Choice Resources Corp.

Choice Resources Corp.

June 28, 2005 19:11 ET

Choice Announces February 28, 2005 Year End Financials

CALGARY, ALBERTA--(CCNMatthews - June 28, 2005) - Choice Resources Corp. (TSX VENTURE:CZE):

The progress of the Corporation in the last year was excellent. The goals and accomplishments are significant over the past year. Net income was 7 cents per share and cash flow was 21 cents per share. Reserves growth was also substantial as previously press released.

For the year ended Feb 28th;

- Net income was $2.9 million or 7 cents per share compared to a loss for the previous period.

- Production is up 11% averaging 1,336 boe/d.

- Assets were rationalized with the sale of a minor property in December and the purchase of a new area for exploration and development in the Snipe Lake area of Alberta.

- Cash flow from operations is up over 120% at $8.8 million or 21 cents per share.

- G&A is reduced by 15% for the year after the addition of significant exploration efforts.

- Net debt is reduced by 37% and this was further reduced subsequent to year end.

- Several new exploration plays were added to the portfolio.

- Reserves are up over 30% after production and production was replaced by over 3 times.

- Reserves value is up 35% and will be reflected in our net asset value.

- A Coal Bed Methane play is being exploited.

- Interest expense has been reduced over 80% on a year-to-year basis.

Continuous improvement in the Corporation is ongoing and showing results. As previously mentioned, the management team has reduced debt, reduced G&A, added several high quality exploration plays, acquired seismic over our key operating areas and identified a high impact exploitation opportunity at Pincher Creek with a resource base of between 30 and 80 Bcf potential. The Corporation is now finalizing terms for a horizontal well at Pincher Creek.

Several exploration wells are being completed and tested to determine the ultimate reserves. The Corporation is starting to realize the results of a significant exploration effort. Reserves are up 30% after taking account the current years production and the value of the reserves is increased 35%.

For the fourth quarter production was reduced due to significant downtime related to weather, a process interruption at Pincher Creek and the sale of a 65 boe/d property. Last years fourth quarter by comparison included significant flush production from a 25 well drilling program done in the fall of last year.

Cash flow at 21 cents per share is on target with internal projections. The quarterly cash flow was 6 cents per share.

Our exploration play inventory continues to grow. Land was purchased in our key exploration areas subsequent to year end and several exploration wells were drilled at Kaybob, Ponoka and Snipe Lake at or subsequent to year end. All these wells were cased. Choice Resources Corp. and Vecta, a private corporation have shot 2 seismic programs in the Chalmers and Gilby areas and will be deciding on a well after final processing and analysis. This program covers 13 section of land with a moderate depth target of less than 2200 meters.

Net debt continues to be reduced as the Corporation rationalized 2 minor properties for $2.4 million. Subsequent to year end the Corporation completed an equity offering for $7.5 million. Net Debt currently sits at approximately $10 million.

Management is very pleased with the results to date and looks forward to some significant reporting during the year as our exploration and development program for 2005 is implemented. The comparison below highlights the financial and operating results of the three month periods and annual periods between 2004 and 2005. Enclosed are the financial statements themselves and a management discussion and analysis. Please refer to the filings on Sedar for the notes to the financials.


Certain statements contained herein constitute forward-looking statements. The use of any of the words "anticipate", "continue", "estimate", "expect", "may", "will", "project", "should", "believe", and similar expressions are intended to identify forward-looking statements. These statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking statements. The Corporation believes the expectations reflected in those forward-looking statements are reasonable but no assurance can be given that these expectations will prove to be correct and such forward-looking statements included in this report should not be unduly relied upon. These statements speak only as of the date of this presentation. The Corporation does not undertake any obligation to publicly update or revise any forward-looking statements.

