Cinch Energy Corp.
TSX : CNH

Cinch Energy Corp.

May 10, 2006 23:59 ET

Cinch Energy Corp. Releases First Quarter 2006 Results

CALGARY--(CCNMatthews - May 10) - Cinch Energy Corp ("Cinch" or "the Company") is pleased to report on the Company's activities and financial results during the first quarter of 2006. Highlights are as follows:




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Three Months Ended March 31,
2006 2005
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Petroleum and natural gas sales, net of
transportation and before royalties ($000's) 5,200 6,062

Sales volumes per day
Natural gas (Mcf/d) 5,647 7,129
Natural gas liquids (Bbl/d) 189 233
Equivalence at 6:1 (BOE/d) 1,130 1,421

Sales Price
Natural gas ($/Mcf) 8.22 7.70
Natural gas liquids ($/Bbl) 60.19 53.75
Equivalence at 6:1 ($/BOE) 51.13 47.41

Funds from operations ($000's)(1) 2,475 3,198
- per share, basic(1) 0.05 0.10
- per share, diluted(1) 0.05 0.09
Net income (loss) ($000's) (131) 612
- per share, basic (0.00) 0.02
- per share, diluted (0.00) 0.02

Capital expenditures ($000's) 6,696 6,381

Basic weighted average shares outstanding (000's) 47,813 33,444
Working capital (deficiency) ($000's)
- As at March 31, 2006 (820)
- As at December 31, 2005 3,490

As at May 5, 2006
Common Shares and
Special Warrants outstanding 47,812,632
Options outstanding 3,344,000
- 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 expense, future
income taxes and accretion of asset retirement obligations. See
further discussion under Non-GAAP measures in the MD&A.


PRODUCTION, PRICES, AND COSTS

For the three months ended March 31, 2006, Cinch's production averaged 1,130 BOE/d versus an average of 1,245 BOE/d in the fourth quarter of 2005. The difference is attributable to normal declines, turn around periods at Musreau, and Bigstone production being shut in for a portion of the period. High activity levels in the Musreau and Kakwa areas have placed pressure on infrastructure in the area, and although additional capacity is expected to be added in approximately May of this year, the lack of available capacity has impacted new and existing well production. In addition, our production at Bigstone was shut-in late in the quarter as the plant is being fully utilized by operators with firm service at the plant. This has also affected the first quarter's production and we anticipate that the Bigstone wells will recommence production in July. Currently, the Company has approximately 550 boepd behind pipe, with the majority of this production projected to come on stream or be reinstated in the third quarter. The Company anticipates that 2006 production should average 1,300 boepd and the exit rate is forecast to range between 1,600 and 1,800 boepd.

Prices for the first quarter of 2006 averaged $51.13 per BOE and were down from the 2005 fourth quarter average of $72.68 per BOE, in conjunction with the natural gas markets. The company does not have any hedges in place and remains positive about the natural gas market.

We have experienced higher costs in the quarter, in part as a result of the issues encountered with the production, the higher well count, and the higher number of employees that we now have. We are attempting to reduce our costs where possible. The per unit metrics in the current quarter are further pressured by production levels and we anticipate that they will improve in the third and fourth quarters, as production behind pipe and new production is brought on.

During the first quarter and winter drilling season, the Company had a number of locations planned for which we could not obtain a drilling rig, which ultimately resulted in delays in bringing on new production. Subsequent to the quarter end, we contracted a drilling rig for a one year period in order to alleviate some of the challenges in obtaining rigs.

OPERATIONS

During the first quarter, Cinch participated in eight wells of which seven wells were cased as potential gas wells.

In the Musreau area, the Company participated in the drilling of two wells which were cased as potential gas wells. Completion operations are expected to commence on these wells late in the second quarter.

At Kakwa, Cinch participated in the drilling of two wells which were also cased as potential gas wells. These wells will also be completed in the second quarter when surface conditions are feasible.

At Kakwa North, a well in which the Company has a 25% working interest was reentered and completed in the Cardium zone. This well had a stabilized flow rate of 2 mmcf/d. It is expected that this well will commence production in September.

Two wells were farmed in and hence the Company has a carried working interest until after completion operations. One well was drilled in the Gold Creek area and cased as a potential gas well. Cinch has 35% interest in this well. At Resthaven, a well was drilled with Cinch having a 33.33% working interest after completion. This well has been completed in two zones with one more zone to be completed in the second quarter. Results are very encouraging to date with production expected to commence in September.

