Hawk Energy Corp.

Hawk Energy Corp.

March 23, 2005 22:22 ET

Hawk Announces 2004 Results and 2005 Outlook


NEWS RELEASE TRANSMITTED BY CCNMatthews

FOR: HAWK ENERGY CORP.

TSX VENTURE SYMBOL: HK.A
TSX VENTURE SYMBOL: HK.B

MARCH 23, 2005 - 22:22 ET

Hawk Announces 2004 Results and 2005 Outlook

CALGARY, ALBERTA--(CCNMatthews - March 23, 2005) - Hawk Energy Corp.
("Hawk" or "the Company") (TSX VENTURE:HK.A)(TSX VENTURE:HK.B) is
pleased to announce its operating and financial results for the year
ending December 31, 2004, and to provide guidance with respect to the
Company's 2005 activities. Hawk has experienced rapid growth this past
year and has accomplished the following:

- Increased production over 2003 by 649% and exited the year with
production of 1,675 boe/d, exceeding its targeted exit rate of 1,400
boe/d;

- Generated cash flow of $7,616,522 ($0.50 per diluted share) and net
income of $2,507,713 ($0.17 per diluted share);

- Added 2,450 mboe of Proven reserves through drilling and optimization,
at a Proved Finding and Development (F&D) cost of $9.47 per boe
(including future capital), resulting in a Proved recycle ratio of 2.3
to 1;

- Added 3,839 mboe of Proven plus Probable reserves through drilling and
optimization, at a Proved plus Probable F&D cost of $6.96 per boe
(including future capital), resulting in a Proved plus Probable recycle
ratio of 3.1 to 1;

- Increased its Proved reserve base (working interest, before royalties)
to 4,202 mboe which is forecast to generate a Net Present Value,
discounted at 10% before tax, of $57.6 million;

- Increased its Proved plus Probable reserve base (working interest,
before royalties) to 6,079 mboe which is forecast to generate a Net
Present Value, discounted at 10% before tax, of $75.0 million;

- Drilled 40 (32.8 net) wells, 75% of which were classified as
exploration, resulting in 28 (21.4 net) producers for an overall success
rate of 70% in 2004;

- Discovered 14 new gas pools and 3 new oil pools;

- Divested 70 boe/d of high operating cost southeast Saskatchewan
production;

- Assembled a drilling inventory in excess of 25 high quality
exploration and development prospects that will provide a strong
platform for continued growth in 2005 and beyond.

2004 Operational Review

Hawk's business strategy is to profitably grow the Company on a per
share basis by focusing on cash flow. We accomplish this by targeting
high netback production in low-cost areas. These areas are characterized
by year-round access, available existing infrastructure, moderate
drilling depths, affordable land costs and in-house technical knowledge.

Hawk's exploration activities have been focused on generating a diverse
and technically sound inventory of drilling opportunities with
multi-zone potential. The Company has concentrated its exploration
efforts in southern and central Alberta, where high-quality reserves and
strong initial production rates can be attained at reasonable costs.

During 2004, Hawk has had continued success drilling high working
interest exploration wells. The Company drilled 40 (32.8 net) wells, 75%
of which were classified as exploration, resulting in 28 (21.4 net)
wells capable of production. This represents an overall success rate of
70%. Hawk has continued to focus its efforts in southern and central
Alberta and in southeast Saskatchewan. In 2004, the Company drilled the
following wells in its core areas:

Retlaw, Alberta (94% Avg. WI): The Company drilled nine (8.5 net) wells
in the Retlaw area resulting in five (4.5 net) wells capable of
producing natural gas and one (1.0 net) producing oil well. Current net
gas production at Retlaw is 3,300 mcf/d. One (0.5 net) gas well remains
to be tied in. The one oil well is producing at a rate of 35 bopd.
Additional drilling is planned on this oil discovery in the second
quarter. Hawk is continuing to build its land inventory in this
multi-zone area.

Edmonton, Alberta (50% Avg. WI): Hawk drilled 13 (8.14 net) gas tests in
this area resulting in 10 (5.64 net) wells that are capable of gas
production. Seven (3.64 net) of these wells will be on production by the
end of the first quarter of 2005 with the remaining three to be brought
on-stream in the second quarter. Before tieing in these seven wells the
Company is producing a net 2,200 mcf/d in the Edmonton area. Discoveries
made by Hawk in this area are notable for their long life reserves.

Veteran, Alberta (95% Avg. WI): The Company drilled eight (7.8 net)
wells at Veteran and cased five (3.9 net) for production. Current
natural gas production is 2,400 mcf/d net from a new gas pool discovery.
A new oil pool discovery is presently producing 60 bopd of light oil and
will be further developed in the second quarter of 2005.

Chinook, Alberta (100% WI): Hawk is excited about an evolving play in
southeast Alberta in a multi-zone, natural gas prospective area. One
(1.0 net) well was cased for natural gas potential in late 2004 and will
be evaluated during the second quarter of 2005. The Company continues to
evaluate the 1,700 kilometers of 2D seismic data it acquired in 2004 and
has plans for additional drilling during the summer. Thus far, Hawk has
acquired 11 sections of prospective crown land.

Southeast Saskatchewan (72% Avg. WI): Hawk is continuing to optimize its
five high working interest, core properties in this region. The Company
also drilled two (1.1 net) horizontal wells in this area and has plans
for an additional two horizontal wells and one vertical well in 2005. At
present Hawk is producing in excess of 420 boepd, net of the 70 boepd of
non-core assets from this region which were divested in 2004.

2004 Reserves

The reserves of the Company were evaluated by Gilbert Laustsen Jung
Associates Ltd. ("GLJ'), as at December 31, 2004. Utilizing the
methodology and definitions set out in National Instrument 51-101 and
converting gas to barrels of oil equivalent at 6 mcf to 1 boe, Hawk's
December 31, 2004 reserves are as follows:



Before Tax
Company Interest Present Value of
Reserves Before Royalty Future Net Revenues
(000's)
Oil Gas NGL's BOE's Discounted at
(mbbls) (mmcf) (mbbls) (mboe's) 0% 10% 15%
--------------------------------------------------------
Proved
Producing 1,238 7,753 22 2,551 45,620 33,890 30,358
Proved
Non-Producing 133 5,293 131 1,146 25,567 17,253 15,037
Proved
Undeveloped 317 1,128 0 505 9,628 6,491 5,518
--------------------------------------------------------
Total Proved 1,688 14,174 153 4,202 80,815 57,634 50,914
Probable 779 6,276 51 1,877 35,875 17,380 13,368
--------------------------------------------------------
Proved plus
Probable 2,467 20,450 204 6,079 116,690 75,014 64,281
--------------------------------------------------------


2004 Finding and Development Costs

Finding and development costs are a measure of capital efficiency and
are calculated by dividing total capital costs for the period by the
change in reserves (including revisions) for the same period. Under
51-101, the implied methodology to be used to calculate F&D costs
includes incorporating changes in future development capital required to
bring the Proved Undeveloped and Probable reserves to production.

Based on total 2004 capital expenditures of $19.6 million and inclusive
of future development capital of $3.6 million for proved reserves and $
7.1 million for proved plus probable reserves, Hawk's finding and
development costs were $9.47/boe for Total Proved reserves and $6.96/boe
for Total Proved plus Probable reserves.

Undeveloped Land

At December 31, 2004, Hawk had a total of 71,754 (50,677 net) acres of
land under title of which 45,287 (31,779 net) acres were undeveloped.

Eighty-three percent (83%) or 37,541 (25,163 net) acres of the
undeveloped land was located in Alberta while 17% or 7,746 (6,614 net)
acres, was located in Saskatchewan.