Quarter and Year ended February 28, 2005

($000 except per unit and where noted)
(Per share #'s are based on the weighted average # of shares issued and
outstanding during the period)

2005 2004 2005 2004
-------- --------- -------- --------
Gross Sales Revenue 5,651 6,714 19,981 16,618
Net Sales Revenue (after royalties) 5,189 5,556 16,792 13,010

Cash Flow 2,617 654 8,824 4,009
Per Share (basic) $ 0.06 $ 0.03 $ 0.21 $ 0.35

Net Income 1,018 (71) 2,965 (1,156)
Per Share (basic) $ 0.02 $ 0.00 $ 0.07 $ (0.10)

General & Administrative Expense 485 75 1,336 1,565

Capital Expenditures MM$ 3.17 approx. 0 10.09 33.83

Net Debt (excluding capital lease) 16.56 26.81 16.56 26.81

Shares Outstanding (millions)
Weighted Average (basic) 46.7 19.7 43.0 11.6

Natural gas (mcf/d) 7,233 9,308 7,700 6,717
NGL (bbls/d) 66 102 48 86
-------- --------- -------- --------
Boe/d 1,271 1,654 1,332 1,205

Gas $/mcf $ 8.08 $ 7.44 $ 6.72 $ 6.22
Liquids $/bbl $61.80 $40.27 $54.63 $39.24

Reserves (as at fiscal year end)
Natural Gas (Bcf)
Proven 30.4 25.9
Proven Plus Probable 40.0 33.8

NGL (Mbbl)
Proven 676 800
Proven Plus Probable 836 966

Present Value (10% before Tax) 61.3 45.5
(proven + Probable $ million)

The Company's year end is February 28, 2005. However, reference may be to the 2004 year meaning all operations to the end of February 28, 2005.

Management's Discussion & Analysis

Year Ended February 28, 2005 as compared to February 29, 2004

This Management Discussion and Analysis should be read in conjunction with Choice Resources Corp. ("Choice Energy Corp.") audited consolidated financial statements and corresponding notes for the years ended February 28, 2005 and February 29, 2004. This commentary is based on information available at June 22, 2005. Additional information relating to Choice Resources Corp. is available on SEDAR at

For the purposes of calculating unit costs, natural gas has been converted to a barrel of oil equivalent ("BOE") using six thousand cubic feet equal to one barrel of oil unless otherwise stated. This conversion conforms to Canadian Securities Regulators National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities. BOE's are a very approximate comparative measure that, in some cases, could mislead particularly if used in isolation. Certain measures in this MD&A do not have any standardized meaning as prescribed by Canadian generally accepted accounting principles ("Canadian GAAP") such as cash flow, cash flow per share - basic, cash flow from operations, and netback from operations. Therefore, they are considered non-GAAP measures and may not be comparable to similar information presented by other issuers. These measures have been described and presented in order to provide shareholders and potential investors with additional information regarding the Company's liquidity and its ability to generate funds to finance its operations. Management's use of these measures has been disclosed further in this MD&A as they are discussed and presented.

Corporate History

Choice Resources Corp. is a publicly traded Company, amalgamated under the Business Company Act of British Columbia and continued on September 29, 2004 under the Business Company Act of Alberta.

This Management Discussion and Analysis along with the associated financial statements referenced above include the accounts of the Company and its wholly owned subsidiaries Brigus Resources Ltd. and Brigus Energy Ltd. including the wholly owned Brigus Limited Partnership.

The Company's principal business is the exploration, development and production of natural gas and associated liquids in Western Canada principally in the Province of Alberta.

Choice in late 2002 acquired the Pincher Creek, Alberta natural gas producing property and then in May 2003 completed the acquisition of Brigus Resources Ltd. The Company acquired additional interests in the Viking and Bow Island areas where the Brigus properties were situated and commenced a significant development drilling program in these areas. These activities were largely financed utilizing debt and soon the Company found itself in a highly leveraged debt position. As well the Company had few exploration opportunities and did not have the full complement of professional and technical staff to develop new oil and gas prospects or to properly and fully exploit the existing asset base.