The Company has now closed two purchase and sale agreements, to acquire additional interests in the Chime area (Twp. 60 Rge. 5&6 W6M ) effective April 1, 2006 for an aggregate $10.75 million. Cinch has acquired working interests ranging from approximately 21.0% to 43.9% in seven producing gas wells and 18% to 40.0% in 35,200 gross acres of undeveloped land. The transactions add approximately 140 boepd of production to the Company and increase Cinch's operated interest in the Chime area. It is expected that these transactions will enhance the Company's flexibility in joint venture arrangements and project timing in the Chime area. Cinch has budgeted for three wells to be drilled on the Chime block during 2006 at working interests ranging from approximately 30 to 45%.

As previously mentioned, Cinch has also entered into a one year contract on a drilling rig, which has capabilities to drill to 4000m, so that the Company can more easily execute its upcoming summer and winter drilling program.

Annual Meeting

Cinch's annual meeting of shareholders will be held in The Great Room 3 on the Plus 15 level at the Sandman Hotel, Calgary, 888-7th Avenue S.W. Calgary, Alberta on May 18th at 2:30 p.m. (Calgary time).

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.

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 are forward looking statements, including management's assessment that future plans and operations, wells to be drilled, timing of drilling, completion and tie in of certain wells, productive capacity of new wells, timing of commencement or recommencement of production form certain wells, improving per unit metrics, production estimates and the affect of recently completed acquisitions, and capital expenditures and the timing thereof. Since forward looking statements address future events and conditions, by their very nature, they involve inherent risks and uncertainties. Actual results could differ materially from those currently anticipated due to any number of factors, including risks associated with oil and gas exploration, development, exploitation, production, marketing and transportation, loss of markets, volatility of commodity prices, currency fluctuations, imprecision of reserve estimates, environmental risks, competition from other producers, inability to retain drilling rigs and other services, delays resulting from or inability to obtain required regulatory approvals and the ability to access sufficient capital from internal and external sources. 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 is included in reports on file with Canadian securities regulatory authorities and may be accessed through the SEDAR website (www.sedar.com), and at the Company's website (www.cinchenergy.com). Furthermore, the forward looking statements contained in this news release are made as at the date of this news 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.

MANAGEMENT'S DISCUSSION AND ANALYSIS

May 5, 2006

The following discussion and analysis is provided by management as of May 5, 2006. It should be read in conjunction with the unaudited interim financial statements and related notes for the three month period ended March 31, 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 (loss) 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.

OPERATIONAL UPDATE

Throughout the first quarter of 2006, the Company focused on its capital program primarily in the Chime, Musreau and Kakwa areas. Our planned program for the first quarter of 2006 was delayed by lack of access to drilling rigs. As such, drilling commenced later than planned on a number of locations and we did not drill several planned locations. This subsequently caused delays on completions and tie-ins. These activities will recommence once spring break up is over. Subsequent to quarter end, the Company contracted a drilling rig for one year to assist in minimizing this type of delay on a go forward basis.

The first quarter was also impacted by third party infrastructure issues. The high levels of industry activity in Musreau and Kakwa have placed strains on plant and gathering system capacity, resulting in ongoing compression issues and limitations on productive capacity, resulting in shut-in production for multiple companies. Additional third party plant capacity is anticipated to be brought on in Musreau during May and potentially again in December, with the expectation that this should reduce shut-in production in the area. As well, in Bigstone, plant capacity has also been reached and production processed at the plant on an interruptible basis was shut-in late in the quarter, which equated to approximately 125 BOE/d of Cinch production being shut-in at March 31, 2006. Although we have no formal indication as to when this production may resume, we anticipate that Bigstone production will recommence in July, 2006.

Going forward, the impact of the above noted production shut-ins is expected to be offset by the Company's acquisitions in April, 2006 of additional working interests in the Chime area for $10.75 million, including approximately 140 BOE/d of production in wells in which the Company already has an ownership interest. Through these acquisitions, the Company also increased its land base in 35,200 gross acres of undeveloped land. These transactions are expected to enhance the Company's flexibility in joint venture arrangements and project timing in the Chime area.



PRODUCTION

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Three Months Ended March 31,
2006 2005 Change
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Sales volumes %
Natural gas (mcf/d) 5,647 7,129 (21)
Liquids (bbl/d) 189 233 (19)
Equivalence (BOE/d) 1,130 1,421 (20)
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Volumes

Sales volumes for the three months ended March 31, 2006 versus the comparable period in 2005 are down as the first quarter of 2005 included flush production from the Kakwa 16-13 well, with this well producing 265 BOE/d more in 2005 versus the current quarter. 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.

Typically, we work towards offsetting declines with new production, however in the first quarter of 2006, the Company experienced drilling delays due to the lack of rig availability. Compounding this was the fact that wells in the Bigstone and Musreau area were shut-in, as discussed above, reducing existing production by an average of approximately 60 BOE/d in the quarter. As well, two new wells in the Bigstone and Musreau areas producing at rates of approximately 70 BOE/d commenced production late in the quarter but were shut-in approximately 70% of the time as a result of plant capacity issues.