2005 Outlook

Since Hawk's inception in April 2003, the Company has been successful in
adding value through both drilling and acquisitions. The Company has
prudently invested $32.8 million to date creating a company which on
December 31, 2004 produced 1,675 boe/d with proved reserves of 4.2
million boe. The Company has also positioned itself with land and
seismic to continue the momentum created in 2004.

The Company has set a capital budget for 2005 of $20 million. This
budget will result in the drilling of 40 high working interest wells.
The majority of these wells will be drilled in Hawk's core areas of
Retlaw, Edmonton, Veteran, Chinook and southeast Saskatchewan. To date
in 2005, Hawk has drilled five (3.2 net) wells. Hawk plans on spending
approximately 20% of its 2005 budget on deeper, higher risk prospects in
western Alberta.

Based on drilling success in the fourth quarter of 2004 and the first
quarter of 2005, Hawk is increasing its production guidance for 2005 to
average 2,000 boe/d with a year-end exit rate of 2,400 boe/d.

Hawk is well positioned to take advantage of the many excellent
opportunities available to grow the Company, given its strong balance
sheet and prospect inventory. Having transformed from an emerging
start-up, into a junior oil and gas producer in 2004, Hawk is continuing
its fast-paced growth in 2005.

Management's Discussion and Analysis

Management's discussion and analysis ("MD&A") of the financial condition
and the results of operations should be read in conjunction with the
audited financial statements and related notes for the year ended
December 31, 2004.

Production information is commonly reported in units of barrel of oil
equivalent or boe. For the purposes of computing such units, natural gas
is converted to equivalent barrels of oil using a conversion factor of
six thousand cubic feet to one barrel of oil. The conversion ratio of
6:1 is based on an energy equivalency conversion method, which is
primarily applicable at the burner tip. It does not represent equivalent
wellhead value for the individual products. Such disclosure of boes may
be misleading, particularly if used in isolation.

All amounts are in Canadian dollars unless otherwise stated.

This disclosure contains certain forward-looking estimates that involve
substantial known and unknown risks and uncertainties, certain of which
are beyond Hawk's control, including the impact of general economic
conditions in Canada and the United States; industry conditions; changes
in laws and regulations including the adoption of new environmental laws
and regulations and changes in how they are interpreted and enforced;
increased competition; the lack of availability of qualified personnel
or management; fluctuations in commodity prices; foreign exchange or
interest rates; stock market volatility and obtaining required approvals
of regulatory authorities. Hawk's actual results, performance or
achievement could differ materially from those expressed in, or implied
by, these forward-looking estimates and, accordingly, no assurances can
be given that any of the events anticipated by the forward-looking
estimates will transpire or occur, or if any of them do so, what
benefits, including the amounts of proceeds, that Hawk will derive
therefrom.

The term "cash flow from operating activities" or "cash flow", which is
expressed before changes in non-cash working capital, is used by the
Company to analyze operating performance, leverage and liquidity. The
term "netback", which is calculated as the average unit sales price,
less royalties and operating expenses, represents the cash margin for
every barrel of oil equivalent sold. These terms do not have any
standardized meaning prescribed by the Canadian Generally Accepted
Accounting Principles (GAAP) and, therefore, might not be comparable
with the calculation of a similar measure for other companies.

Comparability of Prior Period Results

Hawk Energy was incorporated on January 16, 2003 and began operations in
April 2003. As such the prior period results may not be comparable.

Production



Year / Period ended December 31 % Change
2004 2003
---------------------------------
Natural Gas (mcf/d) 3,932 316 1,144
Oil and NGL's (bbls/d) 433 94 361
NGL's (bbls/d) 13 0
---------------------------------
Total (boe/d) 1,101 147 649


The Company added production during 2004 exclusively through drilling
and optimization activities. Sixteen new gas wells were tied in and
brought on production in the Retlaw, Edmonton and Veteran areas. These
wells have added 6,300 mcfd net to the Company's gas production. Also,
five new oil wells have been drilled and placed on production in the
Retlaw, Veteran, Lloydminster and southeast Saskatchewan areas. These
wells have added 150 bopd net to the Company's oil production. Hawk also
divested 70 boe/d of high operating cost southeast Saskatchewan oil
production.

Petroleum and Natural Gas Sales ($)



Year / Period ended December 31 % Change
2004 2003
---------------------------------
Oil sales 7,210,187 1,060,396 580
Per barrel 45.65 30.86 48
Natural gas sales 8,912,613 571,910 1458
Per mcf 6.21 4.96 25
NGL sales 216,262 2,217 9655
Per barrel 46.93 35.76 31
---------------------------------
Total Sales 16,339,062 1,634,523 900


During 2004, Hawk received $45.65 per barrel for its oil production, a
48% increase over the average oil price received in 2003. Hawk's 2004
oil production was comprised of 82% light oil originating from southeast
Saskatchewan, where the Company received an average price of $47.30 per
barrel; 11% heavy oil originating from Marsden, western Saskatchewan,
where the Company received an average price of $29.19 per barrel and 7%
from light oil originating from its Veteran, Endiang and Retlaw
properties in east central and southern Alberta, where the Company
received an average price of $52.74 per barrel. In 2004, the Company
received $6.21/mcf for its gas production, a 25% increase over the
average gas price received in 2003. Approximately 93% of Hawk's gas was
produced from Alberta properties, 4% was produced from western
Saskatchewan and 3%, primarily associated gas from the oil production,
was produced from southeast Saskatchewan. The Company received $46.93
per barrel for its NGL production. Hawk produced 4,608 barrels of NGL's
in conjunction with gas production from eight of its properties.

In 2004, both oil and gas prices were well ahead of prices received in
2003. Oil prices rose to record levels due to supply concerns coupled
with surging global demand. Oil supply shocks throughout the past year
tightened the global supply situation and confirmed that OPEC had
reduced excess capacity. This reduction combined with continued strong
global demand led to sustained oil prices which were significantly above
historic levels. The high oil price environment had little impact on
world-wide demand and also supported natural gas prices throughout the
year. West Texas Intermediate (WTI) oil prices averaged US$41.44/bbl,
33% greater than the 2003 average of US31.09/bbl, and ended the year at
US$43.45/bbl. Likewise NYMEX natural gas prices averaged US$6.18/mmbtu,
13% greater than the 2003 average of $US5.49/mmbtu, and ended the year
at US$6.15/mmbtu. The high oil and gas prices witnessed during 2004 are
expected to continue into 2005.

The Company had no hedging contracts during 2004.

Royalties



Year ended Period ended
December 31, 2004 December 31, 2003
($) Royalty Rate (%) ($) Royalty Rate (%)
------------------------------------------------------
Crown 2,832,855 17.3 236,376 14.4
Freehold 1,155,534 7.1 68,867 4.2
Gross
Overriding 804,613 4.9 49,934 3.1
Royalty Income (19,547) (0.1) (21,505) (1.3)
ARTC (500,000) (3.1) (12,009) (0.7)
------------------------------------------------------
Total 4,273,455 26.1 321,663 19.7


Hawk's 2004 gas royalties were 28.2% compared with 20.6% in 2003. Hawk's
gas royalties are predominantly Crown and attract the ARTC. In 2004,
Hawk's ARTC eligibility exceeded the $500,000 corporate limit, resulting
in higher average gas royalties. During 2004, Hawk's oil royalties,
which are comprised of Crown, freehold and gross overriding royalties,
were 23.4%. Over the same period in 2003, Hawk's oil royalty rate
averaged 19.3%. As oil royalty rates in Saskatchewan are rate dependent,
Hawk's 2004 increased oil royalty rates reflect higher oil production
per well. In 2004, Hawk increased its average oil production rate per
well through optimization activities and also divested of low oil rate
production. Hawk's average royalty rate for NGL production in 2004 was
33.2% as compared with 30.6% in 2003.