In February 2004 a new management team was appointed and shortly thereafter the Company changed its head office from Vancouver to Calgary. Over the course of this past year the Company has raised significant amounts of new equity and reduced the excessive levels of debt, including the recently announced May 2005 equity financing. Choice, since March 2004, has raised over twenty million dollars in additional share capital and with the hiring of a new team of professional and technical employees and consultants has matured into a full cycle exploration, development and production company.

Annual Information February 28, February 29, February 21,
2005 2004 2003

Total Revenue $19,981,132 $16,617,958 $ 2,068,406

Net Income (loss) $ 3,853,576 $(1,722,559) $ 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:


100% Working Interest
41section Choice Operated Unit
Extremely Long Life Reserves
3D&2D seismic data
Numerous High Impact Drill Locations

Production from the Pincher Creek Unit remains strong. Efforts to
improve operations and enhance production resulted in an increase in
production from existing wells over last year's production. Pincher
Creek began the year with net sales of 1.85 mmcf/d and closed the year
at 2.16 mmcf/d.

The Pincher Creek Gas Plant is a mix of in-use compression and
dehydration equipment and idle sulfur treating facilities. A 10-year
plan was devised to remediate the unused portions of the plant and
salvage the component with value. This plan was embraced by the AEUB as
positive steps to improving the area developments and meeting our
environmental obligations. The remediation activities planned for the
2004-2005 year were carried out very successfully ahead of schedule and
under budget. The 2005-06 activities are being scheduled.

During the year significant technical data on pressure and seismic were
reviewed and a well re-entry was attempted. The well produced at a peak
of 1.7 million per day of raw gas but was abandoned after mechanical
problems were encountered as a result of human error in the completion
techniques. The Company learned a great deal about the reservoir and
completion techniques and the amount of gas remaining in this portion
of the reservoir implies significant future opportunities. The
exploitation team will be assessing this and other similar
opportunities during the year.

The Pincher Creek Unit is comprised of thrusted sheets making up a
number of segregated high-pressure pools of gas and condensate. A six
square mile 3-D seismic program shot last summer displays the south gas
pool and reinforces the pressure survey models. A series of development
activities to exploit untapped pool with substantial remaining reserves
is being devised for next year's drilling and work over programs.

Plans are in place to drill a horizontal development well in the South
Pool as defined by seismic, decline curves and pressure surveys. A
resource base of 30 to 80 Bcf of raw gas has been identified. Due to
the expensive nature of the well a portion of the costs will be farmed
out to a third party or parties.

Production / sales averaged 1.92 mmcf/d with sales of 48 barrels / day
of NGLs during the year (368 BOE/d). Current sales are 374 BOE/d.


100% Working Interest in Lands and Facilities (26 sections of land)
Choice Operated
Multi Zone Potentials

The Bow Island area was exposed to several seismic operations and
reservoir analysis to determine an appropriate development program. Two
exploration and one development well were drilled and completed over he
past year adding some 100 boe/d to the area's long term production and
offsetting declines.

Plans for this area will include completing a Sawtooth discovery oil
well and expanding the facilities and infrastructure to the north to
tie in stranded gas wells and take on third party processing.

Three sections of non-core land were also sold for a cash consideration
of $400,000. These lands were prospective for Milk River / Medicine Hat
zones and the Company through it's analysis of these types of plays
determined that a much more significant land block (approx. 36 sections)
is required to make a decent impact on share price. The strategy for
this play was to sell or farm-out and the opportunity for a sale was
realized. Sales averaged 1.22mmcf/d for the year (203BOE/d). Current
production is 174 BOE/d and one well is waiting on completion to be put


Multi zone Potential
Extensive high working interest lands and facilities (approx. 80% owned
and operated)

Production from the Viking area is derived from 7 localized areas, each
with its own unique opportunities and potential. A significant effort
was made over the past year to shoot and evaluate seismic, geologically
map and evaluate the potential for developing these areas. These
efforts were met with exciting results.

Proving up the geophysical interpretations came from the drilling and
completion of 7 development and exploration wells. Horizons were mixed
between deep new pools, shallow gas and Coal Bed Methane prospects. All
of the wells were cased and tied in with the exception of one that was
awaiting a frac stimulation at year end.