The Company has a number of drilling locations planned for the remainder of 2006 and anticipates finishing the completion and tie-in of wells which had started drilling late in the first quarter of 2006 and whose continued operations were delayed by the commencement of spring break up. As previously mentioned, subsequent to the first quarter of 2006, the Company entered into a one year contract on a drilling rig in order to facilitate the execution of our summer and winter drilling program.



Commodity prices

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Three Months Ended

March 31, December 31, March 31,
2006 2005 2005
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Sales prices $ $ $
Natural gas (per mcf) 8.22 12.44 7.70
Liquids (per bbl) 60.19 62.69 53.75
Equivalence (per BOE) 51.13 72.68 47.41
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Natural gas prices have decreased significantly in the first quarter of 2006 compared to the last quarter of 2005 and have increased when compared to the same period of 2005. The Company's production continues to be unhedged and is marketed in the Alberta spot market.

Natural gas liquids pricing has decreased compared to the fourth quarter of 2005 and increased compared to the same period of 2005. The Company has not hedged any of its liquids production.



REVENUES
Dollars in thousands, except per unit amounts
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Three Months Ended March 31,
2006 2005 Change
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$ $ %
Oil and gas sales,
net of transportation 5,200 6,062 (14)
Per BOE 51.13 47.41 8
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Revenues for the three months ended March 31, 2006 are 14% lower than the same period of 2005 due to lower production offset by higher commodity prices, as discussed above. Transportation expenses as a percentage of revenues for the three months ended March 31, 2006 have remained consistent at approximately 3% when compared to the same periods of 2005, as expected.



ROYALTIES
Dollars in thousands, except per unit amounts
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Three Months Ended March 31,
2006 2005 Change
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$ $ %
Royalties, net of ARTC 1,294 1,758 (26)
Per BOE 12.72 13.76 (8)
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Royalty expense, net of Alberta Royalty Tax Credit ("ARTC"), decreased in the three months ended March 31, 2006 due to lower production levels, as previously discussed, and because a larger percentage of wells were eligible for the Crown Deep Gas Royalty Holiday. Two wells of the Company also paid out subsequent to March 31, 2005, hence the Company no longer pays gross overriding royalties on these wells. The Company's royalty rate (royalties net of ARTC as a percentage of oil and gas sales) is typically lower in the first quarter 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 once the maximum ARTC has been earned. The Company anticipates that its royalty rate in 2006 will be slightly lower than that of 2005.



OPERATING EXPENSES
Dollars in thousands, except per unit amounts
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Three Months Ended March 31,
2006 2005 Change
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$ $ %
Operating 765 611 25
Per BOE 7.52 4.78 57
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Total operating expenses increased in the three months ended March 31, 2006 compared to the same period of 2005 due to an additional 17 producing wells and due to expenses incurred on compressor and equipment maintenance and repairs.

Operating expenses are higher on a per BOE basis in the three months ended March 31, 2006 compared to the same period of 2005 as a result of third party gas gathering and processing fees which are approximately $0.80/BOE higher (compared to the same period of 2005), an increase in compressor maintenance and repairs and general operating costs, and as a result of fixed costs being allocated over lower production rates thereby increasing the per unit cost.

Operating costs per BOE in the first quarter of 2006 were higher than the fourth quarter of 2005 primarily due to additional equipment and compressor maintenance and repairs, compressor overhauls, and the increased use of chemical and treating supplies.



GENERAL AND ADMINISTRATIVE EXPENSES
Dollars in thousands, except per unit amounts
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Three Months Ended March 31,
2006 2005 Change
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$ $ %
General and administrative 861 439 96
Per BOE 8.47 3.44 146
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Total general and administrative costs increased in the three months ended March 31, 2006 compared to the same period of 2005 due to the growth of the Company, requiring a greater number of employees (10 employees in the first quarter of 2005 to 16 employees in the first quarter of 2006) and contractors to handle operations, administration and exploration. Due to the increased number of employees and the need to remain competitive in the marketplace, salaries and related compensation increased approximately $342 thousand. This amount includes the increase in non-cash stock based compensation expense of $102 thousand attributable to an increased number of stock options outstanding (2,057,334 options in 2005 to 3,344,000 options in 2006). As at May 5, 2006, the Company has 3,344,000 options outstanding amounting to approximately 7% of issued shares and special warrants. Delays in drilling also impacted general and administrative expense, as operator overhead recoveries were approximately $50 thousand lower in the current quarter compared to the prior year's quarter.

General and administrative expenses per BOE have increased in the three months ended March 31, 2006 compared to the same period in 2005 as the overall costs have increased and production had decreased, as previously noted.

