MD&A4
Management Discussion and Analysis
Management’s discussion and analysis (MD&A) should be read in conjunction with the unaudited November
30, 2005 financial statements and accompanying notes as well as the MD&A for the year ended February
28, 2005 and the audited financial statements for that year. Where amounts are expressed on a barrel of oil
equivalent basis (BOE), gas volumes have been converted to oil equivalents at a six to one ratio.
This commentary is based on information available at January 27, 2006. Additional information relating to
Choice Resources Corp. is available on SEDAR at www.sedar.com.
The MD&A uses the terms “cash flow from operations” which is before non-cash working capital adjustments
and “cash flow per share,” also before non-cash working capital adjustments. Although these are not
currently recognized measures under Canadian generally accepted accounting principles (GAAP),
management believes that in addition to net earnings, cash flow is a useful additional measure or indication
as to how the Company is performing. It provides an indication of what funds the Company is generating
from its operations to deploy, along with other sources of capital, in financing its on going exploration and
development efforts.
Overall performance
Choice (“Choice” or the “Company”) is a publicly listed company on the TSX Venture Exchange trading
under the symbol CZE. It is engaged in the business of exploration, development and production of oil and
gas reserves in the Province of Alberta.
The financial statements for the Company at November 30, 2005 continue to indicate that Choice is in a
strong financial position and is positioned for growth. The Company, at the year ended February 29, 2004
had a debt and working capital deficit of nearly thirty million dollars. In comparison, the net debt and working
capital deficit for the quarter ended November 30, 2005 is $8.39mm ($17.13mm at November 30, 2004)
including bank debt of $2.40 mm ($12.48 at November 30, 2004). The Company has a bank line of credit of
$20.00mm available.
The Company, since the new management group was installed less than two years ago, has raised more
than $20.00mm in new equity and sold certain properties including a 25% interest in the Pincher Creek Unit
for $6.10mm (August 2005) to strengthen the balance sheet. These financial transactions, as well as a
proper distribution of drilling risk, particularly as it pertains to the Pincher Creek horizontal well, have allowed
the Company to undertake the drilling of the high impact Pincher Creek horizontal well. Choice took a 19%
capital interest in the well to earn a 52.5% working interest in the net production on an after-payout basis.
The Pincher Creek horizontal well came on-stream December 7, 2005 and does not impact operations for
these financial statements being reported on.
The emphasis is now on growth and an aggressive capital program is under way, which will see the
Company participating in as many as 55 gross wells (30 net wells) over the next twelve to fifteen months.
The Company has assembled an interesting portfolio of plays which provide a balanced program in terms of
exploration and development drilling and is proceeding with the winter drilling program.
Choice Resources Corp. is pleased to report continuing strong financial results for the year to date and for
the quarter ended November 30, 2005. Commodity prices have been strong throughout the year and have
further strengthened since the latter half of August of this year. Sales production volumes for the nine month
period averaged 1,350 BOE per day compared to 1,425 BOE per day last year for the comparable period.
Production for the three months to November 30, 2005 averaged 1,329 BOE per day compared to 1,294
BOE per day for the comparable period last year. Current production reflects the sale of 25% working
interest in the Pincher Creek unit or approximately 100 BOE per day and the disposition of a non-core
property with production of approximately 60 BOE per day.
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Choice has spent $14.07mm before dispositions in the first nine months of the year on capital projects
including 19% of the capital costs for the Company’s share of the Pincher Creek horizontal well. The
Company expects to spend an additional $3.0 - $5.0mm in the last quarter to February 28, 2006. These
expenditures will generally be concentrated in the exploration areas. We have contracted two rigs for the
winter drilling program.
Annual Information February 28,
2005
February 29,
2004
February 28,
2003
Total Revenue $ 19,981,132 $ 16,617,958 $ 2,068,406
Net Income (loss) $ 2,965,072 $ (1,156,205) $ 188,484
Per Share - Basic $0.07 $(0.10) $0.03
- Diluted $0.07 $(0.10) $0.03
Total Assets $ 55,015,661 $ 48,281,896 $ 5,651,705
Current liabilities, including bank debt $ 21,130,932 $ 30,626,711 $ 2,604,366
Total Long-Term Financial Liabilities $ 10,583,207 $ 8,480,622 $ 918,000
Review of Major properties
PINCHER CREEK
Sale of 25% of Unit for $6.1mm, effective September 1, 2005
Horizontal well 102/01-05-003-28W4 completed and on production December 7, 2005
Extremely long life reserves are present in this unit
41-section Choice operated unit
3D & 2D seismic data is covering the unit
Numerous high impact follow-up drilling and re-entry opportunities have been identified
The sale of 25% of the Pincher Creek unit wells for $6.1mm was completed and took effect in the third
quarter, reducing Choice’s working interest to 75%.
