CALGARY, March 16 /CNW/ - Cinch Energy Corp ("Cinch" or "the Company") is pleased to announce its financial and operational highlights for the three months and year ended December 31, 2005.
2005 ACCOMPLISHMENTS
- Received net proceeds of $19.1 million from the exercise of
outstanding warrants
- Completed a private placement in the third quarter raising net
proceeds of $21.3 million
- Increased annual production from 525 boe/d to 1,297 boe/d, an
increase of 147%
- Increased cash flow from $3.8 million to $15.0 million, an
increase of 296%
- Added a significant land position at Dawson, British Columbia,
consisting of 17,495 gross acres
- Negotiated the acquisition of 3-D seismic coverage in the East
Chime area
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HIGHLIGHTS
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Three Months Ended Year Ended
December 31, December 31,
2005 2004 2005 2004
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Petroleum and natural gas sales,
net of transportation and
before royalties ($000's) 8,323 4,033 27,413 8,215
Sales volumes per day
Natural gas (Mcf/d) 6,248 4,953 6,478 2,707
Natural gas liquids (Bbl/d) 203 155 217 73
Equivalence at 6:1 (BOE/d) 1,245 981 1,297 525
Sales Price
Natural gas ($/Mcf) 12.44 7.29 9.59 6.97
Natural gas liquids ($/Bbl) 62.69 49.66 59.83 48.68
Equivalence at 6:1 ($/BOE) 72.68 44.70 57.90 42.79
NOTE: per share figures reflect a 2.5 for 1 common share consolidation
which occurred on August 12, 2004
$ $ $ $
Funds from operations (000's)(1) 4,899 1,924 15,042 3,757
- per share, basic(1) 0.10 0.06 0.38 0.19
- per share, diluted(1) 0.10 0.05 0.36 0.17
Net income (000's) 1,364 189 3,364 99
- per share, basic 0.03 0.01 0.08 0.00
- per share, diluted 0.03 0.01 0.08 0.00
Capital expenditures (000's) 11,982 11,163 36,045 16,049
Acquisition (000's) (15) 79 1,205 48,704
Basic weighted average shares
outstanding (000's) 47,813 33,331 40,047 20,054
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Net working capital (deficiency) (000's) $
As at December 31, 2005 3,490
As at December 31, 2004 (14,759)
As at March 8, 2006
Common Shares and Special Warrants outstanding 47,812,632
Dilutives outstanding
- options 2,453,000
- 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, future taxes
and any other non-cash expenses related to the company's operations.
See further discussion under Non-GAAP measures in the MD&A.
Exploration
In 2005, Cinch pursued the ongoing exploration evaluation of its core lands in the Kakwa, Chime and Musreau areas, along with establishing another significant land position in Dawson, British Columbia. The year was not without its challenges, as access to services in the drilling industry continued to be severely constrained, costs generally continued to escalate, and wet conditions in the field during the summer and warm weather in the winter delayed operations. Weather conditions have continued to affect operations, shortening the 2005 winter drilling season due to one of the warmest winters on record, and access to drilling equipment continues to be very tight.
Four wells were drilled at MUSREAU, primarily focused on the Falher formation. All four were cased as potential gas wells, the most prolific being the 07-03-62-06w6 well, which has gas pay in four different zones. The productive zone encountered Falher B, which AOF'd at 10 mmcfpd. This well, as are the 05-18-62-05w6 and 03-20-62-05w6 gas wells, has been tied in and is currently on production, although the 07-03 flow rate is constrained by facilities issues at this time. A fourth well at 06-17-62-05w6 was cased as a potential gas well after year end.
The Company also drilled 4 wells in the KAKWA area in 2005. The 12-18-61-04w6 well encountered a productive Dunvegan reservoir and has been tied in and now produces at rates according to our model. This success, along with that of 16-13-061-05w6 late in the prior year, encouraged us to drill three step out wells at high working interests. The Dunvegan sands were present in all three wells, however permeabilities were lower than anticipated. Cinch has two additional Dunvegan development locations budgeted for later in the 2006 year. Amendments to the current downspacing approvals have been filed with the AEUB for this area. In addition, the Kakwa area has witnessed significant success by offsetting operators in deeper horizons who have recently licensed 8 wells in the vicinity of the Company's acreage. Cinch is aware that additional wells are being licensed by other operators and expansions to the gathering and processing facilities are being proposed. Cinch has budgeted two wells in 2006 to date, which will also test these deeper horizons.
Cinch drilled 4 wells on the CHIME block, at an average working interest of 35.7 percent with three of these wells being exploratory in nature. Two wells were drilled to evaluate all zones down to and including the Cadomin formation and both were cased, completed and tied in as producing gas wells. Ultimate flow rates were less than expected, but valuable information into the subtleties shown on Cinch's 3-D seismic data set was collected which the Company hopes will result in a better success ratio in the future. A Cardium test was drilled at 02-27-60-05w6 and did not encounter the fault system which accounts for the prolifically productive Cardium trend to the southeast. A Dunvegan development well was drilled at 13-08-060-05w6 and is on production. The Company has budgeted two additional wells for 2006 in the CHIME area.
Prospects have been mapped on the CHIME EAST and KAKWA EAST acreage and were scheduled to be drilled in 2005, however a combination of unfavorable weather conditions and an inability to obtain drilling rigs prevented them from being drilled in 2005. Cinch now expects to spud the Chime East prospect in the summer and the Kakwa East prospect in the summer or during the 2006 winter drilling season.
The Company consummated a farmout arrangement at RESTHAVEN which saw a well drilled in the first quarter of 2006, with Cinch carried through completion. Cinch will have a 33.33% working interest in production. The well has been cased and is currently being completed. Results to date have been encouraging.
One well was drilled at BIGSTONE. The well will be tied in for production in the first quarter of 2006.
During 2005, Cinch joint ventured in the drilling of two wildcat exploration wells in the DAWSON CREEK WEST area in British Columbia. Participation in these wells earned Cinch an average 30% working interest in 27 sections of land. The Montney, Doig, Kiskatinaw and Notikewin formations are considered to be of primary attraction in the development of this new exploration area. One well was completed as a gas well, with additional seismic work and drilling being considered for the third quarter of 2006.
Undeveloped Land
Cinch's undeveloped land base of 108,307 gross acres (48,820 net acres) continues to represent a significant asset to the Company. Industry has paid record land prices during 2005 for undeveloped lands, particularly in the Deep Basin fairway, where Cinch operates. Prices at crown land sales in Cinch's core areas of Chime, Kakwa and Musreau averaged $2,400 per hectare ($960 per acre), with some lands directly offsetting Cinch's landholdings selling for as high as $6,100 per hectare ($2,440 per acre).
The Company has also developed a new exploration area in the Dawson West area of North East British Columbia, located approximately 10 kilometers north of the City of Dawson. Cinch holds an interest in 16,200 undeveloped gross acres (5,807 net acres) in this multi-zone area.
The Company has a high average net working interest of 45% on its undeveloped lands, the majority of which are operated by Cinch. This land position allows the Company to continue with an active exploration program without having to compete with industry at high priced land sales and to farmout a portion of our interest in the lands to manage risk where desired.
Undeveloped Land Holdings
December 31, December 31,
2005 2004
Gross Acres 108,307 92,907
Net Acres 48,820 44,616
Average Working Interest 45% 48%
RESERVES
The corporate reserves estimates, effective December 31, 2005, were prepared by the independent engineering firm of GLJ Petroleum Consultants Ltd. ("GLJ") in accordance with the definitions set out under National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities ("NI 51-101"). The reserve highlights are:
- Total proven reserves at December 31, 2005 increased 14% to
3.3 million BOE compared to 2.9 million BOE at December 31, 2004.
- Total proven plus probable reserves at December 31, 2005 increased
26% to 4.8 million BOE compared to 3.8 million BOE at December 31,
2004
- On a proven plus probable basis, the finding, development and
acquisition costs were $29.59 per BOE ($43.63 per BOE on a proven
basis)
- On a proven plus probable basis, the finding and development costs
were $34.71 per BOE ($52.92 per BOE on a proven basis).
FORECASTED PRICES AND COSTS
Summary of Oil and Gas Reserves - Gross Reserves(1)
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Light
and
Medium Natural Var
Crude Gas Natural Total Total (2005
Oil Liquids Gas 2005 2004 vs
(mbbls) (mmbls) (mmcf) (mboe) (mboe) 2004)
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Proved - Developed
Producing 39 533 14,078 2,919 2,395 524
- Developed
Non-Producing 26 30 1,529 311 467 (156)
- Undeveloped 2 2 268 49 0 49
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Total Proved 67 565 15,875 3,279 2,862 417
Probable 28 258 7,223 1,490 927 563
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Total Proved Plus Probable 96 823 23,097 4,768 3,789 979
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Note: May not add due to rounding
(1) "Gross" means the total working interest (operating and
non-operating) share before deduction of royalties payable to others
and without including any royalty interest of Cinch.
Net Present Value of Reserves Before Income Taxes - Forecasted Prices and
Costs
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Discounted at
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Undis-
December 31, counted 8% 10% 15% 20%
2005(1)(2)(3) ($M) ($M) ($M) ($M) ($M)
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Proved - Developed
Producing 92,818 62,700 58,571 50,819 45,341
- Developed
Non-Producing 8,911 6,230 5,804 4,966 4,348
- Undeveloped 368 62 6 (111) (202)
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Total Proved 102,097 68,992 64,381 55,674 49,487
Probable 44,776 17,668 15,326 11,498 9,154
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Total Proved Plus
Probable 146,873 86,661 79,706 67,171 58,641
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Note: May not add due to rounding
(1) Utilizing GLJ January 1, 2006 price forecast.
