Forte Resources Inc.

Forte Resources Inc.

March 22, 2005 09:00 ET

Forte Resources Announces 2004 Results


NEWS RELEASE TRANSMITTED BY CCNMatthews

FOR: FORTE RESOURCES INC.

TSX SYMBOL: FRZ

MARCH 22, 2005 - 09:00 ET

Forte Resources Announces 2004 Results

CALGARY, ALBERTA--(CCNMatthews - March 22, 2005) - Forte Resources Inc.
(TSX:FRZ) ("Forte") is pleased to announce its results for the year and
quarter ended December 31, 2004.

Financial

Revenue for 2004 was $38,482,351 which represented an increase of 107%
compared to revenue in 2003. Cash flow from operations was $16,176,396
($0.59 per share) compared to $7,670,408 ($0.48 per share) in 2003. The
net income reported for the year was $58,334 ($0.00 per share) compared
to net income in 2003 of $230,667 ($0.01 per share).

Cash flow from operations for the fourth quarter was $4,356,000 ($0.13
per share) compared to $1,907,000 ($0.12 per share) in 2003. The net
loss for the fourth quarter was $312,000 ($0.01 per share) compared to
net income of $125,000 (0.01 per share) in 2003.

Operations

During 2004 the Company drilled 26 wells (4.0 net) resulting in 6 wells
(3.5 net) cased for oil production, ten wells (4.0 net) cased for
natural gas production and 10 wells (4.8 net) dry and abandoned. Since
the end of 2004, 13 additional wells have been drilled (6.85 net)
resulting in 7 gas wells (3.56 net), 5 oil wells (2.89 net) and 1 well
(0.4 net) abandoned. Activity in the Company's major areas is summarized
as follows:

Leaman, Alberta - Since December, 2004 the Company has drilled four
Paleozoic test wells at working interests from 94 to 100%. The discovery
well has produced at rates in excess of 180 boe/d net to the Company
since being placed on production. The second well at Leaman has been
completed as a potential Paleozoic oil well. A third well has been
recently drilled and completed and flowed oil at a rate of 200 bbls/d
and natural gas at a rate of 1.0 mmcf/d on test. A fourth well has been
cased pending completion and testing while one well is currently
drilling. The Company expects to continue drilling after break up with
two wells planned. The Company can produce these wells at full
capability for the first four production months, after which they become
subject to the allowable production rates as set by the Energy and
Utilities Board. Ultimately the Company believes this pool may be a
candidate for waterflood to increase allowable production rates and
reserves recovery.

Redwater, Alberta - Three horizontal wells (1.5 net) were drilled,
completed and tied in during the first two months of 2005. Production
from the Redwater area net to the Company increased to 750 boe/d in
February 2005 primarily due to these wells. The Company anticipates
drilling three more horizontal wells and two vertical wells at working
interests ranging from 30% to 50% in the second and third quarters,
targeting the Basal Quartz and Bruderheim zones. The three recent
horizontal wells started production at rates of 450-700 bbls/d gross and
after two months are producing in excess of 300-500 bbls/d. Eventually
the wells are expected to stabilize at 75 bbls/d per well.

Laprise/Sojer, British Columbia - Forte has drilled a total of 14 (5.4
net wells) in the area this winter with 9 wells (3.4 net) completed as
gas wells, 2 wells (0.8 net) completed as oil wells and 3 (1.2 net) dry
holes. To date 6 wells have been placed on production and 2 wells that
tested at combined initial flow rates in excess of 250 boe/d net to
Forte's interest are yet to be tied in. A 50 square mile 3D seismic
program is nearing completion over Forte's lands or lands under control
in the area to evaluate Slave Point and Baldonnel potential. Forte has
participated in a well targeting the Slave Point formation. This well is
currently being evaluated. Forte has also participated in a Bluesky
discovery, which tested at 1.8 mmcf/d of natural gas, with numerous
follow up locations identified on the Company's acreage.

Webster, Alberta - Forte completed the drilling of this potential high
impact exploratory gas well to test for production from the Wabamun
formation in December, 2004. Log analysis shows potential for natural
gas, with a pay zone of 5 metres above a one metre zone that indicates
the potential for water production. Forte will be completing this well
in the second quarter of 2005 to determine its productive potential.
Should the well test gas the Company intends to conduct a seismic survey
prior to drilling additional wells on this prospect.

West Central, Alberta - Forte and its partner have drilled and completed
a dual zone lower cretaceous natural gas discovery which tested natural
gas at a combined rate of 3 mmcf/d (1.5 mmcf/d). Forte plans to drill 2
offset wells immediately after break up. Forte and its partner continue
to accumulate acreage in this prospect area.

Production

Average production for 2004 was 2,370 boe/d compared to 1,351 boe/d in
2003 Production during the fourth quarter averaged 2,458 boe/d compared
to 1,615 in 2003. With new wells tied in at Leaman and Laprise, the
production entering January, 2005 was approximately 3,000 boe/d.

Production for the month of February 2005 averaged 3,425 boe/d. In
March, 2005 the Company expects to tie in three additional wells with
initial production rates of 275 boe/d. In addition, there is
approximately 400 boe/d of production that has been tested and which is
anticipated to be tied in during the second quarter of 2005.

Reserves

The Company's reserves are evaluated annually by Sproule Associates Ltd.
The report indicates proved plus probable reserves of 6.454 million boes
and a net present value of $87.545 million discounted at 5%. (See the
M,D & A - Reserves for a more detailed discussion).

In March 2005 the Company entered into a binding letter of intent to
sell properties for $8.1 million. These properties which were estimated
to contain 123,000 boes of proven plus probable reserves with an NPV at
5% of $1.84 million were included in the above reserves. The transaction
is expected to close prior to March 31, 2005.

Liquidity

The Company will have a strong balance sheet as it enters 2005. While it
had net debt of $33.0 million at December 31, 2005 two transactions in
the first quarter of 2005 will strengthen the Company's financial
position significantly. On February 24, 2004 Forte raised approximately
$14.8 million of equity capital net of share issue costs. Additionally
during the first quarter Forte entered into a binding letter of intent
to sell certain properties for $8.1 million. These transactions will
reduce the Company's net debt to less than one-half of one year's
estimated future cash flow.

Outlook

For 2005 the Board of Directors has approved a capital expenditure
budget of $35.5 million to be expended on exploration and development
activities. The budget includes drilling approximately 50 gross (26.5
net) wells. Forte's 2005 capital program will focus on the following
areas:

- Evaluation of the 3D seismic program at Laprise/Sojer and
identification of potential future locations targeting the Baldonnel,
Bluesky, Coplin and Slave Point locations.

- Continue the development of the Redwater property with additional
horizontal wells targeting the Basal Quartz formation and vertical wells
to obtain production from the Bruderheim formation.

- Continued drilling and extensions to our West Central, Alberta
discovery.

- Additional drilling and development of the Leaman area Paleozoic oil
pool.

- Completion of the Webster well in the Wabamun formation and evaluation
of future drilling opportunities on the prospect. We will also continue
to drill for new pools in the Peace River Arch area where we have
scheduled wells targeting the Montney, Banff and Halfway formations.