A Mannville Coal Bed Methane (CBM) program was conducted to test the
viability for CBM recoveries in this area. Three wells were placed on
production. One well was cored and was analyzed, yielding 1.4 BCF per
section gas in place for this Mannville Coal. A down spacing
application is before the AEUB to drill up to 4 wells per section in
the first phase of an extensive CBM Development. Production is expected
to be 100 to 200 mcf/d per well.

The Viking area is also characterized by layers of regional and
channeled reservoirs throughout at the Mannville level (generally above
1000 meters in depth). An extensive 3-D program over existing and
future Choice lands is expected to yield a 20-well deep drill program.
This is expected to commence later this year. Targets are in the
Mannville and are generally between 0.5 and 1.5 Bcf. Choice is
currently in negotiations with several offsetting mineral holders to
partner with and to increase the size and scope of this program.

Choice was successful in divesting of a developed area while
successfully acquiring strategic lands within key development areas. A
small non-operated property at Sedgewick (approx. 65 boe/d) was sold for
$2 million. This property was non-core and the value received helped
reduce our debt to cash flow ratio.

Sales averaged 4.6 mmcf/d over the year. (765 BOE/d) Current sales
average 784 BOE/d.


Choice began the year with minimal to no exploration opportunities.
Strategies were selected to acquire properties in areas where there was
minimal drilling, good available land, significant room for growth and
the opportunity to hold a significant working interest. The Company
focused its exploration efforts in an area west of the 5th Meridian and
northwest of Edmonton. Through a combination of farm-ins and
acquisitions the Company established a core exploration area with high
impact potential. In this area the potential for 10 to 30 Bcf
discoveries exists and the Company conducted a significant 2D seismic
acquisition program during the year. Four of these prospects were
tested during the year and all wells were cased for further evaluation.


Multi zone Potential
Large tracts of undeveloped lands
Majority Choice Operated
High Impact Well Potential

The original interests came in the form of a farm-in in the Goose River
area with the drilling of an exploration well to earn interests in four
sections of undeveloped land. This was followed by an acquisition of 36
sections of land in December 2004. Working interests are between 18 and
49%, with an average of 30%. Subsequent to year end, an additional four
sections of land were acquired at an average working interest of 33%.

Three wells were put on stream at or shortly after year end with one
well producing 2 million scf/d from 2 zones (working interest 35%), one
well doing 0.5 million per day and the other well doing a modest 30
barrels per day of light oil (working interest 40%).

Future activities in this area will see a series of development and
exploration wells being drilled and extensive seismic programs to
assist in the mapping and development.

The Company plans at minimum of four wells to be drilled in the next
year in this area.

No sales were recorded in this area during 2004 and current production
averages 2.5 mmcf/d on a gross basis. (0.95 mmcf/d net)


Multi zone Potential
Large tract of undeveloped lands
Choice Operated
High Impact Well Potential

A significant amount of land has been accumulated in the Wallace area.
Seven and 3/4 sections are available from a farm-in during the year. In
addition 6 sections were acquired subsequent to year end. Two wells are
planned for this area during 2005. Average working interest is 50%.


Multi zone Potential
High Impact Well Potential

This area was drilled subsequent to year end. The well is being
completed. Two wells are planned for this year. Working interest are


Multi zone Potential
3D seismic coverage
High Impact Well Potential

This well was drilled and cased at year end and is being completed in
May and June.
One well is targeted in this area prior to year end. Average working
interest is 25%.


Multi zone Potential
3D seismic coverage
High Impact Well Potential
Working interest up to 25%

This program utilizes proprietary seismic technology from a third party
and was optioned in late 2004 and seismic is being reviewed with a well
to be determined by September. A location is budgeted for this year.


3D seismic coverage
High Impact Well Potential
Working interest up to 33%

This program utilizes proprietary seismic technology from a third party
and was optioned in late 2004 and seismic is being reviewed with a well
to be determined by July. One well is budgeted for this year.