(2) As required by NI 51-101, undiscounted well abandonment costs of
$1.0 million for total proved reserves and $1.3 million for total
proved plus probable reserves are included in the Net Present Value
determination.
(3) Prior to provision of income taxes, interest, debt service charges
and general and administrative expenses. It should not be assumed
that the undiscounted and discounted future net revenues estimated by
GLJ represent the fair market value of the reserves.
Pricing Assumptions - Forecasted Prices and Costs
The January 1, 2006 pricing forecasts presented below have been prepared by GLJ. These prices have been utilized in determining the reserves and cash flow forecasts above.
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Natural
Oil Gas
Edmonton Alberta Pentanes
Par Price Plant Plus
40 degrees Gate (Then Propane Butane Edmonton
API Current) Edmonton Edmonton Light
Year ($CDN/Bbl) ($CDN/MMBtu) ($CDN/Bbl) ($CDN/Bbl) ($CDN/Bbl)
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2006 66.25 10.35 42.50 49.00 67.00
2007 64.00 9.00 41.00 47.25 65.25
2008 59.25 7.75 38.00 43.75 60.50
2009 55.75 7.25 35.75 41.25 56.75
2010 54.00 6.95 34.50 40.00 55.00
2011 52.25 6.65 33.50 38.75 53.25
2012 52.25 6.65 33.50 38.75 53.25
2013 53.25 6.80 34.00 39.50 54.25
2014 54.25 6.95 34.75 40.25 55.25
2015 55.50 7.15 35.50 41.00 56.50
2016 56.50 7.30 36.25 41.75 57.75
2017+ +2.0%/yr +2.0%/yr +2.0%/yr +2.0%/yr +2.0%/yr
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CONSTANT PRICES AND COSTS
Net Present Value of Reserves Before Income Taxes - Constant Prices and
Costs
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Discounted at
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Undis-
December 31, counted 8% 10% 15% 20%
2005(1)(2)(3) ($M) ($M) ($M) ($M) ($M)
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Proved - Developed
Producing 117,145 75,470 69,789 59,199 51,815
- Developed 11,735 7,819 7,214 6,040 5,189
Non-Producing
- Undeveloped 793 350 269 102 (26)
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Total Proved 129,672 83,638 77,271 65,341 56,979
Probable 54,586 23,002 19,972 14,900 11,749
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Total Proved Plus
Probable 184,259 106,640 97,242 80,241 68,727
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Note: May not add due to rounding
(1) Price assumptions: $68.27/Bbl Cdn Edmonton Light Sweet Crude,
$71.67/bbl Cdn. Edmonton Pentanes Plus and $9.46/mmbtu Cdn. Alberta
Plant Gate - Spot "then current".
(2) As required by NI 51-101, undiscounted well abandonment costs of
$0.72 million for total proved reserves and $0.80 million for total
proved plus probable reserves are included in the Net Present Value
determination.
(3) Prior to provision of income taxes, interest, debt service charges
and general and administrative expenses. It should not be assumed
that the undiscounted and discounted future net revenues estimated by
GLJ represent the fair market value of the reserves.
RESERVE RECONCILIATION
Reconciliation of Company Interest(1) Reserves by Principal Product Type -
Forecast Prices and Costs
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Crude Oil NGL's
(mbbls) (mbbls)
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Total Total
Proved Proved
Plus Plus
Proved Probable Proved Probable
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Opening Balance
December 31, 2004 0.0 0.0 535.4 691.8
Technical (0.9) (0.9) (23.9) (18.3)
Exploration Discoveries 0.0 0.0 0.4 0.5
Drilling Extensions 0.0 0.0 21.0 28.2
Infill Drilling 0.0 0.0 87.1 165.8
Improved Recovery 0.0 0.0 0.0 0.0
Acquisition 68.4 96.5 25.0 34.7
Production 0.0 0.0 (79.4) (79.4)
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Closing Balance
December 31, 2005 67.5 95.6 565.5 823.2
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Natural Gas Equivalent
(mmcf) (mboe)
------------------------------------------------
Total Total
Proved Proved
Plus Plus
Proved Probable Proved Probable
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Opening Balance
December 31, 2004 13,982.0 18,606.5 2,865.7 3,792.8
Technical 182.0 198.3 5.5 13.8
Exploration Discoveries 68.2 91.0 11.7 15.6
Drilling Extensions 1,553.7 2,160.4 279.9 388.3
Infill Drilling 1,986.5 3,732.0 418.2 787.8
Improved Recovery 0.0 0.0 0.0 0.0
Acquisition 563.7 768.5 187.4 259.3
Production (2,364.5) (2,364.5) (473.5) (473.5)
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Closing Balance
December 31, 2005 15,971.6 23,192.2 3,294.9 4,784.2
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Note: May not add due to rounding
(1) Company interest reserves means the total working interest (operating
and non-operating) share before deduction of royalties payable to
others and including royalty interests of Cinch.
Reconciliation of Company Net Reserves(1)
By Principal Product Type - Forecast Prices and Costs
ASSOCIATED AND
LIGHT AND MEDIUM OIL NON-ASSOCIATED GAS
------------------------- -------------------------
Net Net
Proved Proved
Net Net Plus Net Net Plus
Proved Probable Probable Proved Probable Probable
FACTORS (mbbl) (mbbl) (mbbl) (mmcf) (mmcf) (mmcf)
------------------- ------- ------- ------- ------- ------- -------
December 31, 2004 0 0 0 10,024 3,343 13,367
Extensions 0 0 0 1,333 479 1,812
Infill Drilling 0 0 0 1,629 1,275 2,904
Improved Recovery 0 0 0 0 0 0
Technical Revisions 0 0 0 305 11 316
Discoveries 0 0 0 55 18 73
Acquisitions 55 23 79 380 137 517
Dispositions 0 0 0 0 0 0
Economic Factors 0 0 0 -5 -2 -7
Production 0 0 0 -1,703 0 -1,703
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December 31, 2005 55 23 79 12,019 5,262 17,281
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NATURAL GAS LIQUIDS
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Net
Proved
Net Net Plus
Proved Probable Probable
FACTORS (mbbl) (mbbl) (mbbl)
------------------- ------- ------- -------
December 31, 2004 331 101 432
Extensions 17 5 22
Infill Drilling 60 48 108
Improved Recovery 0 0 0
Technical Revisions -2 2 -1
Discoveries 0 0 0
Acquisitions 16 6 22
Dispositions 0 0 0
Economic Factors -1 0 -1
Production -55 0 -55
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December 31, 2005 367 162 529
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(1) Net reserves means the Company's interest (operating and non
operating) share after deduction of royalty obligations, plus the
Company's royalty interest in production or reserves.
Finding and Development Costs (F&D) and Finding, Development and Net
Acquisition Costs (FD&A)
NI 51-101 specifies how finding and development ("F&D") costs should be calculated if they are reported. Essentially NI 51-101 requires that the exploration and development costs incurred in the year along with the change in estimated future development costs be aggregated and then divided by the applicable reserve additions. The calculation specifically excludes the effects of acquisitions and dispositions on both reserve and costs. By excluding the effects of acquisitions and dispositions Cinch believes that the provisions of NI 51-101 do not fully reflect Cinch's ongoing reserve replacement costs. Since acquisitions can have a significant impact on Cinch's annual reserve replacement costs, to not include these amounts could result in an inaccurate portrayal of Cinch's cost structure. Accordingly, Cinch will also report finding, development and acquisition ("F,D&A") costs that will incorporate all acquisitions net of any dispositions during the year.
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2005 2004 3 year average
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Proven + Proven + Proven +
Proven Probable Proven Probable Proven Probable
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Capital ($'000s)
Exploration and
development(1) 36,045 36,045 16,050 16,050 20,945 20,945
Acquisition
capital 1,515 1,515 49,645 49,645 17,145 17,145
Change in future
capital 1,796 5,638 926 926 698 2,018
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Total capital
including change
in future capital 39,356 43,198 66,621 66,621 38,788 40,108
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Total capital
excluding goodwill 39,356 43,198 52,005 52,005 33,916 35,236
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Reserve additions
(mboe)
Exploration and
development 715 1,201 1,270 1,503 689 820
Acquisition 187 259 1,342 1,810 512 693
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Total reserve
additions (mboe) 902 1,460 2,612 3,313 1,201 1,512
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Costs ($/boe)
F&D 52.92 34.71 13.37 11.29 31.41 28.02
FD&A 43.63 29.59 25.51 20.11 32.30 26.52
FD&A excluding
goodwill 43.63 29.59 19.91 15.70 28.24 23.30
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Note: May not add due to rounding
(1) The aggregate of the exploration and development costs incurred in
the most recent financial year and the change during that year in
estimated future development costs generally will not reflect total
finding and development costs related to reserves additions for that
year.
Production & Reserve Life Index
The Company's reserve life index using annualized fourth quarter production is 7.3 years for proven BOE reserves compared to 8.0 years in 2004 and 10.5 years for proven plus probable BOE reserves compared to 10.6 years in 2004.
Cinch exited the year at approximately 1,250 BOED.
A multi-well compressor was installed in December 2004 in the north Kakwa field to assist in maintaining production rates from the 04-07-62-04 W6M and 02-18-62-04 W6M wells and to minimize downtime due to fluctuations in line pressure and start-up of new wells into the main gathering system. This reduced the total downtime the Company was exposed to in 2005 as a result of these issues, although it did not completely eliminate them as high industry activity levels has placed pressure on infrastructure. This multi-well compressor is also expected to accommodate new production from the drilling associated with the approval of the holding application for the north Kakwa production.