Operating Expenses



Year ended Period ended
December 31, 2004 December 31, 2003
($) ($/boe) ($) ($/boe)
----------------------------------------------
Production expense 3,152,326 7.85 423,060 7.89
Processing income (74,433) (0.19) (25,645) (0.48)
----------------------------------------------
Operating expense 3,077,893 7.66 397,415 7.41
Transportation expense 259,613 0.65 38,803 0.72
----------------------------------------------
----------------------------------------------
Total production
expense 3,337,506 8.31 436,218 8.13


During 2004 Hawk's total unit operating cost was $8.31/boe. This
compares with the Company's 2003 unit operating cost of $8.13/boe.
Hawk's 2004 natural gas expense was $0.77/mcf or $4.64/boe compared with
$0.66/mcf for the same period in 2003. The Company's oil and NGL expense
in 2004 was $13.71/boe and is further broken down to $9.43/boe for its
light oil and NGL production in Alberta, $13.90/boe for its light oil
production in southeast Saskatchewan and $15.70/boe for its heavy oil
production at Marsden, in western Saskatchewan. At Marsden, production
declines account for the increased per unit operating cost as compared
with the $6.74/boe reported in 2003. This year's operating costs in
southeast Saskatchewan are slightly higher than the $13.58/boe reported
in 2003, but are also inclusive of numerous workovers resulting from
optimization opportunities which were identified and acted upon in 2004.

Field Netbacks



Year ended Period ended
December 31, 2004 December 31, 2003
Oil
Oil & NGL Gas Boe & NGL Gas Boe
Netback Netback Netback Netback Netback Netback
($/bbl) ($/mcf) ($/boe) ($/bbl) ($/mcf) ($/boe)
--------------------------------------------------
Sales price 45.68 6.21 40.67 30.87 4.96 30.47
Royalties (10.83) (1.75) (10.64) (5.95) (1.02) (6.00)
Production expense (13.71) (0.77) (8.31) (9.77) (0.66) (8.13)
Field Netback 21.14 3.69 21.72 15.15 3.28 16.34


The Company's field netbacks are derived from subtracting royalties and
production expense from the sales price. The Company's field netback
increased 33% over 2003.

Recycle Ratio

The recycle ratio is a measure used to evaluate the effectiveness of a
company's re-investment program. The ratio measures the efficiency of
turning a barrel of oil equivalent of reserves into a new barrel of oil
equivalent of production. It accomplishes this by measuring the field
netback per barrel of oil equivalent to that year's Proven and Proven
plus Probable finding and development costs.



Year / Period ended December 31
2004 2003
--------------------------------
Field Netback ($/boe) 21.72 16.34
Proved F&D ($/boe) 9.47 6.72
Proved Recycle Ratio 2.3 2.4
Proved + Probable F&D ($/boe) 6.97 5.48
Proved + Probable Recycle Ratio 3.1 3.0

General and Administrative Expense (G&A)



Year ended Period ended
December 31, 2004 December 31, 2003
($) ($/boe) ($) ($/boe)
----------------------------------------------
Gross G&A Expense 1,260,942 3.14 608,663 11.34
Capitalized Overhead (422,645) (1.05) (193,124) (3.60)
----------------------------------------------
Net G&A Expense 838,297 2.09 415,539 7.74


The Company's Gross G&A Expense was $1,260,942, an increase of 107% over
the same period in 2003. The increase is directly attributable to a
higher production base as well as the G&A expense being incurred over a
full year as opposed to a partial year in 2003. Hawk capitalized the
portion of its G&A expense which was directly related to the geological
and geophysical work performed to generate exploration prospects. During
2004, the Company's net G&A was $838,297 or $2.09/boe. On a unit basis
this represents a 73% reduction in comparison to 2003. The Company's G&A
expenses are expected to continue to decrease on a per boe basis during
2005 as production is increased.

Interest and Stock Based Compensation Expense

The Company incurred a net interest expense of $37,025 in 2004 compared
to net interest income of $134,621 generated in 2003. The interest
expense was higher in 2004 because the Company periodically utilized its
credit facility.

Hawk's stock based (non-cash) compensation expense was $604,598 or $1.50
per boe in 2004 compared to $77,764 or $1.45 per boe in 2003. These
values were calculated using the Black-Scholes option-pricing model. The
assumptions used in the Black-Scholes model were expected volatility of
150%, risk free interest rate of 4% and time to exercise of 3 years.

Depletion, Amortization and Accretion Expense



Year ended Period ended
December 31, 2004 December 31, 2003
($) ($/boe) ($) ($/boe)
----------------------------------------------
Depletion Expense 2,296,010 5.72 245,555 4.58
Amortization Expense 679,006 1.69 64,920 1.21
Accretion Expense 121,639 0.30 1,612 0.03
Total 3,096,655 7.71 312,087 5.82


Hawk follows the full cost method of accounting as described in the
CICA's accounting guideline 16, "oil and gas accounting - Full Cost".
Accordingly, the cost of all wells, both successful and unsuccessful,
are added to the Company's capital base and are depleted at the rate of
production over the remaining proven reserves as determined by the
December 31, 2004 Gilbert Laustsen Jung report. During 2004, the
Company's Depletion, Amortization and Accretion Expense was $3,096,655
or $7.71/boe verses $5.82/boe in 2003. The majority of the increase is
attributable to the higher costs of adding reserves in 2004.

Income Taxes

On June 9, 2003, the Canadian government substantially enacted federal
income tax changes for the oil and natural gas sector as it had outlined
in its 2003 budget. Resource tax rates will decline from the current 27
percent to 21 percent by 2007. Concurrently, the 100 percent
deductibility of the resource allowance is being phased out and Crown
charges will become 100 percent deductible.

During 2004, Hawk incurred current taxes of $236,257 and made a
provision for future income taxes of $1,407,556. The current taxes are
the result of the Saskatchewan tax and resource surcharge.

The Company had the following income tax pools available at December 31,
2004:



Annual Deduction Tax
Available Pools
------------------------------
Canadian exploration expenses (CEE) 100% $3,305,197
Canadian development expenses (CDE) 30% 1,624,219
Canadian oil and gas property
expenses (COGPE) 10% 5,626,954
Undepreciated capital costs 25% 5,492,205
Share Issue Cost 100% 1,207,523
Non-capital losses carried forward 100% 32,844
------------
Total $17,288,942
------------
------------


Cash Flow from Operations

Year ended Period ended
December 31, 2004 December 31, 2003
$ $/boe $ $/boe
----------------------------------------------
Petroleum and natural
gas revenue 16,339,062 40.67 1,634,523 30.46
Royalties,
net of ARTC (4,273,455) (10.63) (321,663) (6.00)
Net Interest (expense) (37,025) (0.09) 134,621 2.51
Operating costs and
transportation (3,337,506) (8.31) (436,218) (8.13)
General and
administrative (838,297) (2.09) (415,539) (7.74)
Current taxes (236,257) (0.59) (37,726) (0.70)
----------------------------------------------
----------------------------------------------
Cash flow from
Operations 7,616,522 18.96 557,998 10.40


In 2004, the Company generated cash flow from operating activities of
$7,616,522 ($0.50 per diluted share). This represents an increase of
1,265% verses 2003. The increase resulted from increased production
rates and stronger commodity prices.

Net Income and Cash Flow from Operating Activities

Net Income is derived from cash flow from operating activities less
stock based compensation, depletion, amortization & accretion expense
and future income tax. There has been a substantial increase in net
income due to production growth and to a lesser extent an increase in
the commodity price.