The 01-05-003-28W4m horizontal Rundle well was successfully completed in October. The well was then
completed with an acid wash followed by a flow and build-up to test the deliverability for this well. The well
has initial raw gas production of approximately 3 MMCF/D. The well was placed on production early in
December.
Phase II of the Pincher Creek plant reclamation activities commenced in November. This Phase will see the
demolition and removal of three unutilized buildings. The project will continue into next quarter at an
estimated cost of $900,000 spread over a period of five months. Activities for the quarter were carried out
without incident, ahead of schedule and under budget.
A study of existing well bores highlighted several potential recompletion prospects to enhance and add new
production.
BOW ISLAND
100% Working Interest in Lands and Facilities
Choice Operated
Production from the Bow Island field remained steady through the quarter, averaging 166 BOE/D.
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VIKING
Multi zone Potentials
Large 3-D Seismic program shot
Extensive high working interest lands and facilities
Choice Operated
A 10 square mile 3-D seismic program was carried out in the Viking area. The results were analyzed and
interpreted to reveal the potential for a 28 well drilling program aimed at both deep and shallow target.
Several locations have been approved, surface locations have been acquired and drilling has commenced in
the fourth quarter. This program will see the drilling and completion of between 7 and 15 wells between now
and the end of March, subject to rig and weather restrictions. The balance of the program will be initiated
after spring break-up.
There was one well drilled and cased in this area through the third quarter which was tied-in and placed on
production. Three additional wells were tested and placed on production. Two of the wells were restricted
from producing at full potential due to hydrocarbon due point constraints at third-party facilities. Remedies for
these bottle necks are expected within six months.
SNIPE LAKE - WALLACE
Multi zone Potential
Large tracts of undeveloped land
Mostly Choice Operated
High Impact Well Potential
A two mile all-season road was constructed, which will allow access to a winter only oil producing pool. This
discovery well was equipped with pumping facilities and was placed on production for 25 BBL/D of sweet oil.
Follow-up locations to this well are planned for the coming winter drilling season.
Seismic was shot, processed and analyzed in this area prior to finalization of the drilling plans.
A nine well drilling program with three additional contingent wells is planned and underway for this area. A
drilling rig has been secured for the winter program and as of this report, three wells have been drilled.
2005 Operation Summary
Choice derives 95% of its revenue from the sale of natural gas. For the nine months ended November 30,
2005 the Company recorded natural gas sales volumes of 2,111,593 MCF (7,679 MCF/day) which is 7% less
than the natural gas sales volumes of 2,280,832 MCF (8,294 MCF/day) recorded in the same period last
year. For the quarter, natural gas volumes produced and sold averaged 7,511 MCF/day compared to 7,845
MCF/day last year. Sulphur volumes (associated with the Pincher Creek gas production) have been
included with gas sales volumes on a 6:1 equivalency basis but represent a small percentage of these
figures. The current year’s gas production was affected by a shutdown at Pincher Creek for approximately
five weeks to conduct certain repairs and maintenance on the gathering system and the sale of 25% working
interest in the Pincher Creek unit.
Total oil and natural gas liquids (NGLs) production increased to 19,206 barrels for the nine months (70
BBL/day) compared to 11,798 (43 BBL/day) for the prior nine month period. This 63% increase in oil and
NGL production is largely due to new oil production coming on-stream from the Kaybob well drilled in the first
quarter of the year and placed on production in July as well as production from an oil well in the Snipe area,
now that all-weather roads and facilities have been completed in the current quarter. Oil and NGL volumes
were also adjusted last year in the third quarter to correct an allocation of liquids by the plant operator in
Pincher Creek. This is reflected in oil and NGL production in the current quarter of 77 BBL/day compared to
the anomalous (13) BBL/day last year.
On a BOE equivalency basis, daily production rates for the nine months ended November 30, 2005 averaged
1,350 barrels of oil equivalent per day (BOE/day) compared to 1,425 BOE/day for the nine month period last
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year. For the third quarter of this year, production averaged 1,329 BOE/day compared to 1,294 BOE/day in
last year’s third quarter.