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2005 2004
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Calculated using:
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Annualized Annualized
Q4 Average Q4 Average
Production Production Production Production
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Production (boe/d) 1,245 1,297 981 525
Proved reserves (mboe)(1) 3,295 3,295 2,866 2,866
Proved reserve life index
(years) 7.3 7.0 8.0 15.0
Proved plus probable
reserves (mboe)(1) 4,784 4,784 3,793 3,793
Proved plus probable reserve
life index (years) 10.5 10.1 10.6 19.8
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(1) Company interest reserves means the total working interest (operating
and non-operating) share before deduction of royalties payable to
others and including royalty interests of Cinch.
Reserve Replacement
The Company's 2005 capital investment program replaced 2005 average production by a factor of 1.9 times on a proved basis and 3.1 times on a proved plus probable basis.
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2005 2004
2005 (Annualized 2004 (Annualized
(average) Q4) (average) Q4)
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Production (mboe) 473.4 454.3 192 358
Proved reserve additions
after revisions of prior
periods (mboe) 902 902 2,612 2,612
Proven replacement ratio 1.9 2 13.6 7.3
Proved plus probable reserve
additions after revision
of prior periods (mboe) 1,460 1,460 3,313 3,313
Proved plus probable
replacement ratio 3.1 3.2 17.3 9.3
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Recycle Ratio
The recycle ratio is a measure for evaluating the effectiveness of a company's re-investment program. The ratio measures the efficiency of capital investment. It accomplishes this by comparing the operating netback per barrel of oil equivalent to that year's reserve finding and development costs. Cinch Energy presents the recycle ratio on both an FD&A basis (based on 2005 actual FD&A) and an F&D basis.
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2005 2005 2004 2004
(FD&A) (F&D) (FD&A) (F&D)
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Operating netbacks ($/BOE) 36.92 36.92 25.63 25.63
Proved finding, development
and net acquisition costs
after revision of prior
periods and including the
change in future development
capital ($/BOE) 43.63 52.92 25.51 13.37
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Proved recycle ratio 0.9 0.7 1.0 1.9
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Proved plus probable finding,
development and acquisition
costs after revisions of
prior periods and including
the change in future
development capital ($/BOE) 29.59 34.70 20.11 11.29
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Proved plus probable recycle
ratio 1.2 1.1 1.3 2.3
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Note: May not add due to rounding
OUTLOOK
The outlook for Cinch's lands is promising as Cinch will continue to test new prospects in its core areas. These areas have witnessed a tremendous amount of drilling activity throughout the 2005 year leading to a new gas plant being built and an additional small gas plant being expanded to accommodate the new production growth. In addition, numerous operators have applied for permission for down-sized drilling spacing in the Musreau and Kakwa areas. These applications, along with continued drilling success, will lead to additional drilling on Cinch's land base. In the Musreau area alone, the Company has identified the possibility of 20 down-spaced locations for the future. With these down-spacing opportunities and multizone potential, Cinch's management compares the future potential in Cinch's core area to the very active Berland River, Leland, and Wild River areas to the south east and the Redrock and Wapiti areas to the northwest, all within the Deep Basin trend.
Cinch exited the 2005 year in a very strong financial position with positive working capital of $3.5 million and an unused line of credit of $26.5 million. The Company has budgeted for approximately $44 million of capital expenditures in 2006, directed mainly at exploratory and development drilling, to be funded from projected cash flow and existing lines of credit. The timing of budgeted expenditures has been revised due to delays in the winter drilling program. As a result, the Company is currently forecasting production for 2006 to average 1300 boe/d, with a projected exit rate in the range of 1600 to 1800 boe/d. A significant factor in the above noted delays has been difficulties in obtaining access to rigs and in order to provide a level of certainty on rig availability, Cinch expects to enter into a one year contract for a rig with a drilling contractor.
Currently, the Company has one well drilling at Musreau 2-34 (30%), and is participating in three additional wells which are preparing to spud at Kakwa.
As part of its business plan, the Company continues to evaluate acquisition opportunities which would provide growth and complement management's expertise. The goal is to develop a broader production base for the Company from which it can fund the future growth in its Deep Basin core area.
Most recent trends in industry include a rising cost structure along with a decline in natural gas prices, the latter associated with the warm winter and the buildup in gas storage reserves. Overall, Cinch expects that prices will improve again over the intermediate term. Management takes a longer term view and does not take a "quarter to quarter" approach in its exploration programs. In spite of the challenges that the Company faced in 2005, Cinch management remains very positive that its excellent land position in a currently very active exploration area will provide the future growth for the Company.
Other Information
Common shares of Cinch trade on the Toronto Stock Exchange under the symbol of "CNH". Additional information relating to the Company is available on SEDAR at www.sedar.com. The Company expects to mail out its Annual Report to shareholders on March 31, 2006. The Annual and Special Meeting will be held on the 18th day of May, 2006 at 2:30 p.m. (Calgary time) in the Great Room 3 at the Sandman Hotel Calgary, 888 - 7th Avenue SW, Calgary, AB.
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 6 mcf to 1 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 MD&A 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, production estimates and expected production rates, timing of tie ins and the effect of delays in tieing in wells and the effects of third party compressor issues and other infrastructure issues, levels of decline rates and the effects thereof, expected royalty rates, general and administrative expenses and other expenses, effects of the results of successful wells, level of capital expenditures and the method of funding of capital expenditures, the ability to incur qualifying expenditures renounceable to purchasers of flow-through shares and the expected levels of activities and results of operations of the Company may constitute forward-looking statements under applicable securities laws and necessarily involve risks including, without limitation, risks associated with oil and gas exploration, development, exploitation, production, marketing and transportation, loss of markets, volatility of commodity prices, currency fluctuations, 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 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 effect 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 MD&A are made as at the date of this MD&A 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
March 8, 2006
The following management's discussion and analysis ("MD&A") should be read in conjunction with Cinch Energy Corp.'s ("Cinch" or the "Company") audited financial statements for the years ended December 31, 2005 and 2004. This commentary is based on the information available as at, and is dated, March 8, 2006. Additional information relating to Cinch, including Cinch's Annual Information Form when filed, is 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.
Growth Strategy
Cinch focuses on drilling as a means for achieving growth, and management believes that this is a viable and ultimately cost effective strategy. Management also believes that strategic acquisitions can and should play a part in our growth, where such acquisitions fit with and/or complement our own assets, or where they provide a balance to our existing program.
Throughout 2005, the Company focused on its programs in the Chime, Kakwa, Musreau and Bigstone areas as well as the Peace River Arch area of British Columbia by drilling and tieing-in production.
Growth cannot be achieved without the right people, and Cinch has assembled a management team comprised of experienced and knowledgeable individuals, very familiar with the Deep Basin.
SALES
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Three Months Ended Year Ended
December 31, December 31,
2005 2004 Change 2005 2004 Change
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Sales volumes % %
Natural gas (mcf/d) 6,248 4,953 26 6,478 2,707 139
Liquids (bbl/d) 203 155 31 217 73 196
Equivalence (BOE/d) 1,245 981 27 1,297 525 147
Sales prices $ $ % $ $ %
Natural gas 12.44 7.29 71 9.59 6.97 38
Liquids 62.69 49.66 26 59.83 48.68 23
Equivalence 72.68 44.70 63 57.90 42.79 35
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Volumes
Sales volumes for the three months ended December 31, 2005 increased 27% over the comparable period in 2004 as a result of successful drilling results, with 13 new wells (7 net) commencing production in the year, 4 (2 net) of those coming on production in the fourth quarter.
Sales volumes in the fourth quarter of 2005 are fairly flat compared to the third quarter of 2005, as production additions were offset by natural declines. In the fourth quarter of 2005, the Company experienced tie-in delays and ongoing third party compressor issues in the Chime/Musreau/Kakwa areas. The Company has been installing compression on its operated locations to alleviate compression problems, which has helped, however system-wide issues on infrastructure controlled by third parties continue to sporadically impact the Company although to a lesser extent than in the third quarter. The Chime/Kakwa/Musreau areas have become much more active over the past two years, increasing pressure on infrastructure, challenged further by tight industry service conditions. However, the high activity levels have also increased third party interest in building facilities and infrastructure and this is expected to alleviate these issues over time.
Sales volumes for the year ended December 31, 2005 increased 147% over the comparable period in 2004 as a result of production additions in 2005 and the acquisition of the Canadian assets of Rio Alto Resources International Inc. ("Rio Alto") on August 12, 2004.
The Company's production is primarily from deep, tight gas, which will experience fairly high decline rates in the first two years, with decline rates typically reducing and stabilizing thereafter. As the Company builds a larger base of production, reflected in higher average production rates, declines on new production should have a less significant impact and a higher portion of capital should be spent on production growth versus replacing declines. Although the production base for the Company has improved in 2005 over 2004, reflected by average production of 1,297 BOE/d versus 525 BOE/d in 2004, management had forecast higher production averages. Several items, however, impacted the results, including the payout of two significant wells earlier than anticipated as a result of continued high gas prices (resulting in a reduction of approximately 77 BOE/d for the year as well as the elimination of gross overriding royalties for these wells), delays as a result of warm weather and soft field conditions, difficulties in accessing services including lack of availability of rigs, and lower than anticipated results on higher working interest wells in the Kakwa pool. The Company currently has two locations planned for Kakwa in 2006, at a lower working interest to mitigate risk.
Cinch exited the year with production of approximately 1,250 BOE/d.