Year ended Period ended
December 31, 2004 December 31, 2003
$/ $/
$ diluted share $ diluted share
----------------------------------------------------
Cash flow from
operating
activities 7,616,522 0.50 557,998 0.07
Less: Stock based
compensation 604,598 0.04 77,764 0.01
Depletion,
amortization &
Accretion expense 3,096,655 0.20 312,087 0.04
Future income
taxes 1,407,556 0.09 146,556 0.02
----------------------------------------------------
----------------------------------------------------
Net income (loss) 2,507,713 0.17 21,591 0.00


Capital Expenditures ($)

Year ended Period ended
December 31, 2004 December 31, 2003
----------------------------------------
Land and lease retention 2,342,092 5,366,344
Seismic 2,279,769 1,041,249
Drilling and completions 11,336,462 3,802,262
Geological and geophysical
salaries capitalized 422,645 193,124
Facilities 4,524,421 2,716,116
Corporate assets(a) 6,546 14,687
----------------------------------------
Total Gross Expenditures 20,911,935 13,133,782
Dispositions (1,255,581) nil
----------------------------------------
Total Net Expenditures 19,646,354 13,133,782

(a) Corporate assets include office improvements, equipment,
computer hardware and software.


The Company incurred gross capital expenditures of $20,911,935
($19,646,354 net after proceeds from property dispositions) in 2004
drilling a total of 40 (32.8 net) wells.

Liquidity and Capital Resources

On December 31, 2004, the Company had no debt and a working capital
deficit of $4,248,184.

On June 24, 2004, the Company entered into a revolving, reducing demand
credit facility agreement with a bank for $12,000,000 at an interest
rate of prime plus one-quarter percent per year. Starting July 31, 2004,
the amount of the facility available was reduced by $600,000 per month.
On December 31, 2004, the Company had zero drawn from this credit
facility.

On January 20, 2005, the Company entered into a revolving, reducing
demand credit facility agreement with a bank for $14,000,000 at an
interest rate of prime plus one-quarter percent per year. Starting
February 28, 2005, the amount of the facility available will be reduced
by $450,000 per month.

2005 Capital Budget

Hawk's Board of Directors approved a $20.0 million 2005 capital budget
which will result in the drilling of approximately 40 high working
interest wells in 2005. The majority of these wells will be drilled in
Hawk's core areas of Retlaw, Edmonton, Veteran, Chinook and southeast
Saskatchewan. Hawk plans on spending approximately 20% of its 2005
budget on deeper, higher risk prospects in western Alberta.

Contractual Obligations

Pursuant to the May 22, 2003, initial public offering, the Company
issued flow-through shares, whereby the Company is required to incur
$9,250,000 of qualifying flow-through expenditures. To the period ended
December 31, 2004, Hawk has incurred sufficient qualifying expenditures
to satisfy its flow-through obligation.

The Company is also committed to a minimum annual lease payment of
$24,850 under a rental agreement for office space until September 2005.

Dividend Policy

Hawk pays no dividends as all cash generated from operations is used to
finance the drilling and acquisition activities of the Company.

Quarterly Results ($)

The following table summarizes certain quarterly financial information
relating to the Company.



Quarter Ended Petroleum and Cash Flow Net Income
Natural Gas Revenue (loss) (loss)
---------------------------------------------------------------------
December 31, 2004 6,238,090 2,846,830 1,046,223
September 30, 2004 4,169,515 2,062,758 632,357
June 30,2004 3,345,385 1,540,429 449,721
March 31, 2004 2,586,071 1,166,507 408,841
December 31, 2003 1,334,781 475,015 55,482
September 30, 2003 249,103 118,139 1,950
June 30, 2003 50,639 (24,406) (25,091)
March 31, 2003 - (10,750) (10,750)



Summary of Fourth Quarter Information ($)

Quarter ended December 31 % Change
2004 2003
--------------------------------------

Production (boe/d) 1,576 465 239
Revenue 6,238,090 1,334,781 367
Per boe 43.03 31.20 38
Royalty 1,853,759 264,868 600
Per boe 12.79 6.19 107
Operating Costs 1,145,089 381,708 200
Per boe 7.90 8.92 (11)
G&A Expense 287,846 223,580 29
Per boe 1.98 5.23 (62)
Net Interest (Income) 42,170 (48,116)
Per boe 0.29 (1.12)
Current Tax 62,396 37,726 65
Per boe 0.43 0.88 (51)
Cash Flow 2,846,830 475,015 499
Per boe 19.64 11.10 77


In comparing the fourth quarter of 2004 with the same period in 2003:

- production increased by 239% due to a successful 2004 drilling and
optimization program;

- per unit revenue received increased by 38% due to stronger oil and
natural gas prices;

- per unit royalty increased by 107% as a result of increased prices
received and as a result of a higher percentage of gas (71% in 2004
verses 40% in 2003) which attracts a higher royalty;

- per unit G&A decreased by 62% as a result of increased production in
2004;

- per unit cash flow increased by 77% , largely as a result of higher
commodity prices, lower operation costs and lower G&A costs.

2004 Stock Price and Trading Activity



Class A 1st Q 2nd Q 3rd Q 4th Q 2004
---------------------------------------------------------------------
High $3.10 $3.50 $3.40 $3.90 $3.90
Low 2.25 2.70 2.40 3.25 2.25
Close 2.75 3.20 3.35 3.59 3.59
Volume 648,677 708,734 218,300 541,702 2,117,413


Class B 1st Q 2nd Q 3rd Q 4th Q 2004
---------------------------------------------------------------------
High $5.75 $7.30 $6.40 $7.25 $7.30
Low 5.10 5.31 6.01 6.20 5.10
Close 5.31 6.01 6.20 7.25 7.25
Volume 11,430 19,930 4,450 18,470 54,280


Critical accounting policies

Hawk's accounting policies are described in note 2 to the consolidated
financial statements. Certain accounting policies are identified as
critical accounting policies because they form an integral part of
Hawk's financial position and also require management to make judgments
and estimates based on conditions and assumptions that are inherently
uncertain. These accounting policies could result in materially
different results should the underlying assumptions or conditions change.

Management assumptions are based on Hawk's historical experience,
management's experience, and other factors that, in management's
opinion, are relevant and appropriate. Management assumptions may change
over time as further experience is gained or as operating conditions
change.

Business risks

The oil and natural gas industry is subject to numerous risks that can
affect the amount of cash flow from operating activities and the ability
to grow. These risks include but are not limited to:

- fluctuations in commodity price, exchange rates and interest rates;

- government and regulatory risk in respect of royalty and income tax
regimes;

- operational risks that may affect the quality and recoverability of
reserves;

- geological risk associated with accessing and recovering new
quantities of reserves;

- transportation risk in respect of the ability to transport oil and
natural gas to market;

- capital markets risk and the ability to finance future growth;

- weather risk in respect of the ability to enter and drill wells in
some wet areas;

- gas processing risk in respect of the ability to process gas into
third party owned facilities; and

- regulatory risk in respect of the ability to license and produce sour
wells in populated areas.

Hawk strives to minimize these business risks by:

- employing management and technical staff with extensive industry
experience;

- adhering to a strategy of exploring, developing, acquiring and
optimizing quality, low-risk reserves in areas where we have technical
and operational expertise;

- developing a diversified, balanced asset portfolio that generally
offers developed operational infrastructure, year-round access and close
proximity to markets;

- maintaining a low cost structure to maximize cash flow and
profitability;

- maintaining prudent financial leverage and developing strong
relationships with the investment community and capital providers;

- adhering to strict guidelines and reporting requirements with respect
to environmental, health and safety practices;

- maintaining an adequate level of property, casualty, comprehensive and
directors' and officers' insurance coverage;

- scheduling the drilling of wells in wet areas in the winter months;

- securing gas processing agreements before gas wells are drilled; and

- investigating anticipated well licensing difficulties before land is
purchased.

Changes in accounting policy

The following two accounting policy changes in accounting policy were
adopted by Hawk in 2004.