The cash costs per BOE for the remainder of 2006 are expected to decrease as production levels increase and are not expected to exceed $6.00 per BOE for 2006. The non-cash stock based compensation expense is expected to average approximately $1.90 per BOE for 2006.



ACCRETION OF ASSET RETIREMENT OBLIGATIONS EXPENSE
Dollars in thousands, except per unit amounts
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Three Months Ended March 31,
2006 2005 Change
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$ $ %
Accretion expense 9 32 (72)
Per BOE 0.09 0.25 (64)
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Accretion expense decreased in the three months ended March 31, 2006 compared to the same period of 2005 and to the fourth quarter of 2005 as a result of an extension of the abandonment dates of the wells based on a detailed assessment of the economic lives of the wells thereby extending the period over which the liability is being accreted.



DEPLETION AND DEPRECIATION EXPENSE
Dollars in thousands, except per unit amounts
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Three Months Ended March 31,
2006 2005 Change
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$ $ %
Depletion and depreciation 2,506 2,211 13
Per BOE 24.64 17.29 43
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Depletion and depreciation expense (D&D) and depletion per BOE for the three months ended March 31, 2006 increased compared to the same period of 2005 due to a larger capital asset balance being depleted.



TAXES
Dollars in thousands, except per unit amounts
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Three Months Ended March 31,
2006 2005 Change
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$ $ %
Current 20 13 54
Future income taxes (81) 274 (130)
Per BOE (0.60) 2.24 (127)
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Current taxes in the three months ended March 31, 2006 is comprised of Large Corporations Tax (LCT).

Future income taxes for the three months ended March 31, 2006 decreased commensurate with the change in income experienced during the period.

The Company had tax pools of $51.7 million outstanding at March 31, 2006 (March 31, 2005 - $37.8 million).



NET INCOME (LOSS) AND FUNDS FROM OPERATIONS
In thousands, except share and per share figures
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Three Months Ended March 31,
2006 2005 Change
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$ $ %
Net income (loss) (131) 612 (121)
per basic share (0.00) 0.02 (130)
per diluted share (0.00) 0.02 (130)
Funds from operations 2,475 3,198 (23)
per basic share 0.05 0.10 (60)
per diluted share 0.05 0.09 (56)

Weighted average shares &
special warrants outstanding 47,813 33,444 43

Common shares & special warrants
outstanding, end of period 47,813 34,041 40
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The Company incurred a net loss in the first three months of 2006 compared to net income for the same period of 2005, attributable to lower production levels as well as higher depletion and operating costs. The Company anticipates higher production levels once production from new wells reaches capacity.

The Company's funds from operations for the three month period ended March 31, 2006 decreased from the prior period primarily due to lower production as well as higher fixed expenses.



LIQUIDITY AND CAPITAL RESOURCES
Dollars in thousands
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March 31, December 31, Change
2006 2005
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$ $ %
Working capital (deficiency) (820) 3,490 (123)
Long term portion of
capital lease obligation 368 421 (13)
Shareholders' equity 90,055 93,400 (4)
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At March 31, 2006, the Company had a working capital deficiency of $820,000, primarily as a result of capital expenditures incurred in the

quarter net of funds from operations. As at March 31, 2006, the Company had not drawn on its credit facility.

Management expects to fund its 2006 capital budget with a combination of funds generated from operations and its credit facility. Subsequent to March 31, 2006, the Company increased its credit facility through ATB Financial to $33 million.

The decrease in shareholder's equity at March 31, 2006 from December 31, 2005 is due to the tax effect of the flow through share renouncement made in the first quarter of 2006.



CAPITAL EXPENDITURES
Dollars in thousands
Additions to property, plant and equipment
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Three Months Ended March 31,
2006 2005
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Land and rentals 218 44
Seismic 160 322
Drilling, completing and equipping 5,525 4,706
Pipelines and facilities 650 1,299
Other assets 143 10
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Total 6,696 6,381
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Capital expenditures for the period ended March 31, 2006 were incurred primarily on drilling locations in the Kakwa, Musreau, and Bigstone areas, and the remainder of total expenditures, or approximately 35% of the total, were incurred on completions and tie-ins. At March 31, 2006, the Company had ten wells at various stages of drilling and completion for which reserves could not yet be assessed.

Subsequent to the first quarter of 2006, the Company acquired additional working interests in the Chime area, increasing its working interest in 7 producing gas wells generating approximately 140 BOE/d (net), as well as increasing its working interest in 35,200 gross acres of undeveloped land in the Chime area. This transaction is expected to enhance the Company's flexibility in joint venture arrangements and project timing in the Chime area.