Choice has enjoyed strong natural gas prices in the current year, particularly in the third quarter, as prices for
the quarter were $10.81/MCF compared to $6.22 for the same period last year. These higher prices in the
quarter carried through for the nine months to an average of $8.51/MCF compared to $6.29/MCF for the nine
months last year. This translates to a 74% increase in prices for the quarter and 35% for the year to date
compared to last year respectively.
Oil and natural gas liquids prices were also up significantly to an average of $69.83/BBL for the nine months
compared $51.17/BBL last year. Prices for the current quarter were even higher, averaging $72.35. Overall,
prices per barrel for the nine months increased to $52.01 compared to $38.17 for the comparable period last
year. This is an increase in the price per BOE of 36% above last year and reflects the general price
increases experienced in the upstream sector of the oil and gas industry this past year. Prices per BOE in
the quarter averaged $65.27/BOE.
Summary of Quarterly Results (8 quarters)
3rd Quarter 2nd Quarter 1st Quarter 4th Quarter
30-Nov-05 31-Aug-05 31-May-05 28-Feb-05
Gross revenue $7,891,534 $5,941,944 $5,468,893 $5,650,846
Net income (loss) $2,013,097 $652,535 $796,323 $1,018,089
Net income (loss) per share - basic and diluted $0.04 $0.01 $0.02 $0.02
3rd Quarter 2nd Quarter 1st Quarter 4th Quarter
30-Nov-04 31-Aug-04 31-May-04 29-Feb-04
Gross revenue $4,477,665 $5,125,820 $5,356,382 $6,714,141
Net income (loss) $621,829 $418,070 $907,083 $ (70,897)
Net income (loss) per share - Basic and diluted $0.01 $0.01 $0.03 $(0.00)
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Revenue:
Three months ended November 30, Nine months ended November 30,
2005 2004 % change 2005 2004 % change
Volumetrics:
Natural gas – MCF * 683,541 713,881 -4% 2,111,593 2,280,832 -7%
Oil & natural gas liquids – barrels 6,983 (1,182) n/a 19,206 11,798 63%
MCF equivalent (Oil & NGL’s converted at 1:6) 725,439 706,789 3% 2,226,829 2,351,620 -5%
MCF equivalent/day 7,972 7,767 8,098 8,551
BOE equivalent (Natural gas converted at 6:1) 120,907 117,798 3% 371,138 391,937 -5%
BOE equivalent/day 1,329 1,294 1,350 1,425
Revenue:
Natural gas revenue $7,386,285 $4,439,055 66% $17,961,252 $14,356,126 25%
Oil and natural gas liquids revenue 505,249 38,610 1209% 1,341,119 603,741 122%
Total revenue $7,891,534 $4,477,665 76% $19,302,371 $14,959,867 29%
Average natural gas & sulphur price ($ /MCF) $10.81 $6.22 74% $8.51 $6.29 35%
Average oil & natural gas liquids price ($/BBL) $72.35 $32.66 122% $69.83 $51.17 36%
Average price per MCF ($ / MCF) $10.88 $6.34 72% $8.67 $6.36 36%
Average price per BOE ($/BBL) $65.27 $38.01 72% $52.01 $38.17 36%
* Gas volumes include sulphur converted at 6 mcf per tonne.
Gross revenue from natural gas, oil and related products for the nine month period increased 29% to
$19.30mm compared to the prior year’s gross revenue of $14.96mm. For the current three month quarterly
period to November 30, 2005 revenues were up 76% to $7.89mm. The total increases in revenue are
attributable to a 36% increase in commodity prices; offset by a 5% decrease in sales volumes for the nine
month period.
In the current quarter volumes were up 3% and prices were up 72% compared to the third quarter last year.
Revenue and operating expenses have been restated for the prior year to reclassify natural gas
transportation costs as operating costs rather than netting these from revenue, as required by the new
accounting guidelines. (Refer to Financial Statement note 2(a), Changes in Accounting Policies.)