Asset retirement obligation (ARO)

The new Canadian Institute of Chartered Accountants ("CICA") standard
for Asset Retirement Obligations changes the method of accounting for
certain site restoration costs. Under the new standard, the fair value
of asset retirement obligations are recorded as liabilities on a
discounted basis, when incurred. The value of the related assets are
increased by the same amount as the liability and depreciated over the
useful life of the asset. Over time the liability is adjusted for the
change in present value of the liability or as a result of changes to
either the timing or amount of the original estimate of undiscounted
future cash flows.

Asset retirement obligation requires that management make estimates and
assumptions regarding future liabilities and cash flows involving
environmental reclamation and remediation. Such assumptions are
inherently uncertain and subject to change over time due to factors such
as historical experience, changes in environmental legislation or
improved technologies. Changes in underlying assumptions, based on the
above noted factors, could have a material impact on Hawk's future
financials results.

Hedging relationships

CICA accounting guideline 13, "Hedging relationships" is effective for
fiscal periods beginning on or after July 1, 2003. This accounting
guideline addresses the identification, designation, documentation and
effectiveness of hedging relationships, for the purpose of applying
hedge accounting. In addition, it establishes criteria for discontinuing
the use of hedge accounting. Under accounting guideline 13, hedging
transactions must be documented and it must be demonstrated that the
hedges are sufficiently effective to continue accrual accounting for
positions hedged with derivatives. Hawk did not engage in any hedging
activities in 2004. During 2005, the Company will assess such strategies
to minimize the price risk associated with the volatility of commodity
prices.

Outlook

Since Hawk's inception in April 2003, the Company has been successful in
adding value through both drilling and acquisitions. The Company has
prudently invested $32.8 million to date creating a company which on
December 31, 2004 produced 1,675 boe/d with proved reserves of 4.2
million boe. The Company has also positioned itself with land and
seismic to continue the momentum created in 2004.

The Company has set a capital budget for 2005 of $20 million. This
budget will result in the drilling of 40 high working interest wells.
The majority of these wells will be drilled in Hawk's core areas of
Retlaw, Edmonton, Veteran, Chinook and southeast Saskatchewan. To date
in 2005, Hawk has drilled five (3.2 net) wells. Hawk plans on spending
approximately 20% of its 2005 budget on deeper, higher risk prospects in
western Alberta.

Based on drilling success in the fourth quarter of 2004 and the first
quarter of 2005, Hawk is increasing its production guidance for 2005 to
average 2,000 boe/d with a year-end exit rate of 2,400 boe/d.

Hawk is well positioned to take advantage of the many excellent
opportunities available to grow the Company, given its strong balance
sheet and prospect inventory. Having transformed from an emerging
start-up, into a junior oil and gas producer in 2004, Hawk is continuing
its fast-paced growth in 2005.

Hawk is a Calgary-based emerging oil and gas company engaged in the
exploration, development and exploitation of oil and gas reserves in
western Canada. Hawk's goal is to generate sustainable and profitable
per share growth in earnings, cash flow from operations and reserves by
aggressively pursuing focused exploration, exploitation, development and
acquisition opportunities in the Company's focus areas. Hawk's Class A
and Class B shares trade on the TSX Venture Exchange under the symbols
"HK.A" and "HK.B" respectively.

Additional information is filed on SEDAR at www.sedar.com.

This MD&A was written on March 22, 2005.




SHAREHOLDER INFORMATION

DIRECTORS OFFICE

Steve Fitzmaurice, P. Eng. Suite 490, 734-7th Avenue S.W.
President, Chief Executive Officer & Calgary, Alberta T2P 3P8
Chairman of the Board
Hawk Energy Corp. Telephone: (403) 262-1204
Fax: (403) 313-4295
Dave Bonnar, P. Geol.
Vice President, Corporate Development AUDITORS
Hawk Energy Corp.
PricewaterhouseCoopers LLP
Thomas Buchanan, CA(a)(b)(c) Calgary, Alberta
Chief Executive Officer
Provident Energy Ltd. BANKERS

John Wright, P. Eng., CFA(a)(b)(c) National Bank of Canada
President and Chief Executive Officer Calgary, Alberta
Petrobank Energy and Resources Ltd.
TRANSFER AGENT
Greg Turnbull, LLB(a)(b)
Partner Computershare Investor
McCarthy Tetrault Services
Calgary, Alberta

OFFICERS SOLICITORS

Steve Fitzmaurice, P. Eng. McCarthy Tetrault LLP
President & Chief Executive Officer Calgary, Alberta

Erik DeWiel, P. Land STOCK EXCHANGE LISTING
Vice President, Land and
Corporate Secretary The TSX Venture Exchange
Trading Symbol: HK.A & HK.B
Randy Deobald, P. Geol.
Vice President, Exploration
ENGINEERING CONSULTANTS
Dave Bonnar, P. Geol.
Vice President, Corporate Development Gilbert Laustsen Jung
Associates Ltd.
Calgary, Alberta
M.H.(Mike) Shaikh, C.A.
Chief Financial Officer

(a) members of the audit committee
(b) members of the reserve committee
(c) members of the compensation committee


HAWK ENERGY CORP.

Financial Statements

December 31, 2004 and 2003







Balance Sheet

December 31
-----------
(All amounts in Canadian Currency)
2004 2003
------------------
(Restated
- Note 6)
ASSETS
Current
Cash $ 491,606 $ 4,670,531
Accounts receivable 3,904,957 1,693,876
Prepaid expenses 81,669 120,305
------------------------
4,478,232 6,484,712

Property, plant and equipment, net (Note 3) 31,093,025 14,083,358
------------------------

$ 35,571,257 $ 20,568,070
------------------------
------------------------

LIABILITIES AND SHAREHOLDERS' EQUITY

Current
Bank indebtedness (Note 4) $ - $ 50,000
Accounts payable and accrued liabilities 8,529,032 3,215,417
Income taxes payable 197,384 37,726
------------------------
8,726,416 3,303,143

Future income taxes (Note 5) 4,400,030 3,138,694

Asset retirement obligations (Note 6) 1,711,631 1,261,663
------------------------
14,838,077 7,703,500
------------------------
Shareholders' equity
Share capital (Note 7) 17,521,514 12,765,215
Contributed surplus (Note 7(b)) 682,362 77,764
Retained earnings 2,529,304 21,591
------------------------
20,733,180 12,864,570
------------------------

$ 35,571,257 $ 20,568,070
------------------------
------------------------
Commitments (Note 9)

Approved on behalf of the Board

----------------------------------Director

----------------------------------Director

See Accompanying Notes

Statement of Operations and Retained Earnings (Deficit)
(All amounts in Canadian Currency)


For the
Period
For the January 16,
Year Ended 2003 to
December 31, December 31,
2004 2003
--------------------------
(Restated
- Note 6)
Revenue
Petroleum and natural gas sales $ 16,339,062 $ 1,634,523
Royalties (4,273,455) (321,663)
Interest income 45,371 135,211
-------------------------
12,110,978 1,448,071
-------------------------

Expenses
Operating 3,077,893 397,415
Transportation 259,613 38,803
General and administrative 838,297 415,539
Stock based compensation (Note 7(b)) 604,598 77,764
Interest 82,396 590
Depletion, amortization and accretion 3,096,655 312,087
-------------------------
7,959,452 1,242,198
-------------------------

Income before income taxes 4,151,526 205,873
-------------------------

Provision for income taxes (Note 5)
Current 236,257 37,726
Future 1,407,556 146,556
-------------------------
1,643,813 184,282
-------------------------

Net income 2,507,713 21,591
-------------------------

Retained earnings (deficit),
beginning of period (12,753) -
Adjustment for change in accounting
policy (Note 6) 34,344 -
-------------------------
21,591 -
-------------------------

Retained earnings, end of period $ 2,529,304 $ 21,591
-------------------------
-------------------------

