TEMPEST ENERGY CORP.

TEMPEST ENERGY CORP.

March 07, 2005 09:00 ET

Tempest Energy Corp. Provides Year End Financial Statements, Reserves and Management Discussion and Analysis.


NEWS RELEASE TRANSMITTED BY CCNMatthews

FOR: TEMPEST ENERGY CORP.

TSX SYMBOL: TMY.A
TSX SYMBOL: TMY.B

MARCH 7, 2005 - 09:00 ET

Tempest Energy Corp. Provides Year End Financial
Statements, Reserves and Management Discussion and
Analysis.

CALGARY, ALBERTA--(CCNMatthews - March 7, 2005) - Tempest Energy Corp.
(TSX:TMY.A) (TSX:TMY.B) is pleased to release its year end reserves,
financial statements and management discussion and analysis.



Highlights Twelve Months Twelve Months Twelve Months
Ended Ended Ended
Operating Dec. 31, 2004 Dec. 31, 2003 Dec. 31, 2002
------------------------------------------------------------------------

Production

Crude oil and NGLs
(bbls/d) 1,388 1,848 1,475
Natural gas (mcf/d) 13,473 5,102 2,575
------------------------------------------------

Barrels of oil
equivalent (6:1)
(boe/d) 3,634 2,699 1,904

Prices

Crude oil and NGLs
($/bbl) 46.13 30.04 30.87
Natural gas ($/mcf) 6.47 6.18 3.99
------------------------------------------------
Barrels of oil
equivalent (6:1)
($/boe) $ 41.63 $ 33.98 29.30

Operating costs ($/boe) $ 6.47 $ 5.66 4.82

Financial
($thousands, except
share data)
Petroleum and natural
gas sales $ 55,363 $ 33,473 20,364
Cash flow from operations 28,797 16,275 11,633
Per basic share 1.55 0.97 0.92
Per diluted share 1.52 0.95 0.88

Net income 4,171 967 1,746
Per basic share 0.23 0.06 0.14
Per diluted share 0.22 0.06 0.13

Total assets 123,358 89,254 55,004

Total liabilities 62,254 45,212 23,582

Working capital (deficit) (32,167) (20,859) (5,085)

Capital expenditures 50,962 47,499 34,316

Shares outstanding
Class A 19,060,810 17,370,319 14,737,933
Class B 653,476 653,476 653,476
Options 1,499,004 2,076,704 2,116,867

Basic shares
(weighted)(1) 18,513,240 16,756,145 12,651,760
Diluted shares
(weighted) 18,924,314 17,067,422 13,257,405
------------------------------------------------------------------------

(1) Class B shares are fully converted in basic calculation
(See the Equity section in the MD&A for the calculation).


Significant Financial Events

- Production, revenue and cash flow were higher in 2004 by 35 percent,
65 percent and 77 percent, respectively.

- Tempest raised $10.0 million on December 13, 2004, issuing 1,162,791
Class A shares at a price of $8.60 per Class A share, on a flow-through
basis.

- Tempest has hedged 5,000 gigajoules (GJ) per day of natural gas, using
a three-way structure, for the period August 2004-July 2005. This hedge
is based on the AECO benchmark price in Canadian dollars and includes
the purchase of a $6.21 per GJ put (floor), the sale of a $7.00 per GJ
call and the purchase of an $8.68 per GJ call.

- Tempest syndicated its banking facilities to the CIBC and the National
Bank to establish a $40.0 million bank line.