2004 Operation Summary

Choice is a natural gas producer. Essentially 100% of the production revenues are derived from natural gas and natural gas liquids (including sulphur as a by-product in the Pincher Creek area). In the year ended February 28, 2005 the Company increased its produced sales volumes of gas 13% to 2,811 mmcf from 2,493mm in the prior year.

Natural gas production averaged 7,700 mcf per day compared to 6,717 mcf per day last year. The increase reflected the first complete year of production from the Brigus Resources Ltd. acquisition of May 2003. The total natural gas liquids (NGLs) production was 17,701 barrels compared to 31,421 in the prior year. The decrease in NGL production reflects a revision in liquids allocated at the processing plant in the Pincher Creek / Waterton area and significant downtime at Shell's Waterton plant during the year (3 weeks down during the summer months and 2 weeks in the winter). NGL production averaged 49 barrels per day compared to 85 barrels per day in the comparable period last year.

The average daily production rates for the years ended February 28, 2005 and February 29, 2004 (expressed in barrel of oil equivalents) were 1,346 and 1,217 BOE per day respectively. Production volumes were up by 11% compared to last year.

Natural gas prices for the year averaged $6.73 compared to $6.68 for the prior year. NGL prices averaged $56.47 in the current year compared to $39.24 last year. Overall prices per BOE for the year ended February 28, 2005 were $40.88 compared to $36.34 for the year ended February 29, 2004. This is an increase in the price per BOE of 12% above last year and reflects the general price increases experienced in the upstream sector of the oil and gas industry this past year.

Summary of Quarterly
Results (8 quarters)

4th Quarter 3rd Quarter 2nd Quarter 1st Quarter
28-Feb-05 30-Nov-04 31-Aug-04 31-May-04

Gross revenue $ 5,527,444 $ 4,309,546 $ 4,959,014 $ 5,185,128

Net income (loss) $ 1,018,089 $ 621,829 $ 418,070 $ 907,083

Net income (loss)
per share -
basic and diluted $ 0.02 $ 0.01 $ 0.01 $ 0.03

4th Quarter 3rd Quarter 2nd Quarter 1st Quarter
29-Feb-04 30-Nov-03 31-Aug-03 31-May-03

Gross revenue $ 6,592,718 $ 4,025,200 $ 4,308,863 $ 1,691,177

Net income (loss) $ (70,897) $ (991,587) $ (148,968) $ 55,247

Net income (loss)
per share -
Basic and diluted $ (0.00) $ (0.05) $ (0.01) $ 0.01


Gross revenue from natural gas and related products for the year increased 20% to $19.98mm over the prior year figure of $16.62mm. On a BOE basis, prices were up 9% to $41.11 from $37.67. Total revenue was up due to an 8% increase in price and a 12% increase in sales volumes. Revenue and operating expenses have been restated for the prior year to reclassify the natural gas transportation costs as operating costs rather than netting these with revenue as required by the new accounting guidelines. (Refer to Financial Statement note 3(b), Changes in Accounting Policies.)


Royalties for the year decreased by 12% to $3.2mm from $3.6mm last year and reflect a revision in crown royalties in Pincher Creek, which saw the Company reduce its royalties on injection gas. This credit was recorded in the fourth quarter of the year as it became apparent the Company could reduce its crown royalties at this facility.

Overall, royalties as a percentage of gross revenue decreased to 16% from 22%, or $6.56 per BOE compared to $8.18 per BOE for the same period last year.

Production and Operating:

Operating expense for the year increased by 6% to $5.82mm compared to $5.51mm last year. This increase in total operating costs reflects an increase in produced volumes and down time at the Shell Waterton Pincher Creek facility as well as downtime experienced due to cold-weather related incidents in the winter months and a reclassification of transportation costs from oil and gas revenue.