Tax pools at March 31:
Dollars in thousands
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2006 2005
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COGPE 7,626 4,110
CDE 19,070 13,233
CEE 8,843 9,895
Tangibles 16,124 10,515
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51,663 37,753
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The Company's tax pools increased significantly since March 31, 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, and this amount has been deducted from the above noted tax pools as the flow through expenditures were renounced in February, 2006. As at March 31, 2006, approximately $6 million of the required expenditures had been incurred. The Company anticipates no difficulties incurring the remaining $4.0 million of expenditures for the remainder of 2006. The future tax liability increased by approximately $3.4 million in the first quarter of 2006 as a result of the renouncement.

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 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.

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 quarter of 2006. Cinch continues to increase its land base in northern Alberta and has assembled a large, contiguous block of land which is 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 grow and that success will continue to be achieved.

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
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Payments
less greater
than 1-3 4-5 than
Total 1 year years years 5 years
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Working capital deficiency 820 820 - - -
Long term portion of
capital lease obligation 368 - 368 - -
Operating lease 631 166 465
Asset retirement obligations 2,657 284 262 39 2,072
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4,476 1,270 1,095 39 2,072
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The Company has committed to a one year contract (200 drilling days) on a drilling rig to commence on approximately June 1, 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 months ended March 31, 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 quarter of 2006, the Company has been focused on drilling and completing wells as well as tieing in production. Drilling activities were delayed due to a lack of access to rigs. The Company is also affected by factors such as weather conditions, with spring break up commencing towards the end of the first quarter limiting continued operations. Subsequent to the first quarter of 2006, the Company entered into a one year contract on a drilling rig anticipated to commence June 2006, which is anticipated to facilitate the execution of the Company's summer and winter drilling program.

The Company has made strides on building a strong and 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.

Comparing the first quarter of 2006 to the same period of 2005, the Company's production decreased as a result of a well coming on production in late 2004 at higher rates and subsequently experiencing declines as 2005 progressed, as is typical with deep, tight gas wells. Declines in the production were partially offset by production additions. In the first quarter of 2006, there was also production that had been shut in due to limited plant capacity and this is expected to continue until infrastructure is designed to accommodate the additional activity in these areas. The increase in commodity prices in the first quarter of 2006 compared to the same period in 2005 assisted in offsetting some of the impact of the decrease in production. The Company is largely affected by price variations in the short term while working on efforts to increase production.

Commodity prices dropped significantly in the first quarter of 2006 compared to the last quarter of 2005. The Company also experienced a decrease in production largely due to production being shut in and natural declines, resulting in lower revenues and higher expenses for the quarter.

In 2005, the Company's core areas experienced unusually warm temperatures delaying activities toward the end of 2005 and into 2006. In the fourth quarter of 2005, the Company also encountered further delays due to lack of rig availability.

Comparing 2005 to 2004, revenues and funds from operations as well as net income increased in 2005 as a result of higher gas prices, higher production levels attributable to drilling results, acquisitions occurring in 2005 and a full year of production attributable to the wells acquired as part of the Rio Alto acquisition in August 2004.



SELECTED ANNUAL AND QUARTERLY INFORMATION
(000's, except per share and production data)
-------------------------------------------------------------------------
Q1 Q2 Q3 Q4 Annual
-------------------------------------------------------------------------
2006 $ $ $ $ $
-------------------------------------------------------------------------
Petroleum and natural gas
sales, net of transportation
and before royalties 5,200
Funds from operations 2,475
Per share - basic 0.05
- diluted 0.05
Net income (131)
Per share - basic (0.00)
- diluted (0.00)
Capital expenditures 6,696
Acquisition -
Total assets 113,356
Working capital (deficiency) (820)
-------------------------------------------------------------------------
Production (BOE/d) 1,130
-------------------------------------------------------------------------
2005 $ $ $ $ $
-------------------------------------------------------------------------
Petroleum and natural gas
sales, net of transportation
and before royalties 6,062 5,821 7,207 8,323 27,413
Funds from operations 3,198 3,037 3,908 4,899 15,042
Per share - basic 0.10 0.09 0.09 0.10 0.38
- diluted 0.09 0.08 0.09 0.10 0.36
Net income (loss) 612 537 851 1,364 3,364
Per share - basic 0.02 0.01 0.02 0.03 0.08
- diluted 0.02 0.01 0.02 0.03 0.08
Capital expenditures 6,381 8,116 9,566 11,982 36,045
Acquisition - - 1,220 (15) 1,205
Total assets 80,706 89,047 112,178 113,620 113,620
Working capital (deficiency) (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 (deficiency) 990 109 (6,011) (14,759) (14,759)
-------------------------------------------------------------------------
Production (BOE/d) 204 216 691 981 525
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Per share amounts reflect a 2.5 for 1 common share consolidation which
occurred on August 12, 2004.
Note: numbers may not cross-add due to rounding.