2004 Overview and 2005 Guidance
------------------------------------------------------------------------
2004
2005 2004 % of 2003 Undeveloped
Estimate Production Total Production Land
Area (boe/d) (boe/d) Production (boe/d) (net acres)
------------------------------------------------------------------------
Chipman oil 800 1,094 30 1,727
Chipman gas 500 465 15 328 39,178
Fort
Saskatchewan
gas 800 161 5 2 34,103
Red Earth oil 700 294 10 121
Red Earth gas 100 180 5 450 48,814
Otter gas 300 642 17 0 3,695
Norris gas 500 109 3 4 14,941
Looma/Joarcam
gas 500 606 17 60 5,581
Other/Cygnet 300-800 84 - 7 59,737
Total 4,500-5,000 3,634 100 2,699 206,049


2004 Overview

In 2004 Tempest continued to execute its core strategies of exploration
and development, with growth predominantly through the drill bit. At the
outset of 2004, Tempest announced guidance for production (3,600 boe per
day), cash flow ($25.0 million) and earnings before tax ($8.0 million).
Actual results included production (3,634 boe per day), cash flow ($28.8
million or $1.56 per basic share) and earnings before tax ($6.8 million
or $0.37 per basic share). Net income was negatively affected by higher
than anticipated depletion charges and the adoption of stock-based
compensation and fourth quarter results were negatively affected by
water issues at Otter.

Tempest drilled 39 (32.8 net) net wells in 2004, which resulted in 14
(8.5) net oil wells, 15 (14.9 net) natural gas wells and 10 (9.4) dry
and abandoned wells, for a success ratio of 74 percent. The drilling
program shifted Tempest's production mix to 62 percent natural gas from
68 percent oil in 2003. As well Tempest added 38,333 net acres of
undeveloped land during the year.

Central Area

The use of 3-D seismic in the Chipman area has been key to locating
natural gas opportunities. The area produced more than two times the
volume of natural gas in 2004 compared to 2003, resulting in natural gas
equivalent production of 810 boe per day versus 401 boe per day in 2003.
In Central Alberta, Tempest closed a $6.0 million property acquisition
at mid-year which added production, some new facilities and over 20
sections of land at Bon Accord. As well, Tempest continued drilling
development wells at Joarcam, which increased production to more than 17
percent of the 2004 corporate total.

Northern Core Area

From January to March 2004 Tempest tied in its Otter natural gas wells.
This gas provided over $5 million or approximately 15 percent of total
operating income to Tempest in 2004. On the oil side, the Company
drilled eight (4.5 net) wells in the January to March 2004 time-frame
and an additional 12 (7.5 net) wells from December 2004 to March 2005.
Production results in early 2004 were disappointing based on the
information received while drilling the wells. However, the Company
prepared a water-flood report in the summer of 2004 and subsequent
drilling has confirmed that pressure maintenance could greatly enhance
the value of the oil pool.

In order to maintain a strong balance sheet and have access to
acquisition opportunities, Tempest completed an equity financing on
December 13, 2004. The Company issued 1,162,791 Class A shares at $8.60
per share on a flow-through basis. Also, as part of risk management,
Tempest hedged 5,000 GJs per day of natural gas to July 2005. To
maintain a reasonable level of leverage the Company will access sources
of financing, including entering the equity markets as required. The
Company also has credit available through existing banking lines and
will deploy capital as we encounter appropriate opportunities.

2005 Guidance

Annual forecasts for 2005 include average production (4,500-5,000 boe
per day), cash flow ($35-$40 million or approximately $1.70-$1.90 per
basic share), earnings ($7-$9 million) and capital expenditures ($40-$50
million).

2005 Year-to-Date Activities

Northern Alberta Core Area

Since drilling the initial Red Earth discovery in February 2003, Tempest
has drilled 17 (10 net) delineation wells which have intersected Keg
River oil pay including 12 (7.5 net) wells drilled from December 2004 to
March 2005, which delineated the pool over eight sections of land and
proved up a significant aerial extension to the Keg River pool. The new
wells are now on-stream with initial production rates of 50-200 barrels
of oil per day per well.

During break-up Tempest will evaluate strategies for the entire property
including development and exploration drilling, seismic analysis and
interpretation, as well as water-flood and facility options. An
additional 15-20 development drilling locations have been identified on
3-D seismic, with over 10 sections of additional lands prospective from
an exploration/extension point of view.