On a BOE basis, operating costs are down 4%. On a dollars per BOE basis, operating costs were $11.97 / BOE versus $12.49 / BOE respectively. Prior to the required transportation adjustment, operating costs on a BOE basis were $10.67 and $11.42.

General and administrative expenses:

General and administrative expenses were $1.34mm compared to $1.57mm, which is a decrease of 15%. G&A per BOE was $2.75 compared to $3.55 last year. The Company capitalized $730,945 in G&A to property, plant and equipment this year compared to $NIL last year. Choice in fiscal 2005 in establishing itself as a full cycle exploration company hired a complete technical team of geologists, geophysicists and engineers. Approximately 30% of all G&A costs are directed toward these longer term exploration efforts and accordingly these costs are capitalized as property, plant and equipment assets.

The Company in the past year has developed a dozen quality exploration plays and done a technical review on the existing properties including an evaluation of the Pincher Creek assets which has led to the work-up of the high impact development play in Pincher Creek.

Interest and financing expense:

Interest expenses were only 20% of what they were in the prior year. Interest charges were reduced substantially reflecting the new equity that has been raised replacing debt over the past year, specifically the repayment of the bridge loan. In the prior year there were certain charges to interest that related to the extensions to the bridge facility. This facility was repaid in March 2004. Overall financing costs this year were $1.68 per BOE compared to $9.19 last year which illustrates the success of the restructuring efforts of the new management team.

Depletion, depreciation, and accretion:

The depletion, depreciation and accretion provision increased to $4.41mm from $3.30mm or $9.07 per BOE compared to $7.48 last year. As a percentage of revenue it was consistent with the prior year at 22% compared to 20% for the prior year.

Income taxes:

Choice has available over $23.0 mm in income tax pools at the end of February 2005. The Company has spent $3,088,530 to February 28, 2005 in exploration expenditures to certain investors who subscribed for flow through shares of the Company.

At February 28, 2005 the Company had to expend $5,420,670 to the end of December 31, 2005 to fulfill its obligation to these subscribers under the flow through renouncement program. The major components of the Company's tax pools at February 28, 2005 are as follows (in 000s):

Tangible capital $ 4,300
Canadian oil and gas property expense 8,600
Canadian development expense 6,100
Other 4,600

Net income and cash flow from operations:

Cash flow from operations (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 120% to $8.82mm ($0.21 per share) from $4.01 ($0.34 per share). This increase in cash flow reflects the significant decrease in interest expenses as equity was substituted for debt as well as increases in production revenues and decreases in royalties. Per share amounts reflect the restructuring.

The Company recorded net income of $2.97mm ($0.07 per share) compared to a loss of $1.16mm ( $.10 per share) last year.

Per share amounts have been calculated on a basic and fully diluted basis as the warrants are considered non-dilutive.

Liquidity and capital resources:

The past fiscal year has seen Choice reduce its highly leveraged debt position through a series of equity offerings commencing in March 2004. The Company has raised over $13,000,000 in new equity this past year and subsequent to year end in May 2005 closed another equity financing of $7,500,000. This has allowed the Company to reduce its debt to acceptable levels that should translate into a debt-to-cash flow ratio of less than one to one.

Management feels that the Company is financially sound and that its planned capital program for the coming fiscal year can be financed from cash flows generated from operations.

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 $391,509. 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.

The Company has a credit facility for up to $20,000,000 with a major Canadian chartered bank. At year end the Company had drawn $12,750,000 against this credit. Also, Choice has an additional acquisition and development facility of $5,000,000 but it has not availed this facility to date.


During the year the Company entered into a costless collar for 1,000 GJ/d with a ceiling price of $10.30 / GJ and a floor price of $8.50 / GJ from December 1, 2004 to March 31, 2005. Subsequent to the year end, the Company entered into a fixed price swap for 1,000 GJ/d at a price of $7.11 / GJ for the period April 1, 2005 to October 31, 2005. 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.

Related party transactions:

(a) Other than as disclosed elsewhere, the Company paid or accrued the
following during the year ended February 28, 2005:

(i) management fees of $Nil (2004 - $123,500) to directors and a
company controlled by a director of the Company;

(ii) consulting fees of $394,400 (2004 - $Nil) to companies
controlled by senior officers of the Company.