Financial Statements

Cinch Energy Corp.
March 31, 2006
(unaudited)



CINCH ENERGY CORP.

BALANCE SHEETS
(Unaudited)

March 31, December 31,
2006 2005
$ $
-------------------------------------------------------------------------
ASSETS

Current
Cash and cash equivalents (note 2) 1,293,273 5,654,594
Accounts receivable 6,496,022 6,510,076
Prepaid expenses and deposits 750,925 752,551
-------------------------------------------------------------------------
8,540,220 12,917,221

Property, plant and equipment (note 3) 90,198,905 86,085,917

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

113,356,121 113,620,134
-------------------------------------------------------------------------
-------------------------------------------------------------------------

LIABILITIES AND SHAREHOLDERS' EQUITY

Current
Accounts payable and accrued liabilities 9,150,103 9,216,805
Current portion of capital lease obligation
(note 5) 210,007 210,007
-------------------------------------------------------------------------

9,360,110 9,426,812

Capital lease obligation (note 5) 368,426 420,988

Asset retirement obligations (note 6) 2,657,456 2,725,627

Future income taxes (note 7) 10,915,400 7,646,760
-------------------------------------------------------------------------
23,301,392 20,220,187
-------------------------------------------------------------------------

Commitments (note 9)

Shareholders' equity
Share capital (note 8) 89,658,605 93,044,644
Contributed surplus (note 8) 1,422,328 1,250,842
Deficit (1,026,204) (895,539)
-------------------------------------------------------------------------
90,054,729 93,399,947
-------------------------------------------------------------------------

113,356,121 113,620,134
-------------------------------------------------------------------------
-------------------------------------------------------------------------
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)

For the three months ended March 31, 2006 2005
$ $
-------------------------------------------------------------------------

Revenue
Oil and gas sales 5,386,084 6,263,026
Transportation (185,621) (200,763)
Royalties, net of Alberta Royalty Tax Credit (1,293,558) (1,758,327)
Other income 48,922 35
-------------------------------------------------------------------------
3,955,827 4,303,971
-------------------------------------------------------------------------

Expenses
Operating 765,224 611,414
General and administrative 861,472 439,379
Interest on credit facility - 106,237
Interest on capital lease (note 5) 5,583 5,772
Accretion of asset retirement obligations
(note 6) 9,203 32,236
Depletion and depreciation 2,505,830 2,210,988
-------------------------------------------------------------------------
4,147,312 3,406,026
-------------------------------------------------------------------------

Income (loss) before taxes (191,485) 897,945

Taxes (note 7)
Current 20,280 12,500
Future income tax expense (recovery) (81,100) 273,701
-------------------------------------------------------------------------
(60,820) 286,201
-------------------------------------------------------------------------

Net income (loss) for the period (130,665) 611,744

Deficit, beginning of period (895,539) (4,259,456)
-------------------------------------------------------------------------

Deficit, end of period (1,026,204) (3,647,712)
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Net income (loss) for the period per share
(note 8)
Basic and diluted (0.00) 0.02
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Weighted average number of shares outstanding
(note 8)
Basic 47,812,632 33,444,304
Diluted 50,506,628 34,610,971
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes



CINCH ENERGY CORP.

STATEMENTS OF CASH FLOWS
(Unaudited)

For the three months ended March 31, 2006 2005
$ $
-------------------------------------------------------------------------

Operating activities
Net income for the period (130,665) 611,744
Add non-cash items:
Depletion and depreciation 2,505,830 2,210,988
Accretion of asset retirement obligations 9,203 32,236
Non-cash compensation expense (note 8) 171,486 69,168
Future income tax expense (recovery) (81,100) 273,701
-------------------------------------------------------------------------
2,474,754 3,197,837
Net change in non-cash working capital 318,214 (1,248,922)
-------------------------------------------------------------------------
Cash provided by operating activities 2,792,968 1,948,915
-------------------------------------------------------------------------

Investing activities
Additions to property, plant and equipment (6,696,192) (6,381,024)
Net change in non-cash working capital (398,453) (2,915,000)
-------------------------------------------------------------------------
Cash used in investing activities (7,094,645) (9,296,024)
-------------------------------------------------------------------------

Financing activities
Issue of common shares, net of issue costs (36,299) 1,372,954
Increase in credit facility - 6,070,138
Capital lease payments (52,562) (51,730)
Net change in non-cash working capital 29,217 (44,253)
-------------------------------------------------------------------------
Cash provided by (used in) financing activities (59,644) 7,347,109
-------------------------------------------------------------------------

Decrease in cash (4,361,321) -

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

Cash and cash equivalents, end of period 1,293,273 -
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Supplemental information:
Cash taxes paid 50,612 13,500
Cash interest paid 5,583 112,009
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying note




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. CASH AND CASH EQUIVALENTS

As at March 31, 2006, cash and cash equivalents include term deposits of
$2,630,000 with maturities of 30 days or less. The term deposits earned
interest between 2.70% and 3.30%.

3. PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment

March 31, 2006
-------------------------------------------------------------------------
Accumulated
depletion and Net
Cost depreciation book value
$ $ $
-------------------------------------------------------------------------

Petroleum and natural gas
properties 110,979,789 (21,622,823) 89,356,966
Equipment under capital lease 839,303 (118,905) 720,398
Office furniture and equipment 230,035 (108,494) 121,541
-------------------------------------------------------------------------

112,049,127 (21,850,222) 90,198,905
-------------------------------------------------------------------------
-------------------------------------------------------------------------

December 31, 2005
-------------------------------------------------------------------------
Accumulated
depletion and Net
Cost depreciation book value
$ $ $
-------------------------------------------------------------------------

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 month period ended March 31, 2006 and for the year ended
December 31, 2005, no indirect general and administrative expenditures
were capitalized.

As at March 31, 2006, $14,192,627 of costs related to undeveloped lands
were excluded from costs subject to depletion (December 31, 2005 -
$11,885,839).




4. CREDIT FACILITY

As at March 31, 2006, the Company had a demand bank credit facility
through ATB Financial of $26,500,000 (December 31, 2005 - $26,500,000).
The facility bears interest at the lender's prime rate. There were no
draws on the credit facility for the three months ended March 31, 2006
(December 31, 2005 - nil). As security 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 12.

5. 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 174,307
2007 232,409
2008 232,409
-------------------------------------------------------------------------

Total minimum lease payments 639,125

Less amounts representing interest at 5.12% (60,692)
-------------------------------------------------------------------------

Present value of minimum lease payments 578,433

Less current portion (210,007)
-------------------------------------------------------------------------

Capital lease obligation at March 31, 2006 368,426
-------------------------------------------------------------------------
-------------------------------------------------------------------------

For the three months ended March 31, 2006, there was $5,583 (March 31,
2005 - $5,772) recorded in interest expense relating to capital leases.
There is a first charge on the Company's assets as security for the
capital lease obligation.

6. ASSET RETIREMENT OBLIGATIONS

The total future asset retirement obligations result from the Company's
net ownership interest in wells and facilities. Management estimates the
total undiscounted amount of future cash flows required to reclaim and
abandon wells and facilities as at March 31, 2006 is approximately
$6,334,100 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 $2,657,456 at March 31, 2006. In the
first quarter of 2006, the estimated abandonment dates of some of the
wells were revised and extended to better reflect the economic life of
the wells, thereby reducing the present value of the liability when
compared to December 31, 2005.

The Company's asset retirement obligations changed as follows:

March 31, 2006
$
-------------------------------------------------------------------------

Asset retirement obligations, as at January 1, 2006 2,725,627
Adjustment to abandonment date (77,374)
Liabilities incurred -
Accretion expense 9,203
-------------------------------------------------------------------------

Asset retirement obligations, end of period 2,657,456
-------------------------------------------------------------------------
-------------------------------------------------------------------------

7. FUTURE INCOME TAXES




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

March 31, 2006 March 31, 2005
-------------------------------------------------------------------------
Statutory income tax rate 35.62% 37.62%
$ $
Anticipated income tax expense (recovery) (68,207) 337,807
Increase/(decrease) resulting from:
Resource allowance (120,767) (318,020)
Non-deductible crown royalties, net of
Alberta Royalty Tax Credit 42,700 258,887
Non-deductible items - 1,219
Stock based compensation expense 61,083 26,021
Rate adjustment 4,091 (32,213)
-------------------------------------------------------------------------

Future income tax expense (recovery) (81,100) 273,701
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Large corporations tax 20,280 12,500
-------------------------------------------------------------------------
-------------------------------------------------------------------------

(60,820) 286,201
-------------------------------------------------------------------------
-------------------------------------------------------------------------

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:

March 31, December 31,
2006 2005
$ $
-------------------------------------------------------------------------
Net book value of capital assets in
excess of tax pools (12,878,775) (9,663,114)
Share issue costs 973,054 1,047,675
Asset retirement obligations 893,437 916,356
Other 96,884 52,323
-------------------------------------------------------------------------

Future income tax liability (10,915,400) (7,646,760)
-------------------------------------------------------------------------
-------------------------------------------------------------------------

8. 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 - (24,039)
-------------------------------------------------------------------------
Balance, as at March 31, 2006 47,757,632 89,624,670
-------------------------------------------------------------------------
Special warrants
Balance at beginning and end of period 55,000 33,935
-------------------------------------------------------------------------
Share capital, as at March 31, 2006 47,812,632 89,658,605
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Contributed surplus
Balance, as at January 1, 2006 1,250,842
Non cash compensation expense (ii) 171,486
-------------------------------------------------------------------------
Contributed surplus, as at March 31, 2006 1,422,328
-------------------------------------------------------------------------
-------------------------------------------------------------------------




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 issues 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.