Production from this property is long life, 40 degrees API oil which
generates strong netbacks reflecting Edmonton par oil prices less $1.50
per barrel, with some wells receiving a royalty holiday. Tempest
anticipates that the pool will average 600-800 bbls per day of light oil
in 2005, and provide further growth in 2006 and beyond.

Northern Natural Gas

In December of 2004, Tempest temporarily suspended natural gas
production of about 800 boe per day to install water handling facilities
at Otter. Otter production in the first quarter of 2005 is expected to
average 300 boe per day, after internal compressor problems shut in more
than 500 per day for approximately one month.

Chipman Oil

The Chipman oil pools represent approximately 900 barrels per day of low
decline production. Tempest now has five electric submersible pumps
operating in the Chipman oil property. Based on their performance, the
Company may install 2-4 additional pumps in 2005. As well, Tempest plans
to drill an additional 2 horizontal infill wells during break-up to
complete the delineation of these pools.

Chipman Natural Gas

Chipman gas represents approximately 13 percent of 2004 corporate
production. As these properties decline, we expect that further drilling
identified on the offsetting new 3-D at Norris will backfill the
volumes. Tempest is considering a 10 kilometre pipeline to Atco to
eliminate production bottlenecks in the area. These facilities would
cost approximately $3 million to build, with construction dependent on
finding sufficient reserves at Norris.

Central Area Natural Gas

Looma/Joarcam represents 17 percent of 2004 production and will be a
strong asset for many years, based in part on the property's coal-bed
methane (CBM) potential.

W5 Central Exploration

Tempest recently drilled a 100 percent working interest well in its
emerging W5 multi-zone area. The well encountered two primary and two
secondary zones. Results from completion operations will determine a
development strategy for these potential reserves. The Company has over
15 sections of contiguous land in the area.

3-D Seismic Programs

Tempest has invested heavily in 3-D seismic for its exploration program,
which covers a significant proportion of the Company's undeveloped
acreage. There are four distinct parts to this investment:

- An 86.5 square kilometre 3-D seismic program west of Chipman in
Central Alberta, which has now been completed;

- A 12 square kilometre 3-D program on 100 percent working-interest
lands on the northern edge of the Red Earth Keg River oil pool, now
completed;

- A 113 square kilometre 3-D seismic program at Fort
Saskatchewan/Redwater in the Central Area, which will be completed by
mid-March; and

- A 13 square kilometre 3-D program over lands held at Redwater in
Central Alberta, which will be completed by the end of March.

The data from these 3D seismic programs will be interpreted during
break-up leading to an extensive exploration drilling program.

Outlook

Tempest continues to focus strongly on exploration. However, based on
our successes and related follow-up development activity, we expect to
balance our exploration with development drilling efforts in 2005. We
are engaged in extensive development drilling in the Northern Area in
the first quarter which are expected to follow with exploration drilling
on 3-D prospects in the Central area in the third and fourth quarters.

Undeveloped Land

As an exploration-driven company, Tempest continuously focuses on
generating new opportunities. Continuous growth in the undeveloped land
base is key to success. Tempest's land strategy is primarily
prospect-driven, with limited land purchases made on-trend or for
competitive reasons. Lands are acquired through Crown sales (frequently
posted by Tempest), through freehold leasing and through farm-ins on a
drill-to-earn basis. The Company seeks high-working-interests and large
contiguous blocks. Tempest frequently employs brokers in order to keep
details of land purchases confidential for competitive reasons.

In 2004 Tempest's land budget totalled $5.4 million, or 10 percent of
overall capital expenditures. Central Alberta accounted for the majority
of funds spent on land in 2004. At year-end 2004 Tempest's land base was
206,049 net undeveloped acres with an average working interest of 87
percent, a 23 percent increase in net acres from year-end 2003. An
independent evaluation at December 31, 2004 valued these lands at $22.1
million.

In 2005 Tempest will continue to build its base of undeveloped land,
with a similar ratio of capital spending assigned to land purchases.