(iii) consulting fees of $Nil (2004 - $10,000) and rent of $Nil
(2004 - $180,585) to companies controlled by significant
shareholders of the Company; and

(iv) share issue costs of $259,675 (2004 - $120,000) to a
significant shareholder 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.


Choice will focus during the coming fiscal year on growing its production and increasing its reserve base primarily through the drill bit. One of the major objectives in the forthcoming year is to drill and evaluate the development well in the Pincher Creek area as well as to further assess the future development plans for this high impact area. Also, the Company intends to further exploit its core areas including development drilling in the Viking and Bow Island areas. A major focus for the Company will be in the Snipe and Wallace areas in west central Alberta. Choice intends to follow up on its exploration successes in these areas with further exploration and development drilling and the construction of required production infrastructure.

The Company intends to drill 34 gross wells in fiscal 2006 including 9 exploration tests. The Company is targeting an exit rate of between 2,000 and 3,000 BOE per day. This is largely dependant on the level of participation we take in the high impact Pincher Creek development well expected to spud sometime in the summer of 2005.

Summary of Quarterly Results - fourth quarter:

Gross revenues for the three months ended February 28, 2005 were $5.52mm ($6.59mm for the three months ended February 29, 2004). This reduction in revenues was offset by a reduction in crown royalties. Revenues were lower by 16% due to the sale of the Sedgewick property (approximately 65 boe/d) and production being shut-in December and January due to weather related operational difficulties. In addition, last year's quarterly production reflected a large 25 well drilling program with flush production.

Royalties for the three months were down significantly to $0.46mm from $1.16mm as crown royalties were credited with gas injection royalty charges. The impact of this credit was felt in the fourth quarter as an allowance was granted for crown royalties pertaining to the injection gas utilized in the Pincher Creek field.

Operating costs at $1.88mm were lower by $0.78mm to $2.66mm. Production was down due to last year's flush production and this is reflected in the operating costs.

General and administrative expenses were $0.48mm in the current quarter compared to only $0.08mm in the fourth quarter of the year ended February 29, 2004. The fourth quarter last year had virtually no staffing or consultant costs as the Company was in transition from the Vancouver based management group to the Calgary team.

Depletion, depreciation and accretion increased by $0.26mm to $1.18mm. This increase reflects the higher base for the full cost pool which includes increased seismic and exploration expenses.

The amount recorded for stock based compensation increased to $0.33mm from $0.12mm reflecting the greater number of options vesting in the current period compared to those of last year in the comparable quarter.

Cash flow from operations was $2.62mm ($0.06 per share) in the current quarter compared to $0.65 ($0.03 per share) for the previous years' final quarter.

Net income (loss) for the fourth quarter of fiscal 2005 was $1.01mm ($.02 per share) compared to a loss of $0.71mm in the fourth quarter of fiscal 2004. ($.00 per share).

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 cannot 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.

Changes in Accounting Policies:

a) Effective March 1, 2004, the Company adopted CICA Accounting Guideline 13 "Hedging Relationships". This pronouncement establishes the criteria that must be met before an entity can apply hedge accounting to certain derivative financial instruments. The guideline has been applied on a prospective basis and had no impact on the results for the Company's year ended February 28, 2005. The Company's hedging contracts at February 28, 2005 are disclosed in note 16(c).

b) 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. This adjustment of $629,580 (2004 - $472,120) has no impact on net earnings, per common share calculations, or cash flow for the Company.