The Company has a number of locations planned for drilling in 2006. We do anticipate that some of the challenges incurred in 2005 will continue into 2006, however, we do not anticipate that all locations to be drilled in 2006 will be affected. The Company continues to work on strategies where possible to reduce the impact of lack of availability of rigs, delays in government approvals, and warm weather which impacts location access.
Natural gas prices have remained strong throughout 2005, particularly in the second half of the year, and have significantly increased when compared to the same periods of 2004. It is anticipated that prices in the first quarter of 2006 will be lower than the last quarter of 2005. The Company's production continues to be unhedged and is marketed in the Alberta spot market.
Natural gas liquids pricing has also remained very strong and has also increased significantly when compared to the same periods of 2004. The Company has not hedged any of its liquids production.
REVENUES
Dollars in thousands, except per unit amounts
-------------------------------------------------------------------------
Three Months Ended Year Ended
December 31, December 31,
2005 2004 Change 2005 2004 Change
-------------------------------------------------------------------------
$ $ % $ $ %
Oil and gas sales,
net of
transportation 8,323 4,033 106 27,413 8,215 234
Per BOE 72.68 44.70 63 57.90 42.79 35
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Revenues for the three months and the year ended December 31, 2005 are higher than the same periods of 2004 due to increased production levels and increased commodity prices. Revenues during the fourth quarter of 2005 have increased by 15% compared to the third quarter of 2005, due to higher commodity prices. Transportation expenses as a percentage of revenues for the three months and year ended December 31, 2005 have remained consistent at approximately 3% when compared to the same periods of 2004, as expected.
ROYALTIES
Dollars in thousands, except per unit amounts
-------------------------------------------------------------------------
Three Months Ended Year Ended
December 31, December 31,
2005 2004 Change 2005 2004 Change
-------------------------------------------------------------------------
$ $ % $ $ %
Royalties, net of
ARTC 2,109 1,211 74 7,213 2,205 227
Per BOE 18.42 13.43 37 15.23 11.48 33
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Royalty expense, net of Alberta Royalty Tax Credit, increased in the three months and year ended December 31, 2005 compared to the same periods of 2004 due to higher production levels and prices. The Company's royalty rate (royalties net of ARTC as a percentage of oil and gas sales) has remained consistent over the two years between 26% and 27%. The royalty rate for the first six months of 2006 is expected to be slightly lower after accounting for the benefits from the Alberta Royalty Tax Credit, increasing in the second half of the year once the maximum ARTC has been earned. The Company anticipates that its royalty rate in 2006 will be slightly lower than that of 2005.
OTHER INCOME
Dollars in thousands, except per unit amounts
-------------------------------------------------------------------------
Three Months Ended Year Ended
December 31, December 31,
2005 2004 Change 2005 2004 Change
-------------------------------------------------------------------------
$ $ % $ $ %
Other income 99 5 1,880 156 145 8
Per BOE 0.87 0.06 1,350 0.33 0.76 (57)
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-------------------------------------------------------------------------
Other income is comprised of interest income and gross overriding royalty revenue earned in 2005. The increase in other income in the three months and year ended December 31, 2005 compared to the same periods in 2004 is due to royalty revenue ($45 thousand) earned in 2005 which was not earned in 2004 and interest income ($111 thousand) earned on proceeds received from the September, 2005 private placement. In 2004, interest income was earned primarily on subscription receipt proceeds raised in a private placement in order to acquire Rio Alto's Canadian assets in August, 2004. These funds had been fully expended by the end of the third quarter of 2004. The Company anticipates that it will earn interest income in the first quarter of 2006 but that it will commence drawing on its credit facilities in the second quarter of 2006, thereby incurring interest expense.
OPERATING EXPENSES
Dollars in thousands, except per unit amounts
-------------------------------------------------------------------------
Three Months Ended Year Ended
December 31, December 31,
2005 2004 Change 2005 2004 Change
-------------------------------------------------------------------------
$ $ % $ $ %
Operating 633 462 37 2,722 1,090 150
Per BOE 5.53 5.12 8 5.75 5.68 1
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Total operating expenses increased in the three months and year ended December 31, 2005 compared to the same periods in 2004 primarily as a result of higher production levels. Operating expenses per BOE in the fourth quarter of 2005 are lower than for the full year of 2005 as additional operating expenses were incurred in the second and third quarters of 2005 on plant turnarounds, repairs and maintenance, freight and hauling, and wireline costs.
For the year ended December 31, 2005, operating expenses on a BOE basis are only slightly higher than 2004. There is no single factor which identifies the slight increase other than additional expenditures incurred in the second and third quarters of 2005 as noted above, offset by efficiencies achieved from higher production levels.
Operating expenses are not expected to exceed $6.50 per BOE in 2006
GENERAL AND ADMINISTRATIVE EXPENSES
Dollars in thousands, except per unit amounts
-------------------------------------------------------------------------
Three Months Ended Year Ended
December 31, December 31,
2005 2004 Change 2005 2004 Change
-------------------------------------------------------------------------
$ $ % $ $ %
General and
administrative 912 490 86 2,749 1,463 88
Per BOE 7.96 5.43 47 5.81 7.62 (24)
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Total general and administrative costs have increased for the three months and year ended December 31, 2005 compared to the same periods of 2004 as a result of increased activity in 2005. The Company hired 4 additional employees, and increased compensation for existing staff in order to be more competitive in the marketplace, resulting in compensation and consulting fees increasing approximately 67% from $1.2 million in 2004 to $2.0 million in 2005. In addition, stock based compensation expense increased by $299 thousand due to options granted to new employees and additional options issued to existing employees in 2005. As at March 8, 2006, the Company has 2,453,000 options outstanding amounting to approximately 5% of issued shares and special warrants. Public company-related expenses such as audit fees, legal fees, stock exchange fees, press release and printing fees also increased from $105 thousand to $290 thousand, and office rent increased $100 thousand due to larger office premises obtained necessary to accommodate increased staff levels.
For the year ended December 31, 2005, general and administrative expenses per BOE have decreased compared to 2004 due to increased production levels in 2005. General and administrative costs per BOE have increased for the three months ended December 31, 2005 compared to the same period in 2004 due to increased employment costs in 2005.
General and administrative costs are not expected to exceed $5.25 per BOE in 2006
INTEREST EXPENSE
Dollars in thousands, except per unit amounts
-------------------------------------------------------------------------
Three Months Ended Year Ended
December 31, December 31,
2005 2004 Change 2005 2004 Change
-------------------------------------------------------------------------
$ $ % $ $ %
Interest expense 6 74 (92) 299 87 244
Per BOE 0.05 0.82 (94) 0.63 0.46 37
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Interest expense increased for the year ended December 31, 2005 compared to 2004 due to increased draws on the credit facility primarily in the first eight months of 2005. The Company completed a private placement in September, 2005 for gross proceeds of $22.5 million and eliminated its debt, thereby reducing its interest expense in the three months ended December 31, 2005. For the three months ended December 31, 2004, the Company had been drawn on its credit facility, thereby incurring interest expense.
The Company exited the year with positive net working capital and expects to draw on its $26.5 million credit facility in approximately the second quarter of 2006 to fund its capital program.
ACCRETION OF ASSET RETIREMENT OBLIGATIONS EXPENSE
Dollars in thousands, except per unit amounts
-------------------------------------------------------------------------
Three Months Ended Year Ended
December 31, December 31,
2005 2004 Change 2005 2004 Change
-------------------------------------------------------------------------
$ $ % $ $ %
Accretion expense 45 36 25 158 81 95
Per BOE 0.40 0.39 3 0.33 0.42 (21)
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Accretion expense increased for both the three months and year ended December 31, 2005 as a result of new locations drilled and gathering systems built for which an asset retirement obligation will be incurred, and as a result of asset retirement obligations acquired on the purchase of an interest in 10 wells in December 2005, resulting in a net increase of $254 thousand to the asset retirement obligation.
DEPLETION AND DEPRECIATION EXPENSE
Dollars in thousands, except per unit amounts
-------------------------------------------------------------------------
Three Months Ended Year Ended
December 31, December 31,
2005 2004 Change 2005 2004 Change
-------------------------------------------------------------------------
$ $ % $ $ %
Depletion and
depreciation 2,697 1,434 88 9,257 3,128 196
Per BOE 23.55 15.89 48 19.55 16.29 20
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Depletion and depreciation expense increased for the three months and year ended December 31, 2005 compared to the same periods of 2004 as the Company has a larger capital base being depleted and higher production levels.
Depletion per BOE has increased from the prior year due to a larger capital base being depleted, partially offset by net proven reserve additions of 5.4 Bcf for the year ended December 31, 2005 and 2.8 Bcf for the three months ended December 31, 2005.
TAXES
Dollars in thousands, except per unit amounts
-------------------------------------------------------------------------
Three Months Ended Year Ended
December 31, December 31,
2005 2004 Change 2005 2004 Change
-------------------------------------------------------------------------
$ $ % $ $ %
Current 18 (4) (550) 98 13 654
Future income taxes 637 148 330 1,710 193 786
Per BOE 5.72 1.59 260 3.82 1.08 254
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Current taxes in the three months and year ended December 31, 2005 and 2004 is comprised of Large Corporations Tax (LCT), which increased over the prior year due to increased share capital, primarily warrants exercised in the first half of the year for gross proceeds of approximately $19.1 million and gross proceeds of approximately $22.5 million (2004- $50.6 million) received from a private placement in September, 2005. The Company was not liable for this tax for the first seven months of 2004 as it had a lower capital base and became liable for LCT only after the Rio Alto acquisition in August, 2004.
Future income taxes in the three months and year ended December 31, 2005 arose as the Company earned income which was offset for tax purposes by drawing down its tax pools. The Company had tax pools of $57.2 million outstanding at December 31, 2005 (December 31, 2004 - $37.5 million).