Land Holdings
------------------------------------------------------------------------
2004 2003
------------------------------------------------------------------------
Acres Gross Net W.I.% Gross Net W.I.%

Developed 42,342 37,768 89 26,930 22,337 83
Undeveloped 236,715 206,049 87 199,746 167,716 84
---------------------------------------------------
Total 279,057 243,817 87 226,676 190,053 84
------------------------------------------------------------------------
------------------------------------------------------------------------


Net Undeveloped Land by Area
------------------------------------------------------------------------
2004 2003
------------------------------------------------------------------------
Acres Gross Net Gross Net

Northern 104,880 74,969 99,920 68,965
Central 121,501 121,002 92,224 91,661
Other 10,334 10,078 7,602 7,090
---------------------------------------------------
Total 236,715 206,049 199,746 167,716
------------------------------------------------------------------------
------------------------------------------------------------------------


Drilling Activity

Tempest drilled 39 (32.8 net) wells in 2004, in line with the 40-60
wells forecast. For 2005 Tempest expects to drill 40-60 wells.


Drilling Activity
------------------------------------------------------------------------
2004 2003
------------------------------------------------------------------------
Number of wells Gross Net W.I.% Gross Net W.I.%
Oil 15 9.5 63 13 10.8 83
Natural gas 18 17.9 99 20 19.4 97
Dry/service 6 5.4 90 8 8.0 99
-----------------------------------------------
39 32.8 87 41 38.2 93
-----------------------------------------------
-----------------------------------------------

Exploration 27 26.3 97 29 26.8 93
Development 12 6.5 54 12 11.3 95
-----------------------------------------------
Total 39 32.8 87 41 38.2 93
-----------------------------------------------
-----------------------------------------------

Success rate (%) 85 92 - 81 79.2 -
------------------------------------------------------------------------


Production and Reserves

Tempest's production averaged 3,634 boe per day in 2004, an increase of
35 percent from the 2003 average of 2,699 boe per day. Volume growth was
achieved through exploratory and development drilling on
internally-generated prospects. Average volumes consisted of 13.5 mmcf
per day of natural gas and 1,388 bbls per day of crude oil and NGLs, for
an average natural gas weighting of 62 percent, compared to 32 percent
in 2003.

One hundred percent of Tempest's reserves as at December 31, 2004 were
independently evaluated by Gilbert Laustsen Jung Associates (GLJ),
independent reservoir engineers, according to the requirements of
National Instrument (N.I.) 51-101. The following summary presentation
and discussion conform in all material respects to the results of GLJ's
evaluations.

Tempest increased its base of net proved and probable reserves in 2004.
Tempest's discoveries and pool extensions added 2.5 million boe of
proved plus probable reserves, replacing 2004 production by 1.9 times.

Before accounting for the year's production, Tempest's year-end proved
reserves were up by 64 percent and proved plus probable reserves were
higher by 41 percent over 2003 reserves.



------------------------------------------------------------------------
Year over
% of % of Year
Reserves Category 2004 Total 2003 Total % Change
------------------------------------------------------------------------
Proved Producing 4,519 61% 2,568 41% 76%
------------------------------------------------------------------------
Proved Developed
Non-producing 765 10% 1,369 22% -44%
------------------------------------------------------------------------
Proved Undeveloped 514 7% 410 7% 25%
------------------------------------------------------------------------
Total Proved 5,798 78% 4,347 70% 33%
------------------------------------------------------------------------
Probable 1,641 22% 1,851 30% -11%
------------------------------------------------------------------------
Total Proved plus
Probable Reserves 7,439 100% 6,198 100% 20%
------------------------------------------------------------------------


Summary of Oil & Gas Reserves (forecast prices and costs)

Light/Medium Oil Natural Gas Total
Gross Net Gross Net Gross Net
Reserves Category (mbbl) (mbbl) (mmcf) (mmcf) (mboe) (mboe)
------------------------------------------------------------------------
Proved
Developed
producing 2,320 1,965 13,190 10,262 4,519 3,675
Developed
non-producing 494 372 1,627 1,253 765 581
Undeveloped 424 334 541 450 514 409
Total proved 3,239 2,671 15,356 11,965 5,798 4,665
Probable 865 710 4,658 3,686 1,641 1,324
Total proved
plus probable 4,104 3,381 20,014 15,651 7,439 5,989

Note: Gross represents Company working interest before Royalties. Net
represents Company working interest AFTER Royalties.