------------------------------------------------------------------------
------------------------------------------------------------------------
Three months ended Year ended
December 31, December 31,
% %
HIGHLIGHTS 2004 2003 Change 2004 2003 Change
------------------------------------------------------------------------
FINANCIAL
($ Thousands except
per share data)
Oil and gas sales 12,019 5,154 133 38,483 18,630 107

Cash flow from
operations 4,355 1,907 128 16,177 7,670 111
Per share - basic 21 0.59 0.47 26

Net income (loss) (312) 125 (350) 58 231 (75)
Per share - basic 0.00 0.01 (100)

Capital expenditures
(excl. acquisitions) 13,178 2,044 545 22,518 20,923 8
Net debt 33,047 13,081 153 33,047 13,081 153
Average shares
outstanding - basic 27,642 16,143
Shares, end of
period - basic 37,117 16,399 37,117 16,399

OPERATIONS
Daily production
Oil and NGL's
(bbls/d) 1,811 1,336 36 1,735 1,161 49
Natural gas
(mcf/d) 3,877 1,671 132 3,811 1,137 235
Barrels of oil
equivalent (boe/d) 2,458 1,615 52 2,370 1,351 75

Average sales prices
Oil and NGL's
($/bbl) 57.73 32.53 78 46.12 37.53 23
Natural gas
($/mcf) 6.72 7.52 (11) 6.67 6.56 2

Barrels of oil equivalent are reported with a 6:1 conversion with
six mcf = one barrel
(1) See Non-GAAP measurements
------------------------------------------------------------------------


MANAGEMENT'S DISCUSSION AND ANALYSIS

The following discussion and analysis was prepared as at March 15, 2004
and is management's assessment of Forte's historical financial and
operating results and should be read in conjunction with the unaudited
interim consolidated financial statements of the Company for the three
months and year ended December 31, 2004, and the audited financial
statements and MD&A for the year ended December 31, 2003 together with
the notes related thereto. The reader should be aware that historical
results are not necessarily indicative of future performance. This
discussion contains forward-looking statements that involve risks and
uncertainties. Such information, although considered reasonable by Forte
at the time of preparation, may prove to be incorrect and actual results
may differ materially from those anticipated in the statements made.
Where converted to a barrel of oil equivalent basis, all natural gas
production results have been converted at the rate of six thousand cubic
feet to one barrel of oil equivalent ("boe").

Non-GAAP Measurements

The Management's Discussion and Analysis contains the terms cash flow
from operations, which should not be considered an alternative to, or
more meaningful than, cash flow from operating activities or net income
as determined in accordance with Canadian generally accepted accounting
principles as an indicator of the Company's performance. Forte's
determination of cash flow from operations may not be comparable to that
reported by other companies especially those in other industries. The
reconciliation between net earnings and cash flow from operations can be
found in the consolidated statements of cash flow in the unaudited
interim consolidated financial statements and the audited consolidated
financial statements. The Company also presents cash flow from
operations per share whereby per share amounts are calculated using
weighted average shares outstanding consistent with the calculation of
earnings per share.



Operating results

Forte's operating results in dollar terms and on a boe basis for the
three months ended December 31, 2004 and 2003 are provided below:

------------------------------------------------------------------------
Three months ended Three months ended
(unaudited) December 31, 2004 December 31, 2003 Difference
$000's $ boe $000's $ boe $000's $ boe
------------------------------------------------------------------------
Revenue
Oil and liquids 9,621 57.73 3,998 32.53 5,623 25.21
Natural gas 2,398 40.34 1,156 45.11 1,242 (4.77)
------------------------------------------------------------------------
12,019 53.16 5,154 34.70 6,865 18.46

Royalties 2,709 11.98 651 4.38 2,058 7.60
Operating 3,538 15.65 2,148 14.46 1,390 1.19
General and
administrative 880 3.89 290 1.95 590 1.94
Interest 338 1.49 140 0.94 198 0.55
------------------------------------------------------------------------
4,554 20.15 1,925 12.97 2,629 7.18

Stock option
expense 114 0.51 9 0.06 105 0.45
Depletion,
depreciation
and accretion 5,172 22.88 1,767 11.90 3,405 10.98
Income and
capital taxes (420) (1.86) 24 0.16 (444) (2.02)
------------------------------------------------------------------------
Net income (loss) (312) (1.38) 125 0.85 (437) (2.23)
------------------------------------------------------------------------

Forte's operating results in dollar terms and on a boe basis for the
year ended December 31, 2004 and 2003 are provided below:

------------------------------------------------------------------------
Year ended Year ended
(unaudited) December 31, 2004 December 31, 2003 Difference
$000's $ boe $000's $ boe $000's $ boe
------------------------------------------------------------------------
Revenue
Oil and liquids 29,209 46.12 15,906 37.53 13,303 8.59
Natural gas 9,274 40.00 2,724 39.38 6,550 0.62
------------------------------------------------------------------------
38,483 44.48 18,630 37.79 19,853 6.69
Expenses
Royalties 7,392 8.54 3,330 6.76 4,062 1.78
Operating 11,496 13.29 6,400 12.99 5,096 0.30
General and
administrative 2,125 2.46 876 1.78 1,249 0.68
Interest 972 1.12 336 0.68 636 0.44
------------------------------------------------------------------------
16,498 19.07 7,688 15.58 8,810 3.49

Stock option
expense 332 0.38 9 0.02 323 0.36
Depletion,
depreciation
and accretion 15,924 18.41 6,973 14.15 8,951 4.26
Income and
capital taxes 184 0.21 475 0.96 (291) (0.75)
------------------------------------------------------------------------
Net Income (loss) 58 0.07 231 0.45 (173) (0.38)
------------------------------------------------------------------------
------------------------------------------------------------------------


Revenue increased by 107% in 2004 and 133% in the fourth quarter
compared with the same periods of 2003. Production was 75% higher for
the year and 52% higher in the fourth quarter compared to the same 2003
periods. Although higher production volumes were the primary contributor
to higher revenues, the Company also benefited from higher commodity
prices. Oil revenue was impacted by hedging losses of $2.36 million
($3.73 per bbl) in 2004 and $1,495,000 ($3.53 per bbl) in 2003. The
following tables show the change in components of revenue:



------------------------------------------------------------------------
------------------------------------------------------------------------
Revenue Oil and Natural (unaudited)
($000's) Liquids Gas Total
------------------------------------------------------------------------
Three months ended December 31, 2003 3,998 1,156 5,154
Effect of change in prices 3,098 (122) 2,976
Effect of change in production 2,525 1,364 3,889
------------------------------------------------------------------------
Three months ended December 31, 2004 9,621 2,398 12,019
------------------------------------------------------------------------
------------------------------------------------------------------------

------------------------------------------------------------------------
------------------------------------------------------------------------
Revenue Oil and Natural (unaudited)
($000's) Liquids Gas Total
------------------------------------------------------------------------
Year ended December 31, 2003 15,906 2,724 18,630
Effect of change in prices 3,640 43 3,683
Effect of change in production 9,663 6,507 16,170
------------------------------------------------------------------------
Year ended December 31, 2004 29,209 9,274 38,483
------------------------------------------------------------------------
------------------------------------------------------------------------


Production increased by 1,019 boe/d or 75% for the year and 843 boe/d
or 52% for the fourth quarter. The following table shows the production
for each product:

------------------------------------------------------------------------
------------------------------------------------------------------------
Three months ended Year ended
December 31, December 31,
Production 2004 2003 2004 2003
------------------------------------------------------------------------
Crude oil (bbls/d) 1,705 1,200 1,638 1,099
Liquids (bbls/d) 106 136 97 62
------------------------------------------------------------------------
1,811 1,336 1,735 1,161

Natural gas (mcf/d) 3,877 1,671 3,811 1,137

BOE (boe/d) 2,458 1,615 2,370 1,351
------------------------------------------------------------------------
------------------------------------------------------------------------


Royalties averaged 19.2% of revenue for 2004 compared to 17.9% in 2003.
Average royalty rates for the fourth quarter were 22.5% compared to
23.3% in 2003. Royalty rates as a percentage of revenue calculated
before consideration of hedging losses were 18.1% for 2004 compared to
16.5% in 2003.