Income per share, basic and diluted
(Note 10) $ 0.17 $ -
-------------------------
-------------------------

See Accompanying Notes

Statement of Cash Flows
(All amounts in Canadian Currency)
For the
Period
For the January 16,
Year Ended 2003 to
December 31, December 31,
2004 2003
--------------------------
(Restated
- Note 6)
Cash provided by operating activities
Net income $ 2,507,713 $ 21,591
Items not affecting cash:
Stock based compensation 604,598 77,764
Depletion, amortization and accretion 3,096,655 312,087
Future income taxes 1,407,556 146,556
-------------------------
Cash flow from operating activities
before changes innon-cash working capital 7,616,522 557,998
-------------------------

Changes in non-cash working capital:
Accounts receivable (1,741,828) (1,693,876)
Prepaid expenses 38,636 (120,305)
Accounts payable and accrued liabilities 2,461,299 565,834
Income taxes payable 159,658 37,726
-------------------------
917,765 (1,210,621)
-------------------------
8,534,287 (652,623)
-------------------------
Cash used in investing activities
Additions of property, plant
and equipment (20,911,935) (13,133,782)
Proceeds on disposition of property,
plant and equipment 1,255,581 -
Changes in non-cash working capital
for investing activities 2,383,064 2,649,583
-------------------------
(17,273,290) (10,484,199)
-------------------------
Cash provided by financing activities
Issuance of share capital 4,999,999 17,250,000
Share issue cost (389,921) (1,492,647)
-------------------------
4,610,078 15,757,353
-------------------------

(Decrease) increase in cash and cash
equivalents (4,128,925) 4,620,531

Cash and cash equivalents, beginning
of period 4,620,531 -
-------------------------

Cash and cash equivalents, end of period $ 491,606 $ 4,620,531
-------------------------
-------------------------

Cash and cash equivalents consists of:
Cash $ 491,606 $ 4,670,531
Bank indebtedness - (50,000)
-------------------------
$ 491,606 $ 4,620,531
-------------------------
-------------------------
Supplementary information
Interest paid $ 46,506 $ (590)
-------------------------
-------------------------
Income taxes paid $ 76,599 $ -
-------------------------
-------------------------



Hawk Energy Corp.
Notes to the Financial Statements
For the Year Ended December 31, 2004
(All amounts in Canadian Currency)


1. Incorporation and operations

Hawk Energy Corp. (the "Company") was incorporated under the Business
Corporations Act (Alberta) on January 16, 2003. The principal business
of the Company is exploration, exploitation, development and production
of oil and natural gas reserves. All activity is conducted in Western
Canada and comprises a single business segment.

2. Accounting policies

Property, plant and equipment

Petroleum and natural gas (P&NG) properties and production equipment

The Company follows AcG 16 "Full Cost Accounting", whereby all costs
associated with the exploration for and development of petroleum and
natural gas reserves are capitalized and charged against earnings as
described below. Capitalized costs include lease acquisition costs, the
costs of geological and geophysical activities, the costs of drilling
both productive and non-productive wells, carrying charges of
non-producing properties and overhead costs directly related to
exploration and development activities.

Proceeds from the disposal of properties are applied as a reduction of
the cost of the remaining assets, except when such a disposal would
alter the rate of depletion by more than 20%, in which case a gain or
loss on disposal is recorded.

Depletion of oil and gas properties and production equipment is provided
using the unit of production method which is based upon gross proven
reserve volumes. For this purpose, gas volumes are converted to
equivalent oil volumes based upon the relative energy content where six
thousand cubic feet of gas equates to one barrel of oil.

Costs of acquisition and evaluation of unproved properties are initially
excluded from the depletion calculation. The Company periodically
reviews costs associated with unproved properties to determine whether
they are likely to be recovered. When such costs are not likely to be
recovered, or when proved reserves are found to be attributable to the
properties, the values of these properties are moved to the depletion
pool.

The Company places a limit on the aggregate carrying value of property,
plant and equipment. Impairment is recognized if the carrying amount of
the property, plant and equipment exceeds 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. Upon
recognition of impairment, the Company would measure the amount of
impairment by comparing the carrying amounts of the property, plant and
equipment to an amount equal to the estimated net present value of
future cash flows from proved plus risked probable reserves. The
Company's 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 the Company's future cash flows would be recorded as a
permanent impairment.

Furniture and equipment

Furniture and equipment is recorded at cost. Amortization is provided
thereon at a rate of 20% per annum on a declining balance basis.

Asset retirement obligation

The Company follows the Canadian Institute of Chartered Accountants
standard for Asset Retirement Obligation ("ARO"). Under this standard,
the fair value of a liability for an ARO is recorded in the period where
a reasonable estimate of the fair value can be determined. When the
liability is recorded, the carrying amount of the related asset is
increased by the same amount of the liability. The asset recorded is
depleted over the useful life of the asset. Additions to asset
retirement obligations due to the passage of time are recorded as
accretion expense. Actual expenditures incurred are charged against the
obligation.

Joint ventures

Substantially all of the Company's petroleum and natural gas activities
are conducted jointly with others and, accordingly, the accounts reflect
only the Company's proportionate interest in such activities.

Income taxes

The liability method is used in accounting for income taxes. Under this
method, future tax assets and liabilities are determined based on
differences between the financial reporting and tax bases of assets and
liabilities, and measured using the substantively enacted tax rates and
laws that will be in effect when the differences are expected to
reverse. The effect on future tax assets and liabilities of a change in
tax rates is recognized in income in the period in which the change
occurs.

Flow-through shares

The Company will from time to time issue flow-through shares to finance
a portion of its capital expenditure program. Pursuant to the terms of
flow-through share agreements, the tax deductions associated with the
expenditures are renounced to the subscribers. Accordingly, share
capital will be reduced and a future tax liability will be recorded
equal to the estimated amount of the future income tax liability of the
Company as a result of the renunciations, when the renunciations are
made.

Stock options

The Company has a stock option plan, which is described in note 7.
Consideration paid by directors, officers and key employees and
consultants on the exercise of stock options is credited to share
capital together with the amount previously recognized in contributed
surplus.

Awards of stock options to employees and non-employees are accounted for
in accordance with the fair value method of accounting for stock-based
compensation. The fair value of stock options is determined using the
Black-Scholes option pricing model. Under the fair value method, the
amount to be recognized as expense is determined at the time the options
are issued and is deferred and recognized in earnings over the vesting
period of the options with a corresponding increase in contributed
surplus.

Revenue recognition

Revenues from petroleum and natural gas sales are recognized when title
passes from the Company to its customer.

Per share data

The Company utilizes the treasury stock method in the determination of
diluted per share amounts. Under this method, the diluted weighted
average number of shares is calculated assuming the proceeds that arise
from the exercise of outstanding, in-the-money options are used to
purchase common shares of the Company at their average market price for
the period. Unrecognized stock-based compensation form current grants is
treated as proceeds used to purchase common shares.

Measurement uncertainty

The amounts recorded for depletion and amortization of oil and natural
gas properties and equipment and the provision for asset retirement
obligations are based on estimates. The ceiling test is based on
estimates of proved reserves, production rates, oil and gas prices,
future costs and other relevant assumptions. By their nature, these
estimates are subject to measurement uncertainty and the effect on the
financial statements of changes in such estimates in future periods
could be significant.

3. Property, plant and equipment



2004 2003
------------------------------------- ------------
Accumulated Net Net
Cost amortization book value book value
------------------------------------- ------------
P&NG properties
and production
equipment $ 34,355,658 $ 3,278,065 $ 31,077,593 $ 14,071,608
Furniture and
equipment 21,235 5,803 15,432 11,750
------------------------------------- ------------

$ 34,376,893 $ 3,283,868 $ 31,093,025 $ 14,083,358
------------------------------------- ------------
------------------------------------- ------------


The Company has capitalized $422,645 (2003 - $193,124) general and
administrative costs during the year ended December 31, 2004.