Net Present Values of Future Net Revenue (forecast prices and costs)
Before Income Taxes After Income Taxes
Discounted At (%/yr) Discounted At (%/yr)
($ millions) 0 5 10 15 20 0 5 10 15 20
------------------------------------------------------------------------
Reserves
Category
Proved
Developed 83.6 74.5 67.5 61.9 57.3 70.8 62.6 56.3 51.4 47.4
Developed
non-
producing 16.8 14.7 13.1 11.9 10.8 11.4 9.7 8.3 7.2 6.5
Un-
developed 6.4 4.6 3.5 2.6 1.9 4.4 3.0 2.2 1.6 1.1

Total
proved 106.8 93.9 84.0 76.3 70.1 86.6 75.3 66.8 60.2 55.0
Probable 28.7 21.5 16.9 13.7 11.3 20.2 14.7 11.3 8.9 7.2

Total
proved
plus
probable 135.5 115.4 100.9 90.0 81.4 106.8 90.0 78.1 69.1 62.2


Total Future Net Revenue (Undiscounted) (forecast prices and costs)

Well
($ millions) Operating Development Abandonment
Reserves Royalties Costs Costs Costs
Category
Proved reserves 37.7 70.1 7.8 2.2
Proved plus probable
reserves 48.8 90.5 10.9 2.4


Future Net Future Net
Revenue Revenue
Before After
($ millions) Income Income Income
Reserves Taxes Taxes Taxes
Category
Proved reserves 106.8 20.2 86.6
Proved plus probable reserves 135.4 28.7 106.8


Summary of Pricing and Exchange Rate Assumptions
(forecast prices and costs)

WTI Edmonton Hardisty
Cushing Par Price Heavy
(Oklahoma) 40 degrees API 12 degrees API
Year (US$/bbl) (Cdn$/bbl) (Cdn$/bbl)
------------------------------------------------------------------------
Historical
2003 31.07 43.66 26.26
2004 41.38 52.96 29.11
Forecast
2005 42.00 50.25 27.50
2006 40.00 47.75 28.50
2007 38.00 45.50 28.75
2008 36.00 43.25 27.25
2009 34.00 40.75 25.50
2010 33.00 39.50 24.75
2011 33.00 39.50 24.75
2012 33.00 39.50 24.75
2013 33.50 40.00 24.75
2014 34.00 40.75 25.50
2015 34.50 41.25 25.75
2016 35.19 42.08 26.27
2017 35.89 42.92 26.79
2018 36.61 43.77 27.33
2019 37.34 44.65 27.87


Cromer Medium Natural Gas
29.3 degrees API AECO gas Price Exchange Rate
Year (Cdn$/bbl) (Cdn$/GJ) (US$/Cdn$)
------------------------------------------------------------------------
Historical
2003 37.55 6.32 0.721
2004 45.75 6.53 0.769
Forecast
2005 43.75 6.27 0.820
2006 41.50 6.03 0.820
2007 39.50 5.84 0.820
2008 37.75 5.70 0.820
2009 35.50 5.70 0.820
2010 34.25 5.70 0.820
2011 34.25 5.70 0.820
2012 34.25 5.70 0.820
2013 34.75 5.79 0.820
2014 35.50 5.89 0.820
2015 36.00 5.98 0.820
2016 36.72 6.10 0.820
2017 37.45 6.22 0.820
2018 38.20 6.35 0.820
2019 38.97 6.48 0.820


Reconciliation of Company Gross Reserves by Principal Product Type
(forecast prices and costs)

Light/
Medium Oil
Proved
Plus
Proved Probable Probable
Factors (mbbl) (mbbl) (mbbl)
------------------------------------------------------------------------
December 31, 2003 2341.3 740.2 3082.3
Discoveries and Extensions 1056.5 283.5 1340.0
Acquisitions 0 0 0