Royalties:
Three months ended November 30, Nine months ended November 30,
2005 2004 % change 2005 2004 % change
Royalties, net of ARTC $1,611,470 $696,012 132% $4,021,498 $2,727,502 47%
% of natural gas and liquids sales 20% 16% 21% 18%
Per BOE $13.33 $5.91 126% $10.84 $6.96 56%
Royalties, net of ARTC, for the first three months increased to $1.61mm from $0.70mm. These increases in
the quarter over last years third quarter are due to an adjustment in crown royalties in the prior three month
period where the Company recovered from the crown amounts paid for injection gas which were deemed to
be royalty paid. Royalties as a percentage of revenue are, notwithstanding this prior year quarterly
adjustment, consistent with the year to date and in line with the prior year’s royalties.
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Production and Operating Expenses:
Three months ended November 30, Nine months ended November 30,
2005 2004 % change 2005 2004 % change
Operating expenses $1,664,016 $1,446,852 15% $4,888,999 $4,568,684 7%
% of natural gas and liquids sales 21% 32% 25% 31%
Per BOE $13.76 $12.28 12% $13.17 $11.66 13%
Operating expenses for the nine months increased by 7% over the prior years’ nine months to $4.89mm
compared to $4.57mm. On a BOE basis, operating costs have increased to $13.17/BOE compared to
$11.66. Choice expects that In the fourth quarter, and continuing into the future, operating costs expressed
on a per unit of production basis will be reduced as production increases associated with the Pincher Creek
horizontal well are realized. In addition, operating costs for the third quarter are higher than the second
quarter due to increased third party processing costs. These processing costs are expected to be reduced in
the fourth quarter.
General and administrative expenses:
Three months ended November 30, Nine months ended November 30,
2005 2004 % change 2005 2004 % change
Gross G&A $490,387 $421,079 $1,606,167 $ 1,314,877
Capitalized G&A 243,352 159,044 572,974 464,095
Net G&A $247,035 $262,035 -6% $1,033,193 $ 850,782 21%
% of natural gas and liquids sales 3% 6% 5% 6%
Per BOE – before recovery $4.06 $3.57 13% $4.33 $3.35 29%
Per BOE – net of recovery $2.04 $2.22 -8% $2.78 $2.17 28%
General and administrative expenses (G&A), net of recoveries for the nine months were, $1.03mm
compared to $0.85mm for the period nine month period, an increase of 21%. This reflects increased payroll
and consulting fees required to maintain a growing full cycle exploration junior oil and gas company and is
also necessary to support an increased activity level in the Company as the prospect inventory grows. The
Company anticipates that G&A per BOE will decrease as production volumes increase as most G&A
expenses are fixed.
G&A for the nine months rose to $2.78/BOE compared to $2.17/BOE last year. The Company capitalized
$0.57mm in G&A for the current nine months to property, plant and equipment compared to $0.46mm in the
same period in the prior year. Approximately 30% of all G&A costs are directed toward longer term
exploration efforts and accordingly, these costs are capitalized as property, plant and equipment assets.
Interest and financing expense:
Three months ended November 30, Nine months ended November 30,
2005 2004 % change 2005 2004 % change
Interest on long term debt and capital lease $63,230 $180,065 -65% $281,144 $606,805 -54%
Per BOE $0.52 $1.53 -66% $0.76 $1.55 -51%
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Interest expense for the nine months decreased substantially to $0.28mm from $0.61mm. This represents a
54% reduction in interest expense for the current year compared to the prior period and reflects the
Company’s commitment to reducing overall debt levels. Interest costs in the current quarter were $0.06mm
compared to $0.18mm in last years third quarter. At November 30, 2005 the Company had a bank loan
balance of $2.40mm on an available bank credit facility of $20.00mm.
Depletion, depreciation, and accretion: (DD&A)
Three months ended November 30, Nine months ended November 30,
2005 2004 % change 2005 2004 % change
DD&A $1,131,105 $1,113,309 2% $3,372,450 $3,233,122 4%
% of natural gas and
liquids sales 14% 25% 17% 22%
Per BOE $9.36 $9.45 -1% $9.09 $8.25 10%
The depletion, depreciation and accretion provision for the current nine month period was $3.37mm,
consistent with the $3.23mm recorded in the nine month period last year. It was also consistent in the
current quarter at $1.13mm compared to $1.11mm in last years third quarter. As a percentage of revenue
the provision for the three months and nine months is down considerably from last years figures at 14% and
17% respectively compared to 25% and 22%. The decrease in the DD&A provision reflects a larger reserves
base on which the depletion is calculated on a unit-of-production basis.