Unproved property costs of $3,613,282 (2003 - $1,074,200) and estimated
salvage value of $1,377,950 (2003 -nil) have been deducted from and
future capital cost of $3,554,000 (2003 - Nil) has been added to costs
subject to depletion and amortization for the year ended December 31,
2004.

An impairment test calculation was performed on the Company's property,
plant and equipment at December 31, 2004 in which the estimated
undiscounted future net cash flows based on estimate future prices
associated with the proved reserves exceeded the carrying amount of the
Company's petroleum and natural gas properties.

The following table outlines prices used in the impairment test at
December 31, 2004:



Year Oil ($/bbl) Gas ($/Mcf) NGL ($/bbl)

2005 $43.86 $6.35 $39.76
2006 41.91 6.13 37.33
2007 40.09 5.96 35.63
2008 38.03 5.81 33.86
2009 35.80 5.81 31.78
2010 35.25 5.82 30.74
2011 35.21 5.82 30.75
2012 35.24 5.83 30.73
2013 35.71 5.94 31.25
2014 35.95 6.03 32.14
2015 36.30 6.14 32.50
2016 36.95 6.30 33.08


4. Bank indebtedness

On June 24, 2004, the Company entered into a revolving reducing demand
credit facility agreement with a bank for $12,000,000 at an interest
rate of prime plus one-quarter percent per year. Starting July 31, 2004,
the amount of the facility available was reduced by $600,000 per month.
This credit facility is collateralized by a general assignment of book
debts and a $25,000,000 debenture with a floating charge over all assets
of the Company and will be reviewed periodically. As at December 31,
2004, no amount was drawn on the bank facility except for a $20,000
letter of guarantee issued to the Government of Saskatchewan which
expires February 11, 2005. This letter of guarantee will be renewed
periodically until the wells in Saskatchewan are abandoned. As of year
end, the Company's guarantees were negligible.

Subsequent to year end, the Company increased its demand credit facility
to $14,000,000 effective January 20, 2005. Starting February 28, 2005,
the amount of facility available will be reduced by $450,000 per month.

5. Income taxes



The liability for future income taxes on the Company's balance sheet
is comprised of the following temporary differences:

2004 2003
---- ----

Future income tax liabilities
Property, plant and equipment $ 5,482,608 $ 4,231,069
Future income tax assets
Share issue costs (456,938) (446,848)
Asset retirement obligation (612,512) (486,390)
Non-capital losses carried forward (13,128) (159,137)
-------------------------

$ 4,400,030 $ 3,138,694
-------------------------
-------------------------

The income tax provision differs from the expected amount computed by
applying the Canadian combined Federal and Provincial income tax rate
of 40.97% (2003 - 40.75%) as follows:

Computed "expected" income tax expense $ (1,700,880) $ (83,893)
Add back:
Stock based compensation (247,704) (29,939)
Non-deductible Crown charges (901,186) (83,129)
Non-deductible meals and entertainment (5,874) (2,245)
Deduct:
ARTC 204,850 4,190
Resource allowance 845,874 9,240
Saskatchewan capital tax 30,138 4,718
Change in tax rate and other 367,226 34,502
-------------------------
(1,407,556) (146,556)

Large Corporation and Saskatchewan tax
Large corporation tax - (13,032)
Saskatchewan tax and resource surcharge (236,257) (24,694)

$ (1,643,813) $ (184,282)
-------------------------
-------------------------

As of year end, the Company has tax pools as follows:

Undepreciated capital cost $ 5,492,205 $ 2,403,530
Canadian exploration expenses 3,305,197 258,975
Canadian development expenses 1,624,219 227,276
Canadian oil and gas property expenses 5,626,954 4,851,763
Share issue costs 1,207,523 1,194,117
Non-capital losses carried forward 32,844 401,659
-------------------------
17,288,942 9,337,320
Less tax pools renounced but not
incurred - (4,396,340)
-------------------------
$ 17,288,942 $ 4,940,980
-------------------------
-------------------------


6. Asset retirement obligations

In 2004, the Company adopted the recommendations of the Canadian
Institute of Chartered Accountants on accounting for asset retirement
obligations. These recommendations replaced the previous policy on
future site restoration, and as a result, have been treated as a change
in accounting policy. The Company adopted this policy retroactively with
the restatement of the 2003 financial statements. Implementation of this
accounting standard did not affect the Company's cash flow or liquidity.

The asset retirement obligation is initially recorded at the estimated
fair value as a long-term liability with a corresponding increase to
property, plant and equipment. This fair value is determined through a
review of engineering studies, industry guidelines, and management's
estimate on a site by site basis. The depletion and amortization of
property, plant and equipment is allocated to expense on the
unit-of-production basis. The liability is increased each reporting
period for the fair value of any new future site reclamation costs and
the corresponding accretion on the original provision. The accretion is
charged to earnings in the period incurred. The provision will also be
revised for any changes to timing related to cash flows or undiscounted
reclamation costs. Actual expenditures incurred for the purpose of
dismantlement, removal, abandonment and site reclamation are charged to
the asset retirement obligation to the extent that the liability exists
on the balance sheet. Differences between the actual costs incurred and
the fair value of the liability recorded are recognized to earnings in
the period incurred.

The previously reported 2003 amounts have been restated due to the
retroactive application of this new standard. The effect of this change
on the January 1, 2004 balance sheet was an increase in property, plant
and equipment of $1,255,224 and the recognition of an asset retirement
obligation of $1,261,663. The change in accounting for asset retirement
obligations as compared to the site restoration approach resulted in an
increase in retained earnings of $34,344 and an increase in future
income tax liability of $13,070. The following table reconciles the
asset retirement obligation associated with the retirement of petroleum
and natural gas properties:



Asset retirement obligation, January 16, 2003 $ -
Liabilities incurred 1,258,428
Accretion expense 3,235
--------------
Asset retirement obligation, December 31, 2003 1,261,663
Liabilities incurred 328,329
Accretion expense 121,639
--------------
Asset retirement obligation, December 31, 2004 $ 1,711,631
--------------
--------------


The Company estimates the undiscounted cash flows related to asset
retirement obligations, adjusted for inflation, to be incurred over the
estimated reserve life of the underlying assets to total approximately
$4,150,953. The fair value at December 31, 2004 is $1,711,631 using a
discount rate of eight percent and an inflation rate of two percent. The
expected period until settlement ranges from 2 years to 25 years.

6. Asset retirement obligations

In 2004, the Company adopted the recommendations of the Canadian
Institute of Chartered Accountants on accounting for asset retirement
obligations. These recommendations replaced the previous policy on
future site restoration, and as a result, have been treated as a change
in accounting policy. The Company adopted this policy retroactively
with the restatement of the 2003 financial statements. Implementation
of this accounting standard did not affect the Company's cash flow or
liquidity.

The asset retirement obligation is initially recorded at the estimated
fair value as a long-term liability with a corresponding increase to
property, plant and equipment. This fair value is determined through a
review of engineering studies, industry guidelines, and management's
estimate on a site by site basis. The depletion and amortization of
property, plant and equipment is allocated to expense on the
unit-of-production basis. The liability is increased each reporting
period for the fair value of any new future site reclamation costs and
the corresponding accretion on the original provision. The accretion is
charged to earnings in the period incurred. The provision will also be
revised for any changes to timing related to cash flows or undiscounted
reclamation costs. Actual expenditures incurred for the purpose of
dismantlement, removal, abandonment and site reclamation are charged to
the asset retirement obligation to the extent that the liability exists
on the balance sheet. Differences between the actual costs incurred and
the fair value of the liability recorded are recognized to earnings in
the period incurred.