Per share amounts

Per share amounts have been calculated using the weighted average number
of common shares and special warrants outstanding during the year of
47,812,632 (March 31, 2005 - 33,444,304). For the three month period
ended March 31, 2006, the diluted earnings per share amounts are
anti-dilutive and are therefore not presented. If the amounts had not
been anti-dilutive the weighted average number of common shares would be
calculated assuming the exercise of outstanding, in-the-money options,
and future compensation costs to be incurred on outstanding options
resulting in a weighted average number of common shares of 50,506,628
(March 31, 2005 - 34,610,971).

Stock option plan

The Company has a stock option plan authorizing the grant of options to
purchase shares to designated participants, being directors, officers,
employees or consultants. Under the terms of the plan, the Company may
grant options to purchase shares equal to a maximum of ten percent of the
total issued and outstanding shares and special warrants of the Company.
The aggregate number of options that may be granted to any one individual
must not exceed five percent of the total issued and outstanding shares
and special warrants. Options are granted at exercise prices equal to the
estimated fair value of the shares at the date of grant and may not
exceed a ten year term. The vesting for options granted occurs over a
three year period, with one third of the number granted vesting on each
of the first, second, and third anniversary dates of the grant unless
otherwise specified by the Board of Directors at the time of grant.

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

March 31, 2006 March 31, 2005
Weighted Weighted
Average Average
Number of Exercise Number of Exercise
Options Price Options Price
-------------------------------------------------------------------------
$ $
Stock options outstanding,
beginning of period 2,328,000 2.17 1,635,000 1.88
Granted 1,016,000 2.25 641,000 2.50
Exercised - - (42,000) 1.88
Expired - - (176,000) 1.74
-------------------------------------------------------------------------
Stock options outstanding,
end of period 3,344,000 2.19 2,057,334 2.08
-------------------------------------------------------------------------
-------------------------------------------------------------------------

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

March 31, 2006 March 31, 2005
Weighted Weighted
Average Average
Number of Exercise Number of Exercise
Options Price Options Price
-------------------------------------------------
$ $
1,308,000 1.87-2.00 1,396,334 1.87-2.00
1,231,000 2.01-2.50 90,000 2.01-2.50
680,000 2.51-3.00 571,000 2.51-3.00
125,000 3.01-3.50 - 3.01-3.50
-------------------------------------------------
3,344,000 2.19 2,057,334 2.08
-------------------------------------------------
-------------------------------------------------

The options outstanding at March 31, 2006 have a weighted average
remaining contractual life of 3.9 years (March 31, 2005 - 4.2 years). As
at March 31, 2006, a total of 938,665 outstanding options were
exercisable (March 31, 2005 - 472,000).

The fair value of stock options granted to employees, directors and
consultants during the three months ended March 31, 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 55.3 percent
(2005 - 30.5 percent), risk-free interest rate of 4.04 percent (2005 -
3.51 percent), and an expected life of 4 years (2005 - 4 years).
Outstanding options granted during the three months ended March 31, 2006
had an estimated weighted average fair value of $1.05 per option (March
31, 2005 - $0.74 per option), for a total estimated value of $1,063,200
(2005 - $471,955). A total of $171,486 (2005 - $69,168) has been
recognized as stock compensation expense with an offsetting credit to
contributed surplus for the three months ended March 31, 2006.

9. 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 commencing approximately June 1, 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.

10. FINANCIAL INSTRUMENTS

Fair value of financial instruments

Financial instruments recognized on the balance sheet consist of cash and
cash equivalents, accounts receivable, deposits, accounts payable, and
capital lease obligations. As at March 31, 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.

Commodity price risk management

As at March 31, 2006, the Company had no fixed price contracts associated
with future production.

11. BASIS OF PRESENTATION

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

12. SUBSEQUENT EVENTS

Subsequent to March 31, 2006, the Company closed two acquisitions
totaling approximately $10.75 million which were effective April 1, 2006,
acquiring working interests in 7 producing gas wells and in 35,200 gross
acres of undeveloped land in the Chime area.

Subsequent to March 31, 2006, the Company increased its revolving, demand
bank credit facility through ATB Financial to $33,000,000 from
$26,500,000. The facility bears interest at the lender's prime rate.

Contact Information