Operating costs increased by $0.30 per boe to in 2004 and $4.43 per boe
for the fourth quarter compared to the same 2003 periods. Forte's
northern oil properties still experience higher than average operating
costs due to water handling, power usage and servicing related to the
wells. Costs for repairs and maintenance and workovers exceeded
estimates and contributed $3.24 per boe to the incremental operating
costs.

General and administrative expenses in 2004 increased 140% on and
absolute basis and 37% on a boe basis. Costs increased in 2004 for
several reasons:

- As a result of increased production staffing levels increased from 11
employees at the end of 2003 to 20 employees at the end of 2004.
Associated costs for rent and office supplies also increased
proportionately.

- In 2004 Forte became a public company, resulting in a significant
increase in costs such as listing fees, corporate trust services,
investor relations, legal and accounting. These costs were significantly
less in 2003 when Forte was a private company.

General and administrative costs are reduced by amounts charged to joint
venture partners on a cost recovery basis and by capitalized costs.
Capitalized general and administrative costs represent the direct cost
of geological salaries and services that are related to the Company's
exploration program and are therefore capitalized as part of the cost of
oil and gas property and deducted from general and administrative
expense. The impact of cost recoveries and capitalized amounts is
summarized as follows:



------------------------------------------------------------------------
------------------------------------------------------------------------
General and Administrative Three months ended Year ended
(unaudited) December 31, December 31,
($000's) 2004 2003 2004 2003
------------------------------------------------------------------------
------------------------------------------------------------------------
Gross expenditures 1,223 515 3,340 1,846
Recoveries from partners 155 120 445 447
------------------------------------------------------------------------
1,068 395 2,895 1,399
Capitalized portion 188 105 770 523
------------------------------------------------------------------------
880 290 2,125 876
------------------------------------------------------------------------
------------------------------------------------------------------------


Interest expense, including bank charges, increased by $636,000 in 2004
primarily to higher loan balances and loan fees attributed to new credit
facilities incurred in the Denison and Oiltec acquisitions Forte's
interest rate on its revolving loan is the bank prime rate plus .4%.

Depletion, depreciation and accretion (DD&A) expense increased in 2004.
The D,D & A rate per boe of $18.41 for the year and $22.88 for the
fourth quarter was $4.26 and $10.98 higher per boe, respectively, than
the comparable periods of 2003. The DD&A rate increased due to the high
acquisition costs ascribed to the reserves acquired from Oiltec
Resources Ltd., which were acquired at a cost of $23.59 per boe.

The provision for income taxes is greater than would be expected because
of stock based compensation, which is not deductible for income tax
purposes and hedging losses, which are not deductible in calculating the
resource allowance for income tax purposes. In 2004 this was offset by
rate reductions as the future tax rate was reduced to 37.5%. The impact
of each factor is illustrated in the following table:



------------------------------------------------------------------------
------------------------------------------------------------------------
Provision for taxes Three months ended Year ended
(unaudited) December 31, December 31,
($000's) 2004 2003 2004 2003
------------------------------------------------------------------------
Net Income (loss) (732) 149 242 705
Tax rate 39.5% 40.75% 39.5% 40.75%

Expected provision (289) 61 96 287
Increase from

Stock option expense 43 3 124 4
Hedging impact - 17 166 137
Rate changes and other (374) (74) (523) 29
------------------------------------------------------------------------
(620) 7 (137) 457
------------------------------------------------------------------------
------------------------------------------------------------------------

Capital expenditures excluding corporate acquisitions are indicated
below:

------------------------------------------------------------------------
------------------------------------------------------------------------
Capital Expenditures Three months ended Year ended
(unaudited) December 31, December 31,
($000's) 2004 2003 2004 2003
------------------------------------------------------------------------
Acquisitions 422 129 1,191 11,085
Exploration, land and seismic 1,694 392 3,866 2,269
Drilling, completion and
workovers 9,319 767 14,217 4,571
Equipping 1,568 792 3,025 2,957
Other 175 (36) 216 40
------------------------------------------------------------------------
13,178 2,044 22,515 20,922
------------------------------------------------------------------------
------------------------------------------------------------------------


Reserves

The crude oil, liquids and natural gas reserves of the Company were
evaluated by the independent engineering firm of Sproule Associates
Limited ("Sproule"). All of the Company's properties were evaluated by
Sproule and each property where proved or probable reserves were
assigned, was evaluated individually with respect to geology, reservoir
characteristics, production history and economic factors influencing the
future revenue obtainable from the remaining reserves.

The reserve evaluation was reported to the Reserve Committee of the
Board of Directors for its review. The Board of Directors through the
Reserves Committee conducted certain due diligence and was satisfied
with the process that had been used in the preparation of the reserve
report. Presented below are summary tables of the Company's reserves as
at December 31, 2004 based on Sproule's January 1, 2005 price forecast.
All reserves are defined as the total remaining recoverable reserves
owned by the Company before the deduction of royalties. Reserve values
are based on forecasted product prices of Sproule effective January 1,
2005.



------------------------------------------------------------------------
------------------------------------------------------------------------
Reserves Natural
Crude Oil Natural Gas Gas Liquids
Reserves Gross Net Gross Net Gross Net
Category (Mbbls) (Mbbls) (MMcf) (MMcf) (Mbbls) (Mbbls)
Proved
Developed
producing 2,717.0 2,385.8 7,429 5,587 132.8 92.0
Developed
non-producing 16.5 15.7 262 200 2.8 2.2
Undeveloped 65.9 48.5 943 688 0.0 0.0
------------------------------------------------------------------------
Total proved 2,799.4 2,450.0 8,634 6,475 135.6 94.2

Probable 1,242.4 1,093.3 4,598 3,518 71.3 50.4
------------------------------------------------------------------------

Total proved
plus probable 4,041.8 3,543.3 13,232 9,993 206.9 144.6
------------------------------------------------------------------------
------------------------------------------------------------------------


------------------------------------------------------------------------
------------------------------------------------------------------------
Net Present Values of Future Net Revenue
Before Income Taxes Discounted At (%/year)
At (%/year)
Reserves 0 5 10 15
Category ($M) ($M) ($M) ($M)
------------------------------------------------------------------------
Proved
Developed producing 72,987 65,079 59,136 54,479
Developed non-producing 1,253 1,190 1,135 1,086
Undeveloped 3,639 3,103 2,718 2,412
Total Proved 77,879 69,372 62,989 57,977
------------------------------------------------------------------------

Probable 25,721 18,173 13,749 10,909
------------------------------------------------------------------------

Total proved plus probable 103,600 87,545 76,738 68,886
------------------------------------------------------------------------
------------------------------------------------------------------------


Reserve addition costs for drilling, completion and acquisition
operations including corporate acquisitions were $21.36 per boe. Reserve
addition costs related to exploration, development and drilling
activities were $21.37 per boe. Much of the Company's exploration
program occurred in the fourth quarter. Reserves for recent drilling
without an extensive production history are conservatively estimated.
Management believes that reserves assigned to the recently drilled
wells, which do not have extensive production history, have been
conservatively estimated as production from these wells becomes more
established there will be positive reserve additions in future years.