NET INCOME AND FUNDS FROM OPERATIONS
Dollars in thousands, except per share figures
-------------------------------------------------------------------------
Three Months Ended December 31,
2005 2004 Change
-------------------------------------------------------------------------
$ $ %
Net income 1,364 189 622
per basic share 0.03 0.01 200
per diluted share 0.03 0.01 200
Funds from operations 4,899 1,924 155
per basic share 0.10 0.06 67
per diluted share 0.10 0.05 100
Weighted average shares & special
warrants outstanding 47,812,632 33,331,193 43
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Year Ended December 31,
2005 2004 Change
-------------------------------------------------------------------------
$ $ %
Net income 3,364 99 3,298
per basic share 0.08 0.00 1,597
per diluted share 0.08 0.00 1,684
Funds from operations 15,042 3,757 300
per basic share 0.38 0.19 103
per diluted share 0.36 0.17 112
Weighted average shares & special
warrants outstanding 40,046,588 20,054,494 100
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Net income increased for the three months and year ended December 31, 2005 when compared to the same periods of 2004 due to higher production levels and higher sales prices.
Funds from operations for the three months and year ended December 31, 2005 have significantly increased compared to the same periods of 2004 as a result of higher production, attributable to drilling results and the acquisition of the Rio Alto assets in August 2004, and as a result of higher commodity prices. Net income and funds from operations were also higher in the fourth quarter of 2005 compared to prior quarters of 2005 due to higher commodity prices.
LIQUIDITY AND CAPITAL RESOURCES
Dollars in thousands
-------------------------------------------------------------------------
As at December 31,
2005 2004 Change
-------------------------------------------------------------------------
$ $ %
Working capital (deficiency) 3,490 (4,795) 173
Credit facility - (9,964) 100
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Net working capital (deficiency) 3,490 (14,759) 124
Capital lease obligation 421 621 (32)
Shareholders' equity 93,400 48,335 93
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Shareholder's equity and net working capital have increased in 2005 compared to 2004 due to equity issued during the year. Warrants exercised in the first half of the year provided gross proceeds of $19.1 million to the Company in exchange for 8,022,529 common shares issued. The Company also completed a private placement in September providing gross proceeds of $22.5 million in exchange for 6,029,413 common shares issued. The proceeds received from the September 2005 financing were used to fund capital spending for the fourth quarter and to completely pay down the credit facility. The Company exited the year with positive net working capital.
Looking forward, the Company anticipates funding its capital program with a combination of funds generated from operations and its $26.5 million credit facility.
CAPITAL EXPENDITURES
Additions to property, plant and equipment
Dollars in thousands
-------------------------------------------------------------------------
Year Ended December 31,
2005 2004
-------------------------------------------------------------------------
Land and rentals 4,083 133
Seismic 796 842
Drilling, completing and equipping 26,046 12,695
Pipelines and facilities 5,038 2,310
Other assets 82 69
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Total 36,045 16,049
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Capital expenditures for the year ended December 31, 2005, were incurred primarily on drilling, completing and tieing-in locations in the Chime, Kakwa, Musreau, Bigstone areas and the Peace River Arch area of British Columbia.
Management's primary strategy is to expend capital on exploration and development drilling and earn land by drilling. The Company may, however, also purchase land where considered strategic.
In December 2005, the Company expended $4 million at a public property auction, acquiring a 25% working interest in 10 wells (3 producing at December 31, 2005) and 7.25 sections (gross) of land in the Kakwa area. In 2005, the Company also purchased an additional 2.25 sections (net) in the Kakwa area, an increasingly competitive area. The Company also purchased land in the Dawson West area, a new area for the Company, acquiring working interests between 20% and 40% in 18 sections of land. The Company subsequently earned the rights to an additional 9 sections (gross) of land in Dawson West by drilling two wells. The Company is performing additional geological and geophysical appraisals with the anticipation that another well will be drilled on these lands during the second or third quarter of 2006. Successful results would help in establishing another core area for the Company.
Tax pools at December 31, 2005:
Dollars in thousands
2005 2004
-------------------------------------------------------------------------
COGPE 7,620 4,172
CDE 18,412 13,041
CEE 15,723 11,287
Tangibles 15,488 9,049
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57,243 37,549
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The Company's tax pools increased significantly in 2005 as a result of capital expenditures which were higher than the amount needed to eliminate taxable income. The equity financing completed in September 2005 included flow through common shares of $10 million. As at December 31, 2005, $2.6 million of the required expenditures had been incurred and the full $10 million was renounced in February 2006. The Company anticipates no difficulties incurring the remaining $7.4 million expenditures in 2006. A future tax liability will be recorded in the first quarter of 2006 to reflect 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 2500 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.
DISCLOSURE CONTROLS AND PROCEDURES
The Company has established disclosure controls and procedures to provide reasonable assurance that material information required to be disclosed is recorded, processed, summarized and reported within the time periods specified by securities regulations and that information required to be disclosed is communicated to management on a timely basis. The Chief Executive Officer and the Chief Financial Officer have evaluated the effectiveness of these controls and procedures and have concluded that they are adequate and effective as at the end of the period covered by this management discussion and analysis, in all material respects.
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 dried out. 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. Cinch has assembled a large, contiguous block of land which is still relatively unexplored and has entered into a new play in British Columbia. The Company has a strong balance sheet and with prudent risk management, careful evaluation of results, continued development of the lands as well as expansion into new 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 assumed various contractual obligations and commitments in the normal course of its operating and financing activities. These obligations and commitments have been considered when assessing the Company's cash requirements in its analysis of future liquidity.
Dollars in thousands
-------------------------------------------------------------------------
Payments
greater
less than 1-3 4-5 than
Total 1 year years years 5 years
-------------------------------------------------------------------------
$ $ $ $ $
Capital lease obligation 631 210 421 - -
Operating lease 672 163 509 - -
Asset retirement
obligations 2,726 223 129 - 2,374
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4,029 596 1,059 - 2,374
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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 accounting 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 and will be applicable to all companies.
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 2005, the Company has been active in drilling and completing wells, as well as tie-ing in production, generating both positive net income and increasing cash flows. The Company's asset base continues to grow with a total of $37.3 million spent on capital expenditures and acquisitions in 2005. Throughout 2005, the Company has been faced with several challenges, causing drilling, completion and tie-in activities to be delayed toward the end of 2005 and pushed into 2006. The Company's business is affected by seasonal temperature changes. 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, the Company encountered further delays due to lack of rig availability, thereby pushing some planned drilling activity into the first, second and third quarters of 2006.
When comparing 2005 to 2004, revenues and funds from operations as well as net income have increased 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. The increase in income and funds from operations have also led to increased earnings per share and increased cash flows per share when compared to 2004.
SELECTED ANNUAL AND QUARTERLY INFORMATION
(000's, except per share and production data)
-------------------------------------------------------------------------
Q1 Q2 Q3 Q4 Annual
-------------------------------------------------------------------------
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
Net working capital
(deficiency) (16,621) (3,670) 10,629 3,490 3,490
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Production (BOE/d) 1,421 1,264 1,262 1,245 1,297
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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
Net working capital
(deficiency) 990 109 (6,011) (14,759) (14,759)
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Production (BOE/d) 204 216 691 981 525
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2003 $ $ $ $ $
-------------------------------------------------------------------------
Petroleum and natural
gas sales, net of
transportation and
before royalties 813 482 343 274 1,912
Funds from operations 478 270 47 (2) 793
Per share - basic 0.07 0.04 0.01 (0.00) 0.09
- diluted 0.07 0.03 0.01 (0.00) 0.09
Net income (loss) (60) 191 (107) (4,197) (4,173)
Per share - basic (0.01) 0.02 (0.01) (0.40) (0.49)
- diluted (0.01) 0.02 (0.01) (0.40) (0.49)
Capital expenditures 1,530 3,394 2,808 3,395 11,128
Total assets 13,234 13,655 14,731 13,615 13,615
Net working capital
(deficiency) 2,659 (465) 937 2,526 2,526
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Production (BOE/d) 182 126 98 85 124
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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
CINCH ENERGY CORP.
BALANCE SHEETS
As at December 31, 2005 2004
$ $
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ASSETS (note 6)
Current
Cash and cash equivalents (note 3) 5,654,594 -
Accounts receivable (note 4) 6,510,076 5,359,644
Prepaid expenses and deposits 752,551 729,502
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12,917,221 6,089,146
Property, plant and equipment (note 5) 86,085,917 56,854,192
Goodwill (note 5) 14,616,996 14,616,996
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113,620,134 77,560,334
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LIABILITIES AND SHAREHOLDERS' EQUITY
Current
Accounts payable and accrued liabilities 9,211,400 10,664,541
Income taxes payable 5,405 13,110
Credit facility (note 6) - 9,963,616
Current portion of capital lease obligation
(note 7) 210,007 206,921
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9,426,812 20,848,188
Capital lease obligation (note 7) 420,988 620,764
Asset retirement obligations (note 8) 2,725,627 1,633,234
Future income tax liability (note 9) 7,646,760 6,123,388
-------------------------------------------------------------------------
20,220,187 29,225,574
-------------------------------------------------------------------------
Commitments (note 11)
Shareholders' equity
Share capital (note 10) 93,044,644 51,840,767
Contributed surplus (note 10) 1,250,842 753,449
Deficit (895,539) (4,259,456)
-------------------------------------------------------------------------
93,399,947 48,334,760
-------------------------------------------------------------------------
113,620,134 77,560,334
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes
On behalf of the Board:
Director Director
CINCH ENERGY CORP.