Dispositions 0 0 0

Production 508 0 508.0
Technical Revisions 349.3 (159.4) 189.9
December 31, 2004 3239.1 864.3 4104.2

Associated and Non-Associated Gas
Proved
Plus
Proved Probable Probable
Factors (mmcf) (mmcf) (mmcf)
------------------------------------------------------------------------
December 31, 2003 12043.2 6819.5 18862.7
Discoveries and Extensions 4262.6 1358.0 5620.6
Acquisitions 775.9 110.1 886.0

Dispositions 0 0 0

Production 4931.2 0 4931.2
Technical Revisions 3205.6 (3628.6) (423.0)
December 31, 2004 15356.1 4659.0 20015.1


Total
Proved
Plus
Proved Probable Probable
Factors (mboe) (mboe) (mboe)
------------------------------------------------------------------------
December 31, 2003 4348.5 1876.8 6226.1
Discoveries and Extensions 1767.0 509.8 2276.8
Acquisitions 129.3 18.4 147.7

Dispositions 0 0 0

Production 1329.9 0 1329.9
Technical Revisions 883.6 (764.2) 119.4
December 31, 2004 5798.5 1640.8 7440.1


Note: No Heavy Oil


Summary of Oil and Gas Reserves (constant prices and costs)

Light/Medium Oil Natural Gas
(mbbl) (mmcf) Total
Reserves Category Gross Net Gross Net Gross Net
------------------------------------------------------------------------
Proved
Developed
producing 2,461 2,119 13,255 10,318 4,670 3,839
Developed
non-producing 494 369 1,627 1,253 765 578
Undeveloped 424 342 541 450 514 417
Total proved 3,379 2,830 15,423 12,021 5,949 4,834
Probable 883 727 4,671 3,696 1,662 1,343
Total proved
plus probable 4,262 3,557 20,094 15,717 7,611 6,176

Note: No Heavy Oil or Natural Gas Liquids


Net Present Values of Future Net Revenue (constant prices and costs)

Before Income Taxes Discounted At (%/yr)
0 5 10 15 20
Reserves Category ($MM) ($MM) ($MM) ($MM) ($MM)
------------------------------------------------------------------------
Proved
Developed 84.4 74.4 66.7 60.8 55.9
Developed non-producing 18.2 15.7 13.8 12.3 11.2
Undeveloped 6.1 4.4 3.2 2.3 1.7
Total proved 108.7 94.4 83.7 75.4 68.8
Probable 33.1 24.5 19.0 15.3 12.6
Total proved plus probable 141.8 118.9 102.7 90.7 81.4

After Income Taxes Discounted At (%/yr)
0 5 10 15 20
Reserves Category ($MM) ($MM) ($MM) ($MM) ($MM)
------------------------------------------------------------------------
Proved
Developed 72.1 63.0 56.2 50.9 46.7
Developed non-producing 9.7 7.8 6.4 5.3 4.5
Undeveloped 6.5 5.2 4.3 3.6 3.1
Total proved 88.4 76.0 66.8 59.8 54.3
Probable 22.9 16.5 12.6 9.9 8.1
Total proved plus probable 111.2 92.5 79.4 69.8 62.3


Total Future Net Revenue Undiscounted (constant prices and costs)

Well
($ millions) Operating Development Abandonment
Reserves Royalties Costs Costs Costs
Category
Proved reserves 36.0 68.9 7.9 1.9
Proved plus probable
reserves 47.5 86.2 11.0 2.0


Future Net Future Net
Revenue Revenue
Before After
($ millions) Income Income Income
Reserves Tax Taxes Taxes
Category
Proved reserves 108.7 20.4 88.4
Proved plus probable reserves 141.8 30.6 111.2


Summary of Pricing Assumptions (constant prices and costs)