------------------------------------------------------------------------
------------------------------------------------------------------------
Finding and Development Costs
2004 2003 2002 Total
------------------------------------------------------------------------
Proven + probable
reserves added (mboe) 4,353 1,418 1,440 7,005

Capital expenditures ($000's) 92,986 20,985 16,739 130,710

Costs per boe 21.36 14.80 11.62 18.66
------------------------------------------------------------------------
------------------------------------------------------------------------

The detailed components of finding costs for 2004 were as follows:

------------------------------------------------------------------------
------------------------------------------------------------------------
Proven + Probable Costs
Reserves Incurred $/boe
------------------------------------------------------------------------
(Mboe) ($000's)

Denison acquisition 956 10,486 $10.96
Oiltec acquisition 2,288 59,981 $26.21
Leaman acquisition 95 850 $ 8.94

Drilling, extensions and revisions 1,014 21,669 $21.37
------------------------------------------------------------------------
4,353 92,986 $21.36
------------------------------------------------------------------------
------------------------------------------------------------------------


The Oiltec acquisition closed on June 23, 2004 by way of Plan of
Arrangement. Pursuant to the arrangement, Forte issued 10,515,935 common
shares and paid $11,864,000 for 100% of the outstanding shares of
Oiltec. In addition, Forte assumed Oiltec bank debt of $13,963,000. A
value of $59,400,000 was assigned to the petroleum and natural gas
properties acquired net of asset retirement obligations. The metrics of
this acquisition are summarized below:



Reserve value assigned net of land ($000's): 53,380
Proven and probable reserves (mboe): 2,288
Daily production (boe/d): 1,100
$/boe reserves: 23.59
$/boe/d production: 48,527


At December 31, 2004 the reserves acquired from Oiltec Resources Ltd.
were evaluated for the first time by Sproule. Following the acquisition,
production from key properties in the Redwater and Laprise areas
declined at a greater rate than anticipated. This was reflected in the
reserves assigned by Sproule, which were 1.8 million boes less than had
been assigned by Oiltec at their previous year end, December 31, 2003.

Liquidity - Forte has a $34.5 million revolving line of credit of which
$28.0 million is currently drawn. The revolving loan is demand in
nature, however, the credit limits are based on a borrowing base
calculation as determined by estimates of future cash flow from the
Company's assets. The borrowing base calculation is subject to review at
least annually with the next review scheduled for April 2005. The loans
have certain covenants including quarterly tests of the working capital
ratio, debt to equity ratio and debt to cash flow ratio.

On March 25, 2004 the Company issued 3.2 million shares at $2.50 per
share to raise $7.45 million net of share issue costs. In April 2004,
1,341,000 preferred shares, Series I, were converted to common shares
when the share price performance target of 20 consecutive trading days
above $2.23 per share was met. On July 20, 2004 the Company issued 2.0
million flow-through common shares at $3.85 per share to raise $7.7
million before consideration of share issue costs. On December 16, 2004
the Company issued 1,500,000 flow-through shares at $4.30 per share to
raise $6.45 million before consideration of share issue costs.

Management believes that the un-drawn credit line, cash flow from
operations and working capital is sufficient to fund the Company's
capital expenditure budget for 2005. In addition, the Company issued 4.0
million common shares at $3.90 for gross proceeds of $15.6 million on
February 24, 2005. Additionally, the Company entered into a binding
letter of intent to sell properties producing approximately 50 boe/d for
$8.0 million. The effect of these transactions on the Company's
liquidity is as follows:



($000's)
------------------------------------------------------------------------
Net debt and working capital deficit at December 31, 2004 (33,047)

Proceeds of February 24, 2005 financing,
net of issue costs 14,800
Proceeds of property sale 8,000
------------------------------------------------------------------------
Pro-forma net debt and working capital deficit (10,247)
------------------------------------------------------------------------


The pro-forma net debt and working capital is $24.25 million less than
the authorized credit line and with cash flow there should be sufficient
capital to fund the 2005 capital budget of $35.5 million. At December
31, 2004 there were 37,117,208 (March 15, 2005 - 41,153,708) common
shares outstanding.

Asset retirement obligations - A new Canadian accounting standard for
asset retirement obligations is effective for fiscal years beginning on
or after January 1, 2004. As a result of the implementation of this new
standard, the present value of the liability for future abandonment
costs has been recorded at $9.386 million at December 31, 2004. The
transitional provisions require that this standard be applied
retroactively with restatement of prior periods. As a result, 2003
comparative numbers have been restated as follows:



------------------------------------------------------------------------
------------------------------------------------------------------------
Financial Statements at December 31, 2003
($000's) As reported Change As Restated
------------------------------------------------------------------------
Capital assets 32,111 1,932 34,043

Asset retirement obligation - 2,878 2,878
Site restoration and abandonment 1,304 (1,304) -
Future income taxes 1,201 138 1,339
Retained earnings 452 200 672

Depletion, depreciation and accretion 7,198 (225) 6,973
Provision for income taxes 388 87 475
Net income 92 139 231
------------------------------------------------------------------------
------------------------------------------------------------------------


Financial Instruments

In October 2004 the Company entered into a forward sales contract for
500 bbls/d in the 2005 calendar year at a price of $58.30 Cdn. This
contract has been entered into with the company that purchases Forte's
crude oil and is settled monthly in conjunction with payment for crude
oil delivered under the Company's marketing agreement. A similar
arrangement was entered into on February 24, 2005 for 200 bbls/d for the
period from March 1, 2005 to December 31, 2005 at a price of $61.67 Cdn.
In December 2004 the Company entered into a similar contract with its
gas marketer to sell 500 mcf/d of its gas production at a price of $7.00
at AECO for the period from April 1, 2005 to October 31, 2005

Contractual Obligations

The Company has entered into various commitments related to the Calgary
office lease. The following table summarizes the outstanding contractual
obligations of the Company for its office lease for the next five years
and thereafter:



------------------------------------------------------------------------
($000's) 2005 2006 2007 2008 2009 Total
------------------------------------------------------------------------
(unaudited) 298 298 298 298 99 1,291
------------------------------------------------------------------------


Off-Balance Sheet Arrangements and Related Party Transactions

The Company has not entered into any off-balance sheet transactions
other than hedges or into any related party transactions. In addition,
Forte has assumed the office lease of Oiltec, which has approximately 4
years remaining at an annual cost of $135,000. The Oiltec office lease
has been sublet for no net cost to the Company for the remaining term of
the lease.