STATEMENTS OF OPERATIONS AND DEFICIT
For the years ended December 31, 2005 2004
$ $
-------------------------------------------------------------------------
Revenue
Oil and gas sales 28,282,556 8,507,486
Transportation (869,753) (292,773)
Royalties, net of Alberta Royalty Tax Credit (7,212,766) (2,205,060)
Other income 155,697 145,083
-------------------------------------------------------------------------
20,355,734 6,154,736
-------------------------------------------------------------------------
Expenses
Operating 2,721,887 1,089,768
General and administrative (note 10) 2,748,928 1,462,605
Interest on credit facility (note 6) 276,577 87,366
Interest on capital lease (note 7) 22,274 -
Accretion of asset retirement obligations
(note 8) 157,849 81,149
Depletion and depreciation 9,256,752 3,127,970
-------------------------------------------------------------------------
15,184,267 5,848,858
-------------------------------------------------------------------------
Income before taxes 5,171,467 305,878
Taxes (note 9)
Current 97,650 13,150
Future income taxes 1,709,900 193,486
-------------------------------------------------------------------------
1,807,550 206,636
-------------------------------------------------------------------------
Net income for the year 3,363,917 99,242
Deficit, beginning of year (4,259,456) (4,358,698)
-------------------------------------------------------------------------
Deficit, end of year (895,539) (4,259,456)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Net income for the year per share (note 10)
Basic and diluted 0.08 0.00
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Weighted average number of shares outstanding
(note 10)
Basic 40,046,588 20,054,494
Diluted 41,921,643 22,068,795
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes
CINCH ENERGY CORP.
STATEMENTS OF CASH FLOWS
For the years ended December 31, 2005 2004
$ $
-------------------------------------------------------------------------
Operating activities
Net income for the year 3,363,917 99,242
Add non-cash items:
Depletion and depreciation 9,256,752 3,127,970
Accretion of asset retirement obligations 157,849 81,149
Non-cash compensation expense (note 10) 553,866 254,705
Future income taxes 1,709,900 193,486
-------------------------------------------------------------------------
Funds from operations 15,042,284 3,756,552
Net change in non-cash working capital (722,225) (1,467,607)
-------------------------------------------------------------------------
Cash provided by operating activities 14,320,059 2,288,945
-------------------------------------------------------------------------
Investing activities
Additions to property, plant and equipment (36,045,324) (16,049,479)
Proceeds from dispositions of property, plant
and equipment - 560,000
Acquisition, net of cash acquired (note 5) (1,204,754) (44,624,190)
Net change in non-cash working capital (1,937,990) 3,576,441
-------------------------------------------------------------------------
Cash used by investing activities (39,188,068) (56,537,228)
-------------------------------------------------------------------------
Financing activities
Issue of common shares, net of issue costs 40,723,117 2,509,839
Increase (decrease) in credit facility (9,963,616) 9,963,616
Issue of subscription receipts, net of issue
costs - 37,304,676
Proceeds from (payments on) capital lease (196,690) 827,685
Net change in non-cash working capital (40,208) 30,319
-------------------------------------------------------------------------
Cash provided by financing activities 30,522,603 50,636,135
-------------------------------------------------------------------------
Increase (decrease) in cash 5,654,594 (3,612,148)
Cash and cash equivalents, beginning of year - 3,612,148
-------------------------------------------------------------------------
Cash and cash equivalents, end of year 5,654,594 -
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Supplemental information:
Cash taxes paid 89,858 3,775
Cash interest paid 298,851 74,865
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes
1. DESCRIPTION OF BUSINESS
Cinch Energy Corp. (the "Company") was incorporated under the laws of the
Province of Alberta and commenced operations on December 1, 2001. The
Company's activities are comprised of the exploration for and development
of oil and natural gas properties, primarily in Western Canada. On
August 12, 2004, the Company acquired all of the issued and outstanding
common shares of 1099017 Alberta Ltd. ("1099017") and amalgamated with
1099017 immediately thereafter, continuing as Cinch Energy Corp. On
August 4, 2005, the Company acquired all of the issued and outstanding
common shares of and wound up 1008742 Alberta Ltd. into Cinch Energy
Corp.
2. SIGNIFICANT ACCOUNTING POLICIES
These financial statements, which have been prepared in accordance with
Canadian generally accepted accounting principles, have in management's
opinion, been properly prepared within reasonable limits of materiality
and within the framework of the accounting policies summarized below.
Cash and cash equivalents
Term deposits with initial maturities less than three months are
considered to be cash equivalents and are recorded at cost, which
approximates market value.
Property, Plant and Equipment
Petroleum and natural gas properties
The Company follows the full cost method of accounting for its petroleum
and natural gas activities, whereby all costs associated with the
exploration for and development of petroleum and natural gas reserves,
whether productive or unproductive, are capitalized in a single Canadian
cost center and charged to income as set out below. Such costs can
include lease acquisition, drilling, geological and geophysical, and
equipment costs, and overhead expenses directly related to exploration
and development activities. Proceeds from disposal of properties will
normally be applied as a reduction of the cost of the remaining assets,
except when such a disposal would alter the depletion rate by more than
20 percent, in which case a gain or loss will be recorded.
Ceiling test
The net carrying value of the Company's petroleum and natural gas
properties is limited to an ultimate recoverable amount. The Company
tests impairment against undiscounted future net revenue from proved
reserves using expected future prices and costs as well as the income tax
and Alberta Royalty Tax Credit legislation in effect at the period end.
Impairment is recognized when the carrying value of the assets is greater
than the undiscounted future net revenues, in which case the assets are
written down to the fair value of proved plus probable reserves plus the
cost of unproved properties, net of impairment allowances. Fair value is
determined based on discounted future net cash flows calculated using
expected future prices and costs as well as the income tax legislation in
effect at the period end. The discounted rate used is a risk free
interest rate.
Depletion
Depletion of petroleum and natural gas properties and related production
equipment is provided on accumulated costs using the unit of production
method based on estimated proven petroleum and natural gas reserves,
before royalties, as determined by independent engineers. For purposes of
the depletion calculation, proven petroleum and natural gas reserves are
converted to a common unit of measure on the basis that six thousand
cubic feet of natural gas is equivalent to one barrel of petroleum.
The depletion cost base includes total capitalized costs, less costs of
unproven properties, plus for the estimated future development costs
associated with proven undeveloped reserves.
The carrying value of undeveloped properties is reviewed periodically.
The excess of carrying value of undeveloped properties over their fair
value is added to costs subject to depletion.
Office furniture and equipment
Office furniture and equipment is carried at cost and depreciated on a
straight-line basis over the assets' estimated useful lives at a rate of
25% per annum.
Goodwill
Goodwill represents the excess purchase price over the fair value of
identifiable assets and liabilities acquired in business combinations.
Goodwill is subject to ongoing annual impairment reviews, or more
frequent as economic events dictate, based on the fair value of the
Company's assets. The fair value of the Company's assets is determined
and compared to the book value of those assets. If the fair value of the
assets is less than the book value, then a second test is performed to
determine the amount of the impairment. The amount of the impairment is
determined by deducting the fair value of the Company's individual assets
and liabilities from the fair value of the total assets to determine the
implied fair value of goodwill and comparing that amount to the book
value of the Company's goodwill. Any excess of the book value over the
implied value of goodwill is the impairment amount.
Leases
Leases are classified as either capital or operating in nature. Capital
leases are those which transfer substantially all the benefits and risks
of ownership to the lessee. Assets acquired under capital leases are
depleted along with the petroleum and natural gas properties. Obligations
recorded under capital leases are reduced by the principal portion of
lease payments as incurred and the imputed interest portion of capital
lease payments is charged to expense and amortized straight-line over the
life of the lease. Operating lease payments are charged to expense.
Asset Retirement Obligations
The Company recognizes the fair value of a liability for an asset
retirement obligation and a corresponding increase in the carrying value
of the related long-lived asset in the period in which they are
constructed or acquired. The fair value of the obligation is management's
best estimate of the cost to retire the asset based on current
legislation and industry practice. The increase in the carrying value of
the asset is amortized on a unit of production basis consistent with the
method used to record depletion on the Company's petroleum and natural
gas properties. The liability is subsequently adjusted for the passage of
time, which is recognized as accretion expense in the statement of
operations and deficit. The liability is periodically adjusted for
revisions in either the timing or the amount of the original estimated
cash flows associated with the obligation. Any difference between the
related costs incurred and the recorded liability is recorded as a gain
or loss in the statements of operations in the period in which the
settlement occurs.
Measurement Uncertainty
The amounts recorded for depletion and depreciation of petroleum and
natural gas properties and other assets, the provision for asset
retirement obligations, and the ceiling test calculation are based on
estimates of proven or proven and probable reserves, production rates,
petroleum and natural gas prices, future costs and other relevant
assumptions. By their nature, these estimates are subject to measurement
uncertainty and the effect on the financial statements of changes in such
estimates in future periods could be significant.
Joint Operations
Substantially all of the Company's exploration and development activities
are conducted jointly with others and accordingly the financial
statements reflect only the Company's proportionate interest in such
activities.
Flow Through Shares
The Company finances a portion of its exploration and development
activities through the issuance of flow through shares. Under the terms
of a flow through share issue, the tax attributes of the related
expenditures are renounced to subscribers. To recognize the foregone tax
benefits to the Company, share capital is reduced and future income taxes
are increased by the estimated amount of future income taxes payable when
the renouncement is filed with the tax authorities, provided there is
reasonable assurance that the expenditures will be made.
Income Taxes
The Company follows the liability method of accounting for income taxes.