The previously reported 2003 amounts have been restated due to the
retroactive application of this new standard. The effect of this change
on the January 1, 2004 balance sheet was an increase in property, plant
and equipment of $1,255,224 and the recognition of an asset retirement
obligation of $1,261,663. The change in accounting for asset
retirement obligations as compared to the site restoration approach
resulted in an increase in retained earnings of $34,344 and an increase
in future income tax liability of $13,070. The following table
reconciles the asset retirement obligation associated with the
retirement of petroleum and natural gas properties:



Asset retirement obligation, January 16, 2003 $ -
Liabilities incurred 1,258,428
Accretion expense 3,235
------------
Asset retirement obligation, December 31, 2003 1,261,663
Liabilities incurred 328,329
Accretion expense 121,639
------------
Asset retirement obligation, December 31, 2004 $ 1,711,631
------------


The Company estimates the undiscounted cash flows related to asset
retirement obligations, adjusted for inflation, to be incurred over the
estimated reserve life of the underlying assets to total approximately
$4,150,953. The fair value at December 31, 2004 is $1,711,631 using a
discount rate of eight percent and an inflation rate of two percent.
The expected period until settlement ranges from 2 years to 25 years.

7. Share capital



(a) Authorized
Unlimited Class A common voting shares
Unlimited Class B common voting shares

Issued
Number
of Shares Amount
---------- ------------
Class A common shares
For cash as initial private placement 4,000,000 $ 1,000,000
Issuance of flow through shares 3,700,000 925,000
Share issuance 3,500,000 7,000,000
Share issue cost, net of tax effect - (313,918)
Tax effect on flow through shares - (356,125)
---------- ------------
Class A common shares, as of December 31, 2003 11,200,000 8,254,957

Share issuance 1,785,714 4,999,999
Share issue cost, net of tax effect - (243,700)
---------- ------------
Class A common shares, as of December 31, 2004 12,985,714 13,011,256
---------- ------------

Class B common shares
Issuance of flow-through shares 832,500 8,325,000
Share issue cost, net of tax effect - (609,617)
Tax effect on flow-through shares - (3,205,125)
---------- ------------
Class B common shares, as of December 31, 2003
and December 31, 2004 832,500 4,510,258
---------- ------------

Balance, end of period $17,521,514
------------
------------


As of year end, no shares were held in escrow. The Class B shares are
convertible at the option of the Company at any time after June 30, 2006
and before June 30, 2008 into Class A shares. The conversion is
calculated by dividing $10 by the greater of $1 and the then current
market price of Class A shares. If conversion has not occurred by the
close of business on June 30, 2008, the Class B shares become
convertible at the option of the shareholder into Class A shares on the
same basis. Effective August 1, 2008, all remaining Class B shares will
be deemed to be converted into Class A shares on the same basis.

Pursuant to the May 22, 2003 public offering prospectus, the Company
offered for sale a maximum of 9,250 units through a prospectus offering.
Each $1,000 unit consisted of 400 Class A flow-through shares at $0.25
per share and 90 Class B flow-through shares at $10 per share.
Consequently, the Company issued 3,700,000 flow-through Class A common
shares and 832,500 Class B common shares and agreed to incur $9,250,000
qualifying flow-through expenditures. Pursuant to the terms of
flow-through share agreements, the tax deductions associated with the
expenditures are renounced to the subscribers. As of year end, the
Company has incurred all qualifying expenditures totaling $9,250,000.

b) Stock options

The Company has a Stock Option Plan that is granted by the board of
directors to directors, officers, employees of and consultants to the
Company. Under the terms of the plan, the Company has reserved an amount
of Class A shares for options equal to 10% of the issued and outstanding
Class A shares. Options granted under the Plan will have an exercise
price which is not less than the price allowed by regulatory
authorities, will be non-transferable and will be exercisable for a
period not to exceed five years. The options will vest one-third on each
of the first, second and third anniversaries of the date of grant. No
one optionee is permitted to hold options entitling such optionee to
purchase more than 5% of the issued and outstanding Class A shares.



For the Year Ended January 16, 2003 to
December 31, 2004 December 31, 2003
------------------------------------------------
Weighted Weighted
Number of Average Number of Average
Options Exercise Options Exercise
------------------------------------------------
Outstanding,
beginning of period 770,000 $ 0.35 - $ -
Granted 522,500 2.76 770,000 0.35
Cancelled (15,000) 0.35 - -
------------------------------------------------
Outstanding,
end of period 1,277,500 1.34 770,000 0.35
------------------------------------------------
Exercisable,
end of period 251,677 $ 0.35 - $ -
------------------------------------------------

Since January 16, 2003, the Company calculated the non-cash compensation
expense using the Black-Scholes option-pricing model based on the
following assumptions:

Number of Risk free Time to Fair Value
Date Options Expected Interest Exercise of Granted
of Grant Granted (Net) Volatility Rate (Years) Options
------------------------------------------------------------------------
June 6, 2003 755,000 150% 4% 3 $ 218,950
January 6, 2004 310,000 150% 4% 3 659,153
March 19, 2004 30,000 150% 4% 3 58,881
September 9, 2004 182,500 150% 4% 3 462,674
----------
1,399,658
Stock based compensation expense recognized in 2003 (77,764)
Stock based compensation expense recognized in 2004 (604,598)
----------
Amount for future recognition $ 717,296
----------
----------


8. Related party transaction

On August 31, 2004, the Company disposed of oil and gas properties,
through a marketed competitive bid process, to a corporation owned by
persons related to an officer of the Company for an exchange amount of
$263,000.

9. Commitments

The Company is committed to a minimum annual lease payment of $24,850
under a rental agreement for office space until September 2005.

10. Per share data

Basic per share data per Class A and Class B shares is based upon the
weighted average number of Class A shares and the weighted average
number of Class B shares outstanding during the period. For the purpose
of per share data calculation, it is assumed that the Class B shares are
converted into Class A shares using the December 31, 2004 trading price
of $3.59 (December 31, 2003 - $2.85). Diluted per share data is based
upon the weighted average number of Class A and Class B shares
outstanding during the period after giving effect to the exercise of the
share options. The total weighted average number of Class A and Class B
shares are as follows:



For the year ended For the period ended
December 31, 2004 December 31, 2003
------------------ ---------------------

Weighted average number of
Class A shares 12,109,980 5,487,965
Deemed conversion of Class
B shares to Class A shares
(Weighted average number of
Class B shares times $10
divided by period end
trading price)
832,500 x $10/$3.59 (2003-
498,546 x $10/$2.85) 2,318,942 1,749,284
------------------ ---------------------
Equivalent Class A Basic shares 14,428,922 7,237,249
------------------ ---------------------
------------------

Equivalent Class A Diluted shares 15,161,170 7,896,594
------------------ ---------------------
---------------------


11. Financial instruments

The Company's financial instruments consist of accounts receivable and
accounts payable and accrued liabilities. Unless otherwise noted, it is
management's opinion that the Company is not exposed to significant
interest, currency or credit risks arising from these financial
instruments. The fair values of financial instruments that are included
in the balance sheet approximate their carrying amount due to the
short-term maturity or the floating rate nature of those instruments.

12. Comparative figures

Certain comparative figures have been reclassified to conform with
current year's presentation.


-30-

Contact Information

  • FOR FURTHER INFORMATION PLEASE CONTACT:
    Hawk Energy Corp.
    Steve Fitzmaurice
    President and Chief Executive Officer
    (403) 262-1204 ext. 1
    (403) 313-4295 (FAX)
    Email: stevef@hawkenergy.ca
    or
    Hawk Energy Corp.
    Erik DeWiel
    Vice-President, Land
    (403) 262-1204 ext. 2
    Email: erikd@hawkenergy.ca