Selected Quarterly Information (1)

------------------------------------------------------------------------
2004
($000's except per share) Q4 Q3 Q2 Q1
------------------------------------------------------------------------
Revenue, net of royalties 9,310 10,835 6,430 4,516

Cash flow from
Operations 4,355 6,208 3,259 2,354
Per share - basic 0.13 0.17 0.14 0.15
Per share - diluted 0.15 0.16 0.13 0.12
Net earnings (312) 408 (70) 32
Per share - basic (0.01) 0.01 0.00 0.00
Per share - diluted (0.01) 0.01 0.00 0.00
Total Assets 129,424 126,359 121,568 50,114
Bank Debt 28,005 33,796 35,765 8,324
------------------------------------------------------------------------


------------------------------------------------------------------------
2003
($000's except per share) Q4 Q3 Q2 Q1
------------------------------------------------------------------------
Revenue, net of royalties 4,503 4,389 3,271 3,137

Cash flow from
Operations 1,908 2,364 1,574 1,825
Per share - basic 0.12 0.14 0.10 0.11
Per share - diluted 0.10 0.12 0.08 0.09
Net earnings 124 (453) 173 386
Per share - basic 0.01 (0.03) 0.01 0.02
Per share - diluted 0.01 (0.03) 0.01 0.02
Total Assets 37,688 35,603 36,507 24,801
Bank Debt 11,077 11,149 13,927 351
------------------------------------------------------------------------

(1) Unaudited and restated for changes in accounting policy related to
Asset Retirement Obligations.



Selected Annual Information (1)

------------------------------------------------------------------------
($000's except per share) 2004 2003 2002
------------------------------------------------------------------------
Revenue, net of royalties 31,091 15,300 3,687

Cash flow from operations 16,177 7,671 1,936
Per share - basic 0.59 0.48 0.13
Per share - diluted 0.56 0.39 0.10

Net earnings 58 231 467
Per share - basic 0.00 0.01 0.03
Per share - diluted 0.00 0.01 0.03
Total Assets 129,424 37,688 21,263
Bank Debt 28,005 11,077 823
------------------------------------------------------------------------

(1) Restated for changes in accounting policy related to Asset
Retirement Obligations.


Critical Accounting Estimates

Management is often required to make judgments, assumptions and
estimates in the application of generally accepted accounting principles
that may have a significant impact on the financial results of the
Company. A comprehensive discussion of the Company's significant
accounting policies is contained in Note 2 to the annual consolidated
financial statements. The following is a discussion of the accounting
estimates that are critical in determining the Company's financial
results.

(a) Full cost accounting

The Company follows the full cost method of accounting for exploration
and development activities whereby all costs associated with these
activities are capitalized, whether successful or not. The aggregate of
capitalized costs, net of certain costs related to unproven properties,
and estimated future development costs is amortized using the
unit-of-production method based on estimated proven reserves. Changes in
estimated proven reserves or future development costs have a direct
impact on depletion and depreciation expense.

Certain costs related to unproven properties and major development
projects may be excluded from costs subject to depletion until proved
reserves have been determined or their value is impaired. These
properties are reviewed quarterly to determine if proved reserves should
be assigned, at which point they should be included in the depletion
calculation, or for impairment, for which any write-down would be
charged to depletion and depreciation expenses.

The alternative method of accounting for oil and natural gas properties
and equipment is the successful efforts method. A major difference in
applying the successful efforts method is that exploratory dry holes and
geological and geophysical exploration costs would be charged against
net earnings in the year incurred rather than being capitalized to
property, plant and equipment.

(b) Oil and natural gas reserves

The Company's proved oil and gas reserves are 100 % evaluated and
reported on by an independent petroleum engineering consultant. The
estimation of reserves is a subjective process. Forecasts are based on
engineering data, projected future rates of production, estimated
commodity price forecasts and the timing of future expenditures, all of
which are subject to a number of uncertainties and various
interpretations. The Company expects that over time its reserve
estimates will be revised upward or downward based on updated
information such as the results of future drilling, testing and
production levels. Reserve estimates can have a significant impact on
net earnings, as they are a key component in the calculation of
depletion and depreciation. A revision to the reserve estimate could
result in a higher or lower DD&A charge to net earnings. Downward
revisions to reserve estimates could also result in a write-down of oil
and natural gas property, plant and equipment under the ceiling test.

(c) Full cost accounting ceiling test

The carrying value of property, plant and equipment is reviewed for
impairment. Impairment is determined by the carrying amount of the
property, plant and equipment exceeding the sum of the undiscounted cash
flows expected to result from the Company's proved reserves. Cash flows
are calculated based on third party quoted forward prices and adjusted
for the Company's contract prices and quality differentials. If there is
impairment, the magnitude of such impairment would be calculated by
comparing the carrying value of property, plant and equipment to the
estimated net present value of future cash flow from proved plus risked
probable reserves. A risk free interest rate is used to arrive at the
net present value of the future cash flows. Any excess carrying value
above the net present value of future cash flow would be recorded as a
permanent impairment and charged as additional depletion expense in the
consolidated statement of earnings. No write-down is required at
September 30, 2004.

(d) Asset retirement obligation

The Company recognizes the fair value of an asset retirement obligation
("ARO") in the period in which it is incurred when a reasonable estimate
of fair value can be made. The fair value of the estimated ARO is
recorded as a long-term liability, with a corresponding increase in the
carrying amount of the related asset. The capitalized amount is depleted
on a unit-of-production basis over the life of the reserves. The
liability amount is increased each reporting period due to the passage
of time and the amount of this accretion is charged to earnings in the
period. Revisions to the estimated timing of cash flow or to the
original estimated undiscounted cost would also result in an increase or
decrease to the ARO. Actual costs incurred upon settlement of the ARO
are charged against the ARO to the extent of the liability recorded. Any
difference between the actual costs incurred upon settlement of the ARO
and the recorded liability is recognized as a gain or loss in the
Company's earnings in the period in which the settlement occurs.

Determination of the original undiscounted costs is based on estimates
using current costs and technology in accordance with existing
legislation and industry practice. The estimation of these costs can be
affected by factors such as the number of wells drilled, well depth and
area specific environmental legislation.

(e) Future income tax

The Company follows the liability method of accounting for income taxes.
Under this method income tax liabilities and assets are recognized for
the estimated tax consequences attributable to differences between the
amounts reported in the financial statements and their respective tax
base, using substantively enacted future income tax rates. In June 2003,
the Federal Government introduced a gradual reduction in the general
corporate income tax rate over a five year period starting January 1,
2003. The impact of the new legislation requires the Company to schedule
out all existing temporary differences, identify the accounting and tax
values during the five year phase-in period for the declining tax rates
and recalculate the future income tax balance using tax rates in effect
when temporary differences reverse. The above noted forecasts of
estimated net revenue streams are utilized to calculate the future tax
provision and, as such, are subject to revisions, both upwards and
downwards, that are not known at this time. In addition to these
revisions, future capital activities can impact the timing of the
reversal of any temporary differences. These differences can have an
impact on the amount of future taxes determined at a point in time, and
to the extent that these differences are created, they can impact the
charge against earnings for future taxes.