Under this method, the Company records future income taxes for the
difference between the financial statement carrying value and the income
tax basis of an asset or liability. Future income tax assets and
liabilities are measured using income tax rates and laws that are
expected to apply in the periods in which differences are anticipated to
reverse. The effect on future tax assets and liabilities of a change in
tax rates is recognized in net loss in the period in which the change is
substantively enacted.
Revenue Recognition
Revenues from the sale of petroleum and natural gas and related products
are recognized when title passes.
Stock Based Compensation
The Company has a stock based compensation plan, which is described in
note 10. The Company has adopted the fair value based method of
accounting for stock options. Stock option expense is recorded as a
general and administrative expense for all options granted on or after
January 1, 2003, with a corresponding increase recorded to contributed
surplus. The fair value of options granted is estimated at the date of
grant using the Black-Scholes valuation model. Consideration paid by
employees or directors on the exercise of stock options is credited to
share capital. At the time of exercise, the related amounts previously
credited to contributed surplus are also transferred to share capital.
Per Share Information
Per share information is calculated using the treasury stock method.
Under this method, the diluted weighted average number of common shares
is calculated assuming that the proceeds from the exercise of outstanding
and in the money options is used to purchase common shares at the
estimated average market price.
3. CASH AND CASH EQUIVALENTS
As at December 31, 2005, cash and cash equivalents include term deposits
with maturities of 90 days or less of $4,980,000. The term deposits
earned interest at 2.78%.
4. ACCOUNTS RECEIVABLE
A substantial portion of the Company's accounts receivable is with oil
and gas marketing entities. The Company generally extends unsecured
credit to these companies, and therefore, the collection of accounts
receivable may be affected by changes in economic or other conditions and
may accordingly impact the Company's overall credit risk. Management
believes the risk is mitigated by the size, reputation and diversified
nature of the companies to which they extend credit.
The Company has not previously experienced any material credit losses on
the collection of receivables. Of the Company's significant individual
accounts receivable at December 31, 2005, approximately 65% was owed from
7 customers (December 31, 2004 - 83% was owed from 6 customers).
The accounts receivable balance at December 31, 2005 includes $144,431
owed in the normal course of operations by a joint venture partner which
is controlled by one of Cinch's directors.
5. PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment
December 31, 2005
-------------------------------------------------------------------------
Accumulated Net book
Cost depreciation 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
-------------------------------------------------------------------------
-------------------------------------------------------------------------
December 31, 2004
-------------------------------------------------------------------------
Accumulated Net book
Cost depreciation value
$ $ $
-------------------------------------------------------------------------
Petroleum and natural gas
properties 65,992,834 (10,012,446) 55,980,388
Equipment under capital lease 827,685 (25,282) 802,403
Office furniture and equipment 121,313 (49,912) 71,401
-------------------------------------------------------------------------
66,941,832 (10,087,640) 56,854,192
-------------------------------------------------------------------------
-------------------------------------------------------------------------
For the years ended December 31, 2005 and 2004, no indirect general and
administrative expenditures were capitalized.
As at December 31, 2005, $11,885,839 of costs related to undeveloped
lands were excluded from costs subject to depletion (December 31, 2004-
$12,843,595).
Acquisitions
a) Effective August 4, 2005, the Company acquired all of the issued and
outstanding common shares of and wound up 1008742 Alberta Ltd. into Cinch
Energy Corp. The certificate of dissolution was received December 21,
2005. The total cash consideration of the purchase was $1.205 million
which has been allocated to petroleum and natural gas properties, future
taxes and working capital. The acquisition was accounted for using the
purchase method and therefore revenues and expenses from the acquired
assets have been included in the statements of operations and deficit
from August 4, 2005.
The purchase price has been allocated as follows:
-------------------------------------------------------------------------
$
Non-cash working capital 38,852
Land 1,421,639
Property, plant and equipment 93,648
Asset retirement obligation (6,678)
Future taxes (342,707)
-------------------------------------------------------------------------
Total purchase price 1,204,754
-------------------------------------------------------------------------
-------------------------------------------------------------------------
b) On August 12, 2004, the Company acquired the Canadian petroleum and
natural gas properties and related assets of Rio Alto Resources
International Inc. ("Rio Alto"), by purchasing the shares of a newly
created subsidiary company of Rio Alto, 1099017 Alberta Ltd., holding
such assets since the effective date of April 1, 2004, for a purchase
price of $48.703 million, or $45.987 million net of working capital
acquired. Immediately after the acquisition, the Company amalgamated with
1099017 Alberta Ltd. and continued as Cinch Energy Corp.
The Company financed the acquisition with the proceeds of a subscription
receipt and flow through subscription receipt private placement, as more
fully described in note 10, and with its credit facility, as described in
note 6.
The purchase price was allocated as follows:
-------------------------------------------------------------------------
$
Cash acquired 4,079,476
Working capital deficiency, excluding cash acquired (1,362,878)
Undeveloped land 10,000,000
Property, plant and equipment 25,029,299
Goodwill 14,616,996
Asset retirement obligation (975,663)
Future taxes (2,683,563)
-------------------------------------------------------------------------
Total purchase price 48,703,667
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Cash consideration 48,500,000
Transaction costs 203,667
-------------------------------------------------------------------------
Total consideration 48,703,667
-------------------------------------------------------------------------
-------------------------------------------------------------------------
The acquisition was accounted for using the purchase method and therefore
revenues and expenses from the acquired assets have been included in the
statements of operations and deficit from August 12, 2004.
The Company has performed an impairment test as of December 31, 2005
using the estimated average price for each of the next five years as
determined by the Company's independent reserve engineers adjusted for
differentials specific to the Company's reserves as follows:
Natural Gas Natural Gas Liquids
$/mmbtu Cdn $/bbl Cdn
-------------------------------------------------------------------------
2006 10.35 67.00
2007 9.00 65.25
2008 7.75 60.50
2009 7.25 56.75
2010 6.95 55.00
-------------------------------------------------------------------------
Each benchmark price increased by an average of 0% from 2011 to 2012 and
2% from 2013 and thereafter
-------------------------------------------------------------------------
-------------------------------------------------------------------------
6. CREDIT FACILITY
Effective June 8, 2005, the Company increased its revolving, demand bank
credit facility through ATB Financial to $26,500,000 from $20,000,000
(December 31, 2004 - $18,000,000). The facility bears interest at the
lender's prime rate. The effective interest rate at December 31, 2005 was
4.02% (December 31, 2004 - 4.25%). As at December 31, 2005, the amount
drawn on the credit facility was nil (December 31, 2004 - $9,963,616). 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.
7. 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 232,140
2007 232,140
2008 232,140
-------------------------------------------------------------------------
Total minimum lease payments 696,420
Less amounts representing interest at 5.12% 65,425
-------------------------------------------------------------------------
Present value of minimum lease payments 630,995
Less current portion 210,007
-------------------------------------------------------------------------
Capital lease obligation at December 31, 2005 420,988
-------------------------------------------------------------------------
-------------------------------------------------------------------------
For the year ended December 31, 2005, there was $22,274 (2004 - nil)
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.
8. 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 cash flows required to reclaim and abandon
wells and facilities as at December 31, 2005 is approximately $4,260,000
(December 31, 2004 - $2,636,113), to be incurred over the next 18 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 $2,725,627
(December 31, 2004 - $1,633,234).
The Company's asset retirement obligations changed as follows:
December 31, December 31,
2005 2004
$ $
-------------------------------------------------------------------------
Asset retirement obligations, beginning of year 1,633,234 261,485
Liabilities acquired (note 5) 6,678 975,663
Liabilities incurred 927,866 314,937
Accretion expense 157,849 81,149
-------------------------------------------------------------------------
Asset retirement obligations, end of year 2,725,627 1,633,234
-------------------------------------------------------------------------
-------------------------------------------------------------------------
9. 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:
December 31, December 31,
2005 2004
-------------------------------------------------------------------------
Statutory income tax rate 37.62 38.62%
$ $
Anticipated income taxes 1,945,506 118,130
Increase/(decrease) resulting from:
Resource allowance (1,406,352) (459,991)
Non-deductible crown royalties, net of
Alberta Royalty Tax Credit 1,160,585 423,105
Non-deductible items 5,512 3,262
Rate adjustment - 10,613
Stock compensation expense 208,364 98,367
Rate adjustment (203,715) -
-------------------------------------------------------------------------
Future income taxes 1,709,900 193,486
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Large corporation taxes 97,650 13,150
-------------------------------------------------------------------------
-------------------------------------------------------------------------
1,807,550 206,636
-------------------------------------------------------------------------
-------------------------------------------------------------------------
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:
December 31, December 31,
2005 2004
$ $
-------------------------------------------------------------------------
Net book value of capital assets in excess of
tax pools (9,663,114) (7,631,292)
Share issue costs 1,047,675 958,811
Asset retirement obligations 916,356 549,093
Other 52,323 -
-------------------------------------------------------------------------
Future tax liability (7,646,760) (6,123,388)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
10. SHARE CAPITAL
Authorized - Unlimited number of common voting shares without par value
December 31, 2005 December 31, 2004
-------------------------------------------------------------------------
Issued Number $ Number $
-------------------------------------------------------------------------
Common shares
Balance, beginning of
year 33,104,316 51,568,073 5,364,440 8,242,356
Issued for cash on
warrant exercise(i,iii) 8,022,529 19,053,506 - -
Issued for cash on flow
through private
placement(ii) 2,352,941 9,999,999 - -
Issued for cash on
private placement(ii) 3,676,472 12,500,005 - -
Exercise and conversion
of special warrants(iv) 257,600 238,759 5,790,458 6,746,040
Issued for cash on
options exercise(v) 100,334 188,126 70,000 131,000
Issued for cash on
brokers' warrant
exercise(vi) 243,440 243,440 70,054 95,861
Reclassification on
exercise of options(v) - 56,473 - 11,500
Exercise of flow through
subscription receipts(iii) - - 3,333,333 6,984,290
Exercise of subscription
receipts(iii) - - 17,364,905 30,320,386
Issued for cash on private
placement(iii) - - 1,111,112 2,500,000
Rounding on conversion(iv) - - 14 -
Future taxes on flow
through common shares - - - (3,362,000)
Issue costs, net of future
taxes - (837,672) - (101,360)
-------------------------------------------------------------------------
Balance, end of year 47,757,632 93,010,709 33,104,316 51,568,073
-------------------------------------------------------------------------
Special warrants
Balance, beginning of year 312,600 272,694 6,103,058 7,018,734
Exercise and conversion to
common shares(iv) (257,600) (238,759) (5,790,458) (6,746,040)
Balance, end of year 55,000 33,935 312,600 272,694
-------------------------------------------------------------------------
Share capital, end of
year 47,812,632 93,044,644 33,416,916 51,840,767
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Subscription receipts
Balance, beginning of year - - - -
Issued for cash on private
placement(iii) - - 43,412,262 32,559,197
Issued for cash on flow
through private
placement(iii) - - 8,333,333 7,500,000
Issue costs - - - (2,754,521)
Exercise and deemed exercise
into common shares(iii) - - (51,745,595)(37,304,676)
-------------------------------------------------------------------------
Subscription receipts,
end of year - - - -
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Contributed surplus
Balance, beginning of year - 753,449 - 510,244
Non cash compensation
expense(v) - 553,866 - 254,705
Reclassification to share
capital on exercise of
options(v) - (56,473) - (11,500)
-------------------------------------------------------------------------
Contributed surplus, end
of year - 1,250,842 - 753,449
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Share capital and per share amounts have been restated on a retroactive
basis to reflect a 2.5 for 1 common share consolidation which occurred on
August 12, 2004.