Choice Resources Corp.
Consolidated Balance Sheets
As At February 28, 2005 and February 29, 2004

February 28, February 29,
2005 2004

Current assets
Cash $ - $ 848,860
Accounts receivable and prepaid expenses 4,464,828 2,870,408
4,464,828 3,719,268

Property, plant and equipment (note 5) 45,519,928 39,531,723
Goodwill (note 4) 5,030,905 5,030,905
$ 55,015,661 $ 48,281,896

Current liabilities
Cheques in transit $ 1,095,511 $ -
Accounts payable and accrued liabilities 7,458,904 4,582,943
Obligation under capital lease (note 6) 101,517 93,768
Bank loan (note 7) 12,475,000 15,950,000
Loan payable (note 8) - 10,000,000
21,130,932 30,626,711

Obligation under capital lease (note 6) 463,805 565,322
Asset retirement obligations (note 9) 2,225,402 2,444,300
Future income taxes (note 10) 7,894,000 5,471,000
31,714,139 39,107,333

Shareholders' Equity
Equity instruments (note 11) 29,401,947 18,989,467
Contributed surplus (note 13) 1,078,342 328,935
Deficit (7,178,767) (10,143,839)
23,301,522 9,174,563
$ 55,015,661 $ 48,281,896

Commitments (note 16)

Subsequent events (note 19)

See notes to consolidated financial statements filed on Sedar.

Approved by the Board

(signed) "Gordon D. Harris" , Director

(signed) "Chris Cooper" , Director

Choice Resources Corp.
Consolidated Statements of Operations and Deficit
Years Ended February 28, 2005 and February 29, 2004

February 28, February 29,
2005 2004

Oil and natural gas sales $ 19,981,132 $ 16,617,958
Royalties (3,189,366) (3,607,698)
16,791,766 13,010,260

Production 5,817,447 5,511,295
General and administrative 1,335,688 1,565,257
Interest on bank loan and loan payable 775,817 4,036,191
Interest on obligation under capital
lease 39,300 18,100
Stock-based compensation 559,407 303,000
Depletion, depreciation and accretion 4,410,530 3,298,976
12,938,189 14,732,819

Net income (loss) before income taxes 3,853,576 (1,722,559)

Income taxes (recovery) (note 10)
Current - 18,579
Future 888,504 (584,933)
888,504 (566,354)

Net income (loss) 2,965,072 (1,156,205)
Deficit, beginning of year (10,143,839) (8,987,634)
Deficit, end of year $(7,178,767) $(10,143,839)

Net income (loss) per share
Basic (note 14) $ 0.07 $ (0.10)
Diluted (note 14) $ 0.07 $ (0.10)

See notes to consolidated financial statements filed on Sedar.

Choice Resources Corp.
Consolidated Statements of Cash Flows
Years Ended February 28, 2005 and February 29, 2004

February 28, February 29,
2005 2004
Cash provided by (used for):
Operating activities
Net income (loss) $ 2,965,072 $ (1,156,205)
Items not affecting cash
Depletion, depreciation and accretion 4,410,530 3,298,976
Stock based compensation expense 559,407 303,000
Interest on loan payable (note 8) - 2,148,432
Future income taxes (recovery) 888,504 (584,933)
8,823,513 4,009,270

Change in non-cash working capital
(note 15) (486,546) (690,070)
8,336,967 3,319,200

Financing activities
Repayment of obligation under capital lease (93,768) (233,546)
Increase (repayment) in bank loan (3,475,000) 13,490,097
Proceeds (repayment) of loan payable (10,000,000) 10,000,000
Proceeds on issuance of common shares,
net of issuance costs 12,136,973 1,034,140
Proceeds on issuance of special warrants,
net of issuance costs - 5,453,963
(1,431,795) 29,744,654
Investing activities

Property, plant and equipment expenditures (12,496,779) (12,015,731)

Change in non-cash working capital
(note 15) 1,485,248 1,558,065
Proceeds on sale of property, plant and
equipment 2,161,988 -

Acquisition of Brigus, net of cash acquired - (21,813,215)
(8,849,543) (32,270,881)

Increase (decrease) in cash (1,944,371) 792,973
Cash and cash equivalents, beginning
of year 848,860 55,887
Cash and cash equivalents, end of year $ (1,095,511) $ 848,860

See notes to consolidated financial statements filed on Sedar.

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