(f) Stock-based compensation

The Company's Stock Option Plan provides for granting of options to
directors, officers and employees. The Company uses the fair value
method for valuing stock option grants. Compensation costs attributable
to share options granted are measured at fair value at the grant date
and expensed over the expected exercise time frame with a corresponding
increase to contributed surplus. Upon exercise of the stock options,
consideration paid by the option holder, together with the amount
previously recognized in contributed surplus is recorded as an increase
to share capital.

Outlook

Forte is a junior exploration and development company that historically
has focused on building a strong asset base through a strategy based
upon accretive acquisitions followed by production enhancement and
optimization operations combined with a grass roots exploration program.
Beginning in the fourth quarter of 2004 the Company increased its
emphasis on exploration and development activities to provide growth for
the Company.

For 2005 the Board of Directors has approved a capital expenditure
budget of $35.5 million to be expended on exploration and development
activities. The budget includes approximately 50 gross (26.5 net) wells.
Forte's 2005 capital program will focus on the following areas:

- Evaluation of the 3D seismic program at Laprise/Sojer and
identification of potential future locations targeting the Baldonnel,
Bluesky, Coplin and Slave Point locations.

- Continue the development of the Redwater property with additional
horizontal wells targeting the Basal Quartz formation and vertical wells
to obtain production from the Bruderheim formation.

- Continued drilling and extensions to our West Central, Alberta
discovery.

- Additional drilling and development of the Leaman area Paleozoic oil
pool.

- Completion of the Webster well in the Wabamun formation and evaluation
of future drilling opportunities on the prospect. We will also continue
to drill for new pools in the Peace River Arch area where we have
scheduled wells targeting the Montney, Banff and Halfway formations.

The oil and gas industry is experiencing a period of very strong world
oil prices and North American natural gas prices. Among analysts,
economists and experts of geo-political forces there seems to be an
emerging consensus that conditions should continue to remain favorable
for commodity prices for the near term. Although prices may soften
somewhat from current peak levels they may be susceptible to supply
disruptions in producing regions, which could result in price spikes
from time to time. Forte believes that the longer term outlook for oil
and gas prices is very favorable, reflecting the tight world supply and
demand balance, the growth in demand from China, India and the rest of
the world and the increasing costs to explore for and produce reserves.




Forte Resources Inc.
Consolidated Balance Sheet
($000's)
Unaudited December 31, 2004 December 31, 2003
------------------------------------------------------------------------
(restated Note 1 and 2)
Assets
Current
Accounts receivables 9,309 3,645

Capital assets 111,488 34,043
Goodwill (Note 4) 8,627 -
------------------------------------------
129,424 37,688
------------------------------------------

Liabilities and
shareholders' equity
Current
Accounts payable and
accrued liabilities 14,351 5,648
Bank loans (Note 3) 28,005 11,077
------------------------------------------
42,356 16,725

Asset retirement
obligations (Note 2) 4,707 2,878
Future income taxes 4,961 1,339
------------------------------------------
52,024 20,942
------------------------------------------
Shareholders' equity
Share capital (Note 5) 76,329 16,065
Contributed surplus 341 9
Retained earnings 730 672
------------------------------------------
77,400 16,746
------------------------------------------
129,424 37,688
------------------------------------------
------------------------------------------



Signed on behalf of the Board

______________________ ______________________
Doug N. Baker T. J. MacKay
"signed" "signed"



Forte Resources Inc.
Consolidated Statements of Income and Retained Earnings
($000's, except per share data)
unaudited
Three months Three months Year Year
ended ended ended ended
December 31, December 31, December 31, December 31,
2004 2003 2004 2003
------------------------------------------------------------------------
Restated Restated
- see - see
Notes 1 Notes 1
and 2 and 2
Revenue
Oil and gas 12,019 5,154 38,483 18,630
-------------------------------------------------------

Expenses
Royalties 2,709 651 7,392 3,330
Operating 3,538 2,148 11,496 6,400
General and
administrative 880 290 2,125 876
Interest 338 140 972 336
Stock base
compensation 114 9 332 9
Depletion,
depreciation
and accretion 5,172 1,767 15,924 6,974
-------------------------------------------------------
12,751 5,005 38,241 17,925
-------------------------------------------------------

Income (Loss)
Before Taxes (732) 149 242 705
-------------------------------------------------------

Provision for
future Income
taxes (620) 7 (137) 457
Capital taxes 198 17 321 17
-------------------------------------------------------
(420) 24 184 474
-------------------------------------------------------

Net Income (Loss)
for the Period (312) 125 58 231
-------------------------------------------------------

Retained Earnings
Beginning of
period, as
previously
reported 1,042 363 452 360
Change in
accounting
policy related
to asset
retirement
obligations
(Note 2) - 184 220 82
-------------------------------------------------------

Beginning of
period, as
restated 1,042 547 672 442
-------------------------------------------------------
-------------------------------------------------------

Retained Earnings,
end of period 730 672 730 672
-------------------------------------------------------

Shares Outstanding
(weighted average)
Basic 35,839,522 16,398,700 27,641,590 16,143,144
Diluted 37,523,472 16,398,700 28,997,023 19,506,557

Net Income
(Loss) Per Share
Basic and diluted (0.01) 0.01 0.00 0.01

See accompanying notes



Forte Resources Inc.
Consolidated Statements of Cash Flow
unaudited
($000's)
Three months ended Year ended
December 31, December 31,
2004 2003 2004 2003
------------------------------------------------------------------------
Restated Restated
- see - see
Notes 1 Notes 1
and 2 and 2

Operating Activities
Net Income (Loss) for the period (312) 125 58 231
Add items not requiring cash:
Depletion, depreciation
and accretion 5,172 1,767 15,924 6,973
Future income taxes (620) 7 (137) 457
Stock based compensation 115 8 332 9
--------------------------------------
Cash flow from operations 4,355 1,907 16,177 7,670

Site restoration expenditures (222) (62) (283) (62)
Changes in non-cash working
capital related to operating
activities 7,304 (929) 214 1,329
--------------------------------------
Cash provided by operating
activities 11,437 917 16,108 8,937
--------------------------------------


Financing Activities
Issue of common shares,
net of issue costs 6,131 - 20,869 397
Increase (decrease) in
bank loans (5,792) (206) (210) 10,254
--------------------------------------
Cash provided by
financing activities 339 (206) 20,659 10,651
--------------------------------------

Investing Activities
Expenditures on property
and equipment (13,178) (2,044) (22,515) (20,922)
Acquisition of Oiltec
Resources Ltd. (Note 4) - - (11,864) -
Changes in non-cash
working capital 1,402 1,334 (2,388) 1,334
--------------------------------------
Cash used in investing
activities (11,776) (710) (36,767) (19,588)
--------------------------------------

Net change in cash - - - -
Cash, beginning of period - - - -
--------------------------------------
Cash, end of period - - - -
--------------------------------------
--------------------------------------

Supplementary Information
Interest paid 261 122 768 318
--------------------------------------
Taxes paid - 22 90 22
--------------------------------------
--------------------------------------


Selected Notes to the Consolidated Financial Statements
(unaudited)