Net income and cash flow from operations:
Cash flow:
Three months ended November 30, Nine months ended November 30,
2005 2004 % change 2005 2004 % change
Cash flow from operations $4,305,783 $1,892,701 127% $9,077,537 $6,206,094 46%
Cash flow per share $0.08 $0.04 100% $0.17 $0.15 13%
Per BOE $35.61 $16.07 $24.46 $15.83
Cash flow from operations for the current nine months (defined as operational cash flow computed by
subtracting general and administrative expenses, interest expense and cash income taxes from gross
revenues net of royalties and operating and production expenses) increased by 46% to $9.08mm ($0.17 per
share) compared to $6.21mm ($0.15 per share) for the nine month period last year. Increases in commodity
prices and decreased interest expense have contributed to this positive cash flow increment.
The increase in cash flow in the current quarter was even greater on a comparative basis and showed a
127% gain over the third quarter last year to $4.31mm compared to $1.89mm for the third quarter last year
and a cash flow net back of $36.61 compared to $16.07 last year.
Net income:
Three months ended November 30, Nine months ended November 30,
2005 2004 % change 2005 2004 % change
Net income $2,013,097 $621,829 224% $3,461,956 $1,946,982 78%
% of natural gas and liquids sales 26% 14% 18% 13%
Net income per share $0.04 $0.01 $0.06 $0.05
Per BOE $16.65 $5.28 $9.33 $4.97
Net income was substantially higher at $3.46mm ($0.07 per share) compared to the prior year nine month
period at $1.95mm ($0.05 per share). Current year per share calculations include an equity placement
completed in May of this year. For the three month period ended November 30, 2005 net income of
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$2,013,097 is up 224% from $621,829.
Per share amounts have also been reported on a basic and fully diluted basis as the share purchase
warrants are considered non-dilutive. (Refer to Financial Statement note 6, Equity Instruments.)
Capital Expenditures:
For the nine months ended November 30, 2005 the Company has incurred $14.07mm for capital projects
($8.10mm for the three months).
Top capital projects for the quarter ended November 30, 2005 include:
�� $2,529,156 - Tangible and intangible asset purchase in the Prairie River, Goose River and Snipe
Lake areas, effective September, 2005.
�� $1,281,557 – Pincher Creek 102/01-05-003-28 W4 – drilling costs in Pincher Creek horizontal well,
19% net capital interest
�� $822,888 – Seismic activity Wallace, Snipe Lake and Viking areas.
�� $262,867 – Whitecourt – drill and case gas well, 50% working interest
�� $242,605 – McGowan – costs to build a permanent road and purchase and install single well battery
equipment.
Liquidity and capital resources:
The focus for the Company since the new management team was installed in early 2004 was to restore the
financial viability of the Company and to develop a balanced exploration and development portfolio in order
for Choice to grow and expand its asset base. Choice has reduced its bank debt to very low levels and has
eliminated expensive and excessive secondary debt through a series of equity placements and the sale of
certain oil and gas properties. At November 30, 2005 net debt and working capital levels are less than 0.5
times the expected annual operational cash flow.
The equity placement of $7.5mm, which closed in May, 2005, and the disposition of 25% working interest in
the Pincher Creek Unit for $6.1mm have been instrumental in allowing the Company to reduce its bank debt
to $2.40mm.
The Company has developed a strong play inventory and remains in a strong financial position to fund these
capital projects for the balance of this fiscal year and into the following fiscal year through cash flow from
operations and by utilizing a portion of its $20.00mm bank credit facility. (Refer to Outlook section below.)
The Company is obligated under a long term capital lease for a compressor at one of its facilities. Choice
has an obligation to purchase this compressor when the lease ends in October, 2006 for a one-time payment
of $391,508.
The Company had no off balance sheet financial arrangements or interests in any partnership or any minority
interests not recorded in the financial statements as presented.
Hedging:
The Company’s policy is to hedge no more than 25% of production at any given time and to reduce risk due
to price volatility. In September 2005 the company entered into a costless collar for 1,000 GJ per day with
floor and ceiling prices set at $11.00 and $19.00/GJ respectively for the winter months commencing
November, 2005 and ending March, 2006.
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Related party transactions:
(a) Other than as disclosed elsewhere, the Company paid or accrued the following during the nine
months ended November 30, 2005
(i) consulting fees of $443,189 for the nine month period (2004 - $345,039) and $150,578
for the three month period (2004 - $140,738) to companies controlled by senior officers of
the Company.