Common Shares
(i) Warrant exercise
In 2005, a total of 8,022,529 common shares were issued pursuant
to the exercise of warrants (see note iii) at an exercise price of
$2.375, for gross proceeds of $19,053,506 and 1,649,807 warrants
exchangeable for 659,923 common shares expired. There are no
warrants outstanding as at December 31, 2005.
(ii) 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 2006.
(iii) Private Placement
On June 15 and June 17, 2004, the Company issued a total of
1,111,112 flow through common shares at $2.25 per share in a
private placement for gross proceeds of $2,500,000.
In accordance with the terms of the flow through common shares,
and pursuant to certain provisions of the Income Tax Act (Canada),
in 2004 the Company renounced, for income tax purposes,
exploration and development expenditures to holders of its flow
through common shares of $2,500,000.
Under the same private placement, the Company also issued, on
June 15, June 17 and July 22, 2004, 43,412,262 subscription
receipts at $0.75 per subscription receipt and 8,333,333 flow
through subscription receipts at $0.90 per flow through
subscription receipt and the gross proceeds were placed in escrow.
Each subscription receipt entitled the holder to acquire 0.4
common shares without payment of additional consideration and one
half of one warrant, each whole warrant entitling the holder to
acquire 0.4 common shares at an exercise price of $2.375 until
June 15, 2005. If the common shares or warrants issuable on
exercise of the subscription receipts were subject to a restricted
period or a hold period (other than in respect of sales by control
persons) after November 30, 2004, the holders of subscription
receipts were entitled to receive on exercise of the subscription
receipts 0.44 common shares and one half of one warrant. Each flow
through subscription receipt entitled the holder to acquire 0.4
flow through common shares without payment of additional
consideration and was deemed exercised on closing of the
acquisition of 1099017 Alberta Ltd. on August 12, 2004, as
described in note 5, resulting in the issuance of 3,333,333 common
shares.
On August 12, 2004, proceeds from the subscription receipts and
flow through subscription receipts totaling $40,059,197 that had
been placed in escrow were released to the Company on closing of
the acquisition, net of issue costs of $2,754,521.
In accordance with the terms of the flow through subscription
receipts, and pursuant to certain provisions of the Income Tax Act
(Canada), in 2004 the Company renounced, for income tax purposes,
exploration and development expenditures to holders of its flow
through common shares of $7,500,000.
On October 15, 2004, the Company received a receipt for a final
prospectus and the subscription receipts were therefore deemed
exercised 5 business days later, on October 22, 2004. The common
shares issued on the deemed exercise of the subscription receipts
were not subject to a restricted period or a hold period (other
than in respect of sales by control persons), and as such, the
holders of subscription receipts received 0.4 common shares and
one half of one warrant for each subscription receipt deemed to be
exercised. A total of 17,364,905 common shares and 21,706,131
warrants were issued October 22, 2004, with each warrant entitling
the holder to acquire 0.4 of a common share at an exercise price
of $2.375 until June 15, 2005 as noted in (i).
(iv) Exercise of special warrants
Pursuant to the receipt for a final prospectus received on
October 15, 2004 as noted in (iii), the common shares issuable on
exercise of special warrants outstanding were no longer subject to
a restricted period or hold period under applicable securities
laws in Canada (other than Quebec). During the year ended
December 31, 2005, special warrant holders have exercised 257,600
special warrants in exchange for a total of 257,600 common shares
for no additional cash consideration.
During the year ended December 31, 2004, 5,790,458 special
warrants (14,476,146 special warrants consolidated on a 2.5 for
1 basis) were exercised in exchange for a total of 5,790,458
common shares.
(v) Exercise of options
During the year ended December 31, 2005, a total of 100,334 common
shares were issued on exercise of stock options (December 31, 2004
- 70,000) at an average exercise price of $1.875 (December 31,
2004 - $1.875). As a result, stock compensation expense of $56,473
previously recognized for these options has been reclassified from
contributed surplus to common shares (December 31, 2004 -
$11,500).
The non-cash compensation expense is comprised of the stock option
benefit for all outstanding options.
(vi) Brokers' warrant exercise
On January 30, 2005, a total of 50,500 brokers' warrants expired.
During the year ended December 31, 2005, a total 243,440 common
shares were issued pursuant to the exercise of brokers' warrants
at an exercise price of $1.00. (December 31, 2004 - 40,560 common
shares at $1.00 and 29,494 common shares at $1.875). As at
December 31, 2005, there were no brokers' warrants outstanding.
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
40,046,588 (2004 - 20,054,494). 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
resulting in a weighted average number of common shares of 41,921,643
(2004 - 22,068,795). Per share calculations that are anti-dilutive are
not presented.
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:
2005 2004
Weighted Weighted
Average Average
Number of Exercise Number of Exercise
Options Price Options Price
-------------------------------------------------------------------------
$ $
Stock options outstanding,
beginning of year 1,635,000 1.88 658,000 1.89
Granted 1,065,000 2.55 1,087,000 1.87
Exercised (100,334) 1.88 (70,000) 1.88
Expired (271,666) 2.00 (40,000) 1.88
-------------------------------------------------------------------------
Stock options outstanding,
end of year 2,328,000 2.17 1,635,000 1.88
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Stock options outstanding at the end of the year are comprised of the
following weighted average prices:
December 31, 2005 December 31, 2004
Weighted Weighted
Average Average
Number of Exercise Number of Exercise
Options Price Options Price
-----------------------------------------------
$ $
- - 40,000 1.63
762,000 1.87 842,000 1.87
531,000 1.88 678,000 1.88
15,000 1.95 55,000 1.95
75,000 2.04 - -
75,000 2.14 - -
70,000 2.29 - -
20,000 2.38 20,000 2.38
25,000 2.44 - -
556,000 2.52 - -
25,000 2.70 - -
49,000 2.75 - -
125,000 3.30 - -
-----------------------------------------------
2,328,000 2.17 1,635,000 1.88
-----------------------------------------------
-----------------------------------------------
The options outstanding at December 31, 2005 have a weighted average
remaining contractual life of 3.7 years (December 31, 2004 - 4.0 years).
As at December 31, 2005, a total of 630,666 were exercisable
(December 31, 2004 - 332,667).
The fair value of stock options granted to employees, directors and
consultants during the year ended December 31, 2005 and 2004, 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 (2004 - zero percent), expected volatility of 34.62 percent
(2004 - 29.25 percent), risk-free interest rate of 3.43 percent (2004 -
3.69 percent), and an expected life of four years (2004 - four years).
Outstanding options granted during the year ended December 31, 2005 had
an estimated weighted average fair value of $0.83 per option
(December 31, 2004 - $0.53 per option), for a total estimated value of
$827,890 (2004 - $558,451). A total of $553,866 (2004 - $254,705) has
been recognized as stock compensation expense with an offsetting credit
to contributed surplus for the year ended December 31, 2005.
11. 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 capital lease obligation, as more
fully described in note 7. The Company has no other arrangements which
are deemed to constitute a lease obligation either in form or substance.
12. 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, credit
facility, and capital lease obligations. As at December 31, 2005 and
2004, 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
At December 31, 2005, the Company had no fixed price contracts associated
with future production.
13. BASIS OF PRESENTATION
Certain of the comparative figures have been reclassified to conform to
the presentation adopted in the current year.
>>
%SEDAR: 00021196E
For further information: please contact: John W. Elick, Chief Executive Officer, Tel: (403) 693-0090, elickj@cinchenergy.com; George Ongyerth, President, Tel: (403) 693-0090, ongyerthg@cinchenergy.com, or visit our website at www.cinchenergy.com