1. Significant in Accounting Policies

The consolidated financial statements have been prepared in accordance
with Canadian generally accepted accounting principles and as disclosed
in the Company's December 31, 2003 consolidated statements except for
changes in accounting policies noted below. The consolidated financial
statements include the accounts of the Company and its subsidiaries all
of which are wholly owned. Certain information and note disclosure
normally included in the financial statements have been condensed or
omitted. These interim financial statements should be read in
conjunction with the most recent annual financial statements and notes
for the year ended December 31, 2003 The preparation of the consolidated
financial statements requires management to make estimates and
assumptions that effect the reported amounts of assets and liabilities
and disclosure of contingent assets and liabilities at the date of the
consolidated financial statements and the reported amounts of revenue
and expenses during the reported period. Actual results may differ from
these estimates. Changes in accounting policies in 2004 were as follows:

(a) Asset Retirement Obligations

Effective January 1, 2004 the Company retroactively adopted the Canadian
Institute of Chartered Accountants ("CICA") section 3110, "Asset
Retirement Obligations". The new recommendations require that the
recognition of the fair value of obligations associated with the
retirement of long-lived assets be recorded in the period the asset is
put into use, with a corresponding increase to the carrying amount of
the related asset. The obligations recognized are statutory, contractual
or legal obligations. The liability is accreted over time for changes in
the fair value of the liability with the accretion amount included in
depletion, depreciation and accretion expense. The costs capitalized to
the related assets are amortized to earnings in a manner consistent with
the depletion and depreciation of the underlying assets. Note 2
discloses the impact of the adoption of CICA section 3110 on the
financial statements.

(b) Property and Equipment - Oil and Gas

The Company capitalized general and administrative costs of $188,100 and
$104,570 for the three months ended December 31, 2004 and 2003
respectively and $770,100 and $522,570 for the year ended December 31,
2004 and 2003 relating to exploration and development activity.

Effective January 1, 2004 the Company adopted Accounting Guideline 16,
"Oil and Gas Accounting - Full Cost" ("AcG-16"), which replaces
Accounting Guideline 5, "Full Cost Accounting in the Oil and Gas
Industry", AcG-16 modifies how the ceiling test is performed and is
consistent with CICA section 3063, "Impairment of Long-lived Assets".
The recoverability of a cost centre is tested by comparing the carrying
value of the cost centre to the sum of the undiscounted cash flows
expected from the proved oil and gas reserves. If the carrying value is
lower than the amount the cost centre is written down to its fair value
using the expected present value approach. This approach incorporates
risk and uncertainties in the expected future cash flows, which are
discounted using a risk free rate of 5%. The adoption of AcG-16 had no
effect on the Company's financial results as at January 1, 2004 and
December 31, 2004.The test for impairment of the Company's petroleum and
natural gas carrying value was calculated at December 31, 2004 using the
following product price assumptions, which were based upon an average of
the current price assumptions of the Company's independent engineers and
the forward strip pricing of the New York Mercantile Exchange:



---------------------------------------------------------
Oil WTI Natural Gas AECO
Year US $ Cdn $
---------------------------------------------------------
2005 47.72 6.97
2006 45.57 6.66
2007 41.19 6.21
2008 38.73 5.73
2009 37.42 5.37
Thereafter 36.40 - 37.45 5.47 - 5.98
---------------------------------------------------------


(c) Hedging Relationships

The CICA published an amended Accounting Guideline 13, "Hedging
Relationships", effective January 1, 2004, to clarify circumstances in
which hedge accounting is appropriate. All derivative instruments that
do not qualify as a hedge under the guideline, or are not properly
designated as a hedge, will be recorded on the balance sheet as either
an asset or liability with changes in fair value recognized in earnings.
The Company adopted the standard January 1, 2004 with no impact on the
financial results as it continues to follow hedge accounting.

(d) Goodwill

Goodwill is the excess of the total purchase price over the fair value
of the net identifiable assets acquired and the liabilities assumed in
business acquisitions. Goodwill is assessed for impairment annually at
year-end or as events occur that could result in an impairment.
Impairment is recognized based on the fair value of the reporting unit
compared to the carrying value of its net assets. If the fair value of
the reporting unit is less than the book value, impairment is measured
by allocating the fair value to the identifiable assets and liabilities
as if the reporting unit had been acquired in a business combination for
a purchase price equal to its fair value. The excess of the fair value
of the reporting unit over the amounts assigned to the identifiable
assets and liabilities is the fair value of the goodwill. Any excess of
the book value of goodwill over this impaired fair value is charged to
income in the period in which it occurs. Goodwill is stated at cost less
impairment and is not amortized.

2. Asset Retirement Obligations

Effective January 1, 2004 the Company retroactively adopted the new
recommendations related to Asset Retirement Obligations as stated in
Note 1. As a result, year end December 31, 2003 results were restated as
follows:



------------------------------------------------------------------------
Consolidated Balance Sheet
- as at December 31, 2003
(000's) As Reported Change As Restated
------------------------------------------------------------------------
Assets
Capital assets 32,111 1,932 34,043
Liabilities and shareholders' equity
Asset retirement obligation - 2,878 2,878
Provision for site restoration
and abandonment 1,304 (1,304) -
Future income taxes 1,201 138 1,339
Retained earnings 452 220 672
------------------------------------------------------------------------


------------------------------------------------------------------------
Consolidated Statement of
Income & Retained Earnings
Three Months ended
December 31, 2003 ($000's) As Reported Change As Restated
------------------------------------------------------------------------
Depletion, depreciation
and accretion 1,823 (56) 1,767
Provision for income taxes (14) 21 7
Net income (loss) 89 35 125

Year ended December 31, 2003
------------------------------------------------------------------------
Depletion, depreciation and accretion 7,198 (225) 6,973
Provision for income taxes 371 86 457
Net income 92 138 231
------------------------------------------------------------------------


At December 31, 2004, the estimated total undiscounted amount required
to settle the asset retirement obligations was $9.4 million. These
obligations will be settled based on the useful lives of the underlying
assets, which currently extend up to 10 years into the future. This
amount has been discounted using a credit adjusted interest rate of 8%
and an inflation rate of 1.5%.



------------------------------------------------------------------------
Changes to asset retirement
obligations were as follows:
Three months ended Year ended
(000's) December 31, 2004 December 31, 2004
------------------------------------------------------------------------
Asset retirement obligations,
beginning 4,847 2,878
Liabilities incurred on acquisitions - 1,726
Liabilities incurred 41 330
Liabilities settled (222) (283)
Accretion 95 249
Changes in assumed costs (54) (193)
------------------------------------------------------------------------
Asset retirement obligations, ending 4,707 4,707
------------------------------------------------------------------------
------------------------------------------------------------------------


3. Bank Loans

On June 23, 2004 the Company entered into new banking arrangements.
The total credit facility pursuant to these arrangements has three
components:


Revolving production loan: - $34.0 million
- prime + 0.4%
- borrowing base review scheduled for
April, 2005
Compressor loan facility: - $450,000
- prime plus 2% repayable at $30,000
per month


The loans are secured by a General Security Agreement and a $60.0
million debenture secured by a first floating charge on all the
Company's assets.