These transactions are in the normal course of operations and are measured at the exchange
amount which is the amount of consideration established and agreed to by the related parties.
Outlook:
The interpretation of the Viking 3D seismic program shot in the second quarter was encouraging and greatly
assisted in defining the development program for this area. The Viking drilling program commenced in mid-
January and Choice anticipates drilling 7 - 15 wells in the area before spring break-up. Drilling of a deeper
test well in the Brewster area is underway with drilling at Kakwa to follow directly. Both of these test wells
have the potential to highly impact both reserves and production for the Company. Choice has commenced
drilling in the Snipe / Wallace area, where up to nine wells could be drilled this winter.
Over the course of the coming year, Choice intends to continue its active exploration program and is
anticipating drilling up to 55 gross wells (30 net). A capital budget for the next year is expected to be in the
$26.00mm range if all of the programs are undertaken. This is an aggressive program that has taken the
Company some time to assemble, however management believes that these plays comprise a sound
balance between exploration and development and provide an appropriately risked portfolio of plays.
Critical accounting estimates:
The preparation of financial statements that conform with Canadian generally accepted accounting principles
requires management to make the following estimates and assumptions that affect the reported amounts of
assets and liabilities at the date of the financial statements and revenues and expenses for the period then
ended.
Full Cost Accounting – The Company follows the full cost method of accounting. All costs for exploration and
development of reserves are capitalized in a country by country cost centre; the costs are then depleted on
the unit of production method based on estimated proved reserves. The capitalized costs can not exceed a
ceiling amount. If the capitalized costs are determined to be in excess of this reserve based ceiling amount,
the excess is written off. An alternative method of accounting for oil and natural gas operations is the
successful efforts method. Under this method the cost centre is defined to be a property rather than a
country cost centre and exploratory dry holes and geological and geophysical costs are charged to earnings
when incurred.
Reserves – The Company engages independent qualified reserve evaluators to evaluate its reserves each
year. Reserve determinations involve forecasts based on property performance, future prices, future
production and the timing of expenditures; all these are subject to uncertainty. Reserve estimates have a
significant impact on reported financial results as they are the basis for the calculation of depreciation and
depletion. Revisions can change reported depletion and depreciation and earnings; downward revisions
could result in a ceiling test write down.
Asset Retirement Obligation – The company provides for the estimated abandonment costs using a fair
value method based on cost estimates determined under current legislative requirements and industry
practice. The amount of the liability is affected by the estimated cost per well, the timing of the expenditures
and the discount factor used. These estimates will change and the revisions will impact future depletion and
depreciation rates.
Stock Based Compensation – The stock option plan provides for granting of stock options to directors,
officers, employees and consultants. Beginning in 2003, the Company is recording a charge against
earnings for all options granted after March 1, 2003. The basis for this expense is the Black-Sholes
valuation model. None of the Company’s awards call for settlement in cash or other assets.
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Change in Accounting Policies - Transportation Costs - Effective for fiscal years beginning on or after
October 1, 2003, the CICA issued Handbook Section 1100 “Generally Accepted Accounting Principles”
which defines the sources of GAAP that companies must use and effectively eliminates industry practice as
a source of GAAP. In prior years, it had been industry practice for companies to net transportation charges
against revenue rather than showing transportation charges as a component of operating expense on the
consolidated statement of income. Effective March 1, 2003, the Company has recorded revenue gross of
transportation charges and has recorded transportation charges as an operating expense on the
consolidated statement of income.
Forward looking Statements:
Certain information regarding the Company as set forth in the MD&A, including management’s assessment
of the Company’s future plans and operations, contain forward looking statements that involve substantial
known and unknown risks and uncertainties. These forward looking statements are subject to numerous
risks and uncertainties, certain of which are beyond the control, including the impact of general economic
conditions, industry conditions, volatility of commodity prices, currency fluctuation, imprecision of reserve
estimates , environmental risks, taxation policies, competition from other producers, the lack of qualified
personnel or management, stock market volatility and the ability to access sufficient capital from external or
internal sources. The actual results, performance or achievement could materially differ from those
expressed in, or implied by, these forward looking statements and, accordingly, no assurance can be given
that any of the events anticipated by the forward looking statements will transpire or occur, or if any of them
does, what benefits the Company will derive there from.