------------------------------------------

Cash and cash
equivalents, end of
period - 14,854,817 - 14,854,817
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Supplemental information:
Cash taxes paid - 28,032 - 62,032
Cash interest paid 72,759 17,230 211,117 293,004
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes


CINCH ENERGY CORP.

NOTES TO FINANCIAL STATEMENTS

September 30, 2006 and 2005
(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, 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

September 30, 2006
-------------------------------------------------------------------------
Cost Accumulated Net
depletion book value
and
depreciation
$ $ $
-------------------------------------------------------------------------

Petroleum and natural
gas properties 131,968,158 (26,687,826) 105,280,332
Equipment under capital lease 1,020,307 (172,902) 847,405
Office furniture and equipment 235,009 (137,228) 97,781
-------------------------------------------------------------------------
133,223,474 (26,997,956) 106,225,518
-------------------------------------------------------------------------
-------------------------------------------------------------------------

December 31, 2005
-------------------------------------------------------------------------
Cost Accumulated Net
depletion book value
and
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 nine month periods ended September 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 these acquisitions was subsequently sold to a joint venture
partner for $3 million, thereby reducing the Company's acquisition costs
for the production and reserves to $7.75 million (net).

As at September 30, 2006, $19,524,698 (September 30, 2005 - $19,786,910)
of costs related to undeveloped lands were excluded from costs subject to
depletion. Future development costs of $2,548,000 were included in the
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 76,214
2007 304,855
2008 304,855
-------------------------------------------------------------------------

Total minimum lease payments 685,924

Less amounts representing interest at 5.12% 64,382
-------------------------------------------------------------------------

Present value of minimum lease payments 621,542

Less current portion 275,789
-------------------------------------------------------------------------

Capital lease obligation at September 30, 2006 345,753
-------------------------------------------------------------------------
-------------------------------------------------------------------------


During the three and nine month periods ended September 30, 2006,
interest expense of $7,267 and $20,073, respectively (2005 - $5,510 and
$16,734, 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 September 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
September 30, 2006, there was $11,255,977 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 September 30, 2006 is approximately
$7,054,300, to be incurred over the next 34 years. The Company used a
credit adjusted, risk-free rate ranging from 5% to 6% and an inflation
rate of 2% to arrive at the recorded liability of $2,925,788 at
September 30, 2006. The September 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 nine month period ended September 30, 2006.

During the first nine 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 229,037
Accretion expense 48,498
-------------------------------------------------------------------------

Asset retirement obligations as at September 30, 2006 2,925,788
-------------------------------------------------------------------------
-------------------------------------------------------------------------

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 Nine months ended
September 30, September 30,
2006 2005 2006 2005
-------------------------------------------------------------------------
Statutory income tax rate 34.49% 37.62% 34.49% 37.62%

Anticipated income
tax expense (recovery) (257,346) 565,879 (454,554) 1,185,721
Increase/(decrease)
resulting from:
Resource allowance (99,095) (373,909) (315,955) (970,244)
Non-deductible crown
royalties, net of ARTC 96,774 406,986 136,325 828,393
Non-deductible items 2,034 1,346 4,005 3,391
Rate adjustment 24,643 (61,150) (1,070,537) (124,692)
Stock based compensation
expense 63,190 63,510 211,016 150,018
-------------------------------------------------------------------------

Future income tax
expense (recovery) (169,800) 602,662 (1,489,700) 1,072,587
-------------------------------------------------------------------------

Large corporations tax - 50,500 - 79,500
-------------------------------------------------------------------------
-------------------------------------------------------------------------


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

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

Net book value of capital assets
in excess of tax pools (11,223,128) (9,663,114)
Share issue costs 725,827 1,047,675
Asset retirement obligations 883,588 916,356
Other 117,813 52,323
-------------------------------------------------------------------------

Future income taxes (9,495,900) (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 - (53,411)
-------------------------------------------------------------------------
Balance, as at September 30, 2006 47,757,632 89,595,298
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Special warrants
Balance at beginning and end of period 55,000 33,935
Share capital, as at September 30, 2006 47,812,632 89,629,233
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Contributed surplus
Balance, as at January 1, 2006 1,250,842
Non cash compensation expense(ii) 611,819
-------------------------------------------------------------------------
Contributed surplus, as a September 30, 2006 1,862,661
-------------------------------------------------------------------------
-------------------------------------------------------------------------

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 nine
month periods ended September 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 3,112,334 outstanding, out-of-the-money options and 1,806,000
outstanding, out-of-the-money options for the three months and nine
months ended September 30, 2006, 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.

Stock option plan

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

Nine months ended September 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 2,141,000 1.75 1,040,000 2.54
Exercised - - (100,334) 1.88
Expired (251,666) 2.16 (221,666) 1.91
-------------------------------------------------------------------------
Stock options outstanding,
end of period 4,217,334 1.96 2,353,000 2.17
-------------------------------------------------------------------------
-------------------------------------------------------------------------


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

September 30, 2006 September 30, 2005
-------------------------------------------------------------------------
Number of Number of
Exercise Number of exercisable Exercise Number of exercisable
Price Options options Price Options options
-------------------------------------------------------------------------
$ $
1.24-1.50 905,000 - 1.24-1.50 - -
1.51-2.00 1,431,334 993,999 1.51-2.00 1,308,000 572,333
2.01-2.50 1,131,000 101,666 2.01-2.50 315,000 20,000
2.51-3.00 625,000 201,666 2.51-3.00 605,000
3.01-3.50 125,000 41,667 3.01-3.50 125,000
-------------------------------------------------------------------------
1.96 4,217,334 1,338,998 2.17 2,353,000 592,333
-------------------------------------------------------------------------
-------------------------------------------------------------------------


The options outstanding at September 30, 2006 have a weighted average
remaining contractual life of 3.8 years (September 30, 2005 - 3.9 years).
The fair value of stock options granted to employees, directors and
consultants during the nine month periods ended September 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
48 percent (2005 - 33 percent), risk-free interest rate of 3.95 percent
(2005 - 3.43 percent), and an expected life of four years (2005 - four
years). Outstanding options granted during the nine month period ended
September 30, 2006 had an estimated weighted average fair value of
$0.73 per option (2005 - $0.80 per option), for a total estimated value
of $1,556,600 (2005 - $837,397). For the three and nine month periods
ended September 30, 2006, a total of $183,213 and $611,819, respectively,
has been recognized as stock compensation expense, which is included in
general and administrative expense in the statement of operations, with
an offsetting credit to contributed surplus (2005 - $168,820 and
$398,771, 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 and 2007, 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 September 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 September 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