4. Acquisitions

On March 9, 2004 the Company completed an Arrangement Agreement with
Denison Energy Inc. ("Denison") and certain other parties, under which
the oil and gas assets and a subsidiary of Denison were acquired by the
Company. For each Forte Oil Corporation share owned, shareholders
received 0.894 shares (representing approximately 80%) of a newly formed
public company, created for this purpose. Shareholders of Denison
received 3,733,886 shares of the Company (representing approximately
20%). The values assigned to the net assets acquired are as follows:



------------------------------------------------------------------------
$ 000's
------------------------------------------------------------------------
Net assets acquired
Current assets 1,070
Capital assets 10,486
Current liabilities (959)
Asset retirement obligation (1,125)
Bank loan (3,175)
-----------------
6,297
-----------------
-----------------
Consideration
Common shares (3,733,886 shares) 6,297
-----------------
-----------------

------------------------------------------------------------------------


On June 23, 2004 the Company completed an Arrangement Agreement with
Oiltec Resources Ltd. ("Oiltec") under which 100% of the shares of
Oiltec were acquired by Forte. Shareholders of Oiltec received
10,515,935 common shares and $11.864 million cash in total for their
Oiltec shares. The transaction has been accounted for as a purchase of
Oiltec by the Company. The values assigned to the net assets acquired
are as follows:



------------------------------------------------------------------------
$ 000's
------------------------------------------------------------------------
Net assets acquired
Current assets 3,295
Capital assets 59,981
Goodwill 8,627
Current liabilities (8,618)
Future tax liability (4,258)
Asset retirement obligation (601)
Bank debt (13,963)
-----------------
44,463
-----------------
Consideration
Common shares (10,515,935 shares) 32,599
Cash 11,864
-----------------
44,463
-----------------
-----------------

------------------------------------------------------------------------


5. Share Capital

------------------------------------------------------------------------
Common Shares Number $ 000's
------------------------------------------------------------------------
Balance, December 31, 2002 15,998,700 15,667
Issued
For cash 400,000 400
Share issue cost (2)
------------------------

Balance, December 31, 2003 16,398,700 16,065
Issued
Conversion of Preferred, Series I shares 1,341,000 -
Acquisition of Oiltec (Note 4) 10,515,935 32,599
Acquisition of Denison assets 3,733,886 6,297
For cash 6,700,029 22,150
Share issue costs (1,467)
Related tax benefit of share issue costs 499
Exercise of stock options 165,920 186
Reduction resulting from Plan of
Arrangement (Note 4) (1,738,262)
------------------------

Balance, December 31, 2004 37,117,208 76,329
------------------------
------------------------

------------------------------------------------------------------------


------------------------------------------------------------------------
Number of $
Preferred Series I Shares 000's
------------------------------------------------------------------------

Balance, December 31, 2003 and 2002 3,000,000 -

Reduction resulting from Plan of Arrangement
(Note 4) (318,000) -
Conversion to common shares (1,341,000) -
------------------------

Balance, December 31, 2004 1,341,000 -
------------------------
------------------------

------------------------------------------------------------------------


------------------------------------------------------------------------
Number of Exercise
Stock Options Shares Price
------------------------------------------------------------------------
Balance, December 31, 2003 885,000 $1.08
Granted 1,016,000 $3.02
Exercised (165,920) $1.12
Cancelled (127,050) $2.05
Reduction resulting form Plan of Arrangement
(Note 4) (93,810)
------------------------

Balance, December 31, 2004 1,514,220 $2.36
------------------------
------------------------

------------------------------------------------------------------------


The fair value of stock options granted in 2004 was calculated using the
Black-Scholes pricing model assuming a 4% risk free interest rate, a
five-year expected life, 60% volatility and no dividend payments. The
fair value is recorded as stock option expense over the three-year
vesting period of the options.

In April 2004 the Company's common shares traded for 20 consecutive days
at a weighted average price exceeding $2.23 per share. Pursuant to the
terms of the preferred shares, Series I, 1,341,000 preferred shares were
automatically converted to common shares of the Company.

In July 2004 the Company issued 2 million common shares on a flow
through basis at a price of $3.85 per share for a total consideration of
$7.7 million. In December 2004 the Company issued 1.5 million shares on
a flow through basis at a price of $4.30 per share for a total
consideration of $6.45 million. At December 31, 2004 the Company
renounced eligible expenditures of $14.15 million. At December 31, 2004
the Company had incurred $9.4 million of eligible expenditures. The
remainder will be incurred prior to December 31, 2005.

6. Comparative Amounts

Certain comparative amounts have been reclassified to conform to the
presentation adopted for the current year.

7. Commitments

Forte assumed the office lease of Oiltec, which has approximately 4
years remaining at an annual cost of $135,000. In September 2004 the
Company entered into sublet arrangements for this space sufficient to
cover the annual obligation for the remainder of the lease term.

In October 2004 the Company entered into a contract to sell 500 bbls/d
of its crude oil production at a price of $58.30 per bbl for the 2005
year. In December 2004 the Company entered into a contract to sell 500
mcf/d of its natural gas production at a price of $7.00 at AECO for the
period from April 1, 2005 to October 31, 2005. In February 2005 the
Company entered into a contract to sell 200 bbls/d of its crude oil
production at a price of $61.57 per bbl for the period from March 1,
2005 to December 31, 2005.

8. Subsequent Events

On February 24, 2005 the Company issued 4.0 million common shares at
$3.90 for gross proceeds of $15,600,000. In March 2005 the Company
entered into a binding letter of intent to sell properties producing
approximately 50 boe/d for $8.1 million. The transaction is expected to
close prior to March 31, 2005.



Directors Officers

T.J. MacKay D.N. Baker T.J. MacKay, Chairman
& Chief Executive Officer
R.B. Hammond J.S. Blair D.N. Baker, President
& Chief Financial Officer
G.S. Fletcher D.V. Richards R.B. Hammond, Senior Vice President
& Chief Operating Officer
W. P. Comber G. D. Roane


Forte Resources is a Calgary-based oil and natural gas production
company with operations primarily in Alberta, Canada. The company has a
record of successful growth through a combination of acquisitions,
exploration and development. Forte's common shares are listed on the
Toronto Stock Exchange under the symbol FRZ.

This news release may contain forward-looking statements including
expectations of future production, cash flow and earnings. These
statements are based on current expectations that involve a number of
risks and uncertainties, which could cause actual results to differ from
those anticipated. These risks include, but are not limited to: the
risks associated with the oil and gas industry. (e.g. operational risks
in development, exploration and production; delays or changes in plans
with respect to exploration or development projects or capital
expenditures; the uncertainty of reserve estimates; the uncertainty of
estimates and projects relating to production, costs and expenses, and
health, safety and environmental risks), commodity price, price and
exchange rate fluctuation and uncertainties resulting from the potential
delays or changes in plans with respect to exploration or development
projects or capital expenditures. Additional information on these and
other factors that could affect Forte's operations or financial results
are included in Forte's reports on file with Canadian securities
regulatory authorities.

-30-

Contact Information

  • FOR FURTHER INFORMATION PLEASE CONTACT:
    Forte Resources Inc.
    Douglas N. Baker
    President and Chief Financial Officer
    (403) 237-5163
    or
    Forte Resources Inc.
    2450, 500 - 4th Avenue SW
    Calgary, AB T2P 2V6
    Email: info@forteresources.ca
    Website: www.forteresources.ca