WTI Edmonton Hardisty
Cushing Par Price Heavy
(Oklahoma) 40 degrees API 12 degrees API
Year ($US/bbl) ($Cdn/bbl) ($Cdn/bbl)
------------------------------------------------------------------------
Historical (year end)
2000 30.22 44.56 32.61
2001 25.97 39.40 23.48
2002 26.08 40.33 30.60
2003 31.07 43.66 31.18
2004 (year end) 41.38 52.96 35.64


Cromer Medium Natural Gas
29.3 degrees API AECO gas Price Exchange Rate
Year ($Cdn/bbl) ($Cdn/GJ) ($US/$Cdn)
------------------------------------------------------------------------
Historical (year end)
2000 39.91 5.08 .6740
2001 31.56 6.21 .6448
2002 35.48 4.04 .6376
2003 37.55 6.66 .7213
2004 (year end) 45.75 6.88 .7734


Capital Expenditures
------------------------------------------------------------------------
Inception
($000s) 2004 % to Date %
------------------------------------------------------------------------
Land and lease 5,374 11% 20,404 13%
------------------------------------------------------------------------
Seismic 2,828 6% 9,398 6%
------------------------------------------------------------------------
Drilling and completions 20,956 41% 70,493 46%
------------------------------------------------------------------------
Property acquisitions 6,000 12% 10,716 7%
------------------------------------------------------------------------
Property dispositions 0 0% 0 0%
------------------------------------------------------------------------
Finding costs 35,158 70% 111,011 72%
------------------------------------------------------------------------
Facilities 15,804 30% 40,698 28%
------------------------------------------------------------------------
Corporate assets 0 0% 691 0%
------------------------------------------------------------------------
Finding and development costs spent 50,962 100% 152,400 100%
------------------------------------------------------------------------
Acquisition tax accrual 0 2,397
------------------------------------------------------------------------
Finding and development costs 50,962 100% 154,797 100%
------------------------------------------------------------------------


Finding and Development Costs

------------------------------------------------------------------------
Proved
Capital Reserve Proved
Expenditures Additions Costs
------------------------------------------------------------------------
$ 000s mboe $/boe
------------------------------------------------------------------------
Drilling costs on exploration and
development program 20,956 2,779 7.54
------------------------------------------------------------------------
Finding costs on exploration and
development program before 2004
revisions 35,158 2,779 12.65
------------------------------------------------------------------------
F&D exploration and development program
after 2004 revisions (a) 50,962 2,779 18.34
------------------------------------------------------------------------
Change in proved future development
capital (b) (1) (4,016) n/a n/a
------------------------------------------------------------------------
Change in proved plus probable future
development capital (c) (1) (1,884) n/a n/a
------------------------------------------------------------------------
Proved F&D including change in proved
future development capital (d) = (a)+(b) 46,946 2,779 16.89
------------------------------------------------------------------------
Proved plus probable F&D including
change in proved future development
capital (e) = (a)+(c) 49,078 n/a n/a
------------------------------------------------------------------------

------------------------------------------------------------------------
Inception
to Date
Proved Plus Proved Average
Probable Plus Proved
Reserve Probable Plus
Additions Costs Probable(i)
------------------------------------------------------------------------
Mboe $/boe $ boe
------------------------------------------------------------------------
Drilling costs on exploration and
development program 2,544 8.24 7.31
------------------------------------------------------------------------
Finding costs on exploration and
development program before 2004
revisions 2,544 13.82 11.51
------------------------------------------------------------------------
F&D exploration and development
program after 2004 revisions (a) 2,544 20.03 15.80
------------------------------------------------------------------------
Change in proved future development
capital (b) (1) n/a n/a n/a
------------------------------------------------------------------------
Change in proved plus probable future
development capital (c) (1) n/a n/a n/a
------------------------------------------------------------------------
Proved F&D including change in proved
future development capital (d) = (a)+(b) n/a n/a 16.61
------------------------------------------------------------------------
Proved plus probable F&D including
change in proved future development
capital (e) = (a)+(c) 2,544 19.29 16.93
------------------------------------------------------------------------
(i) Includes established basis for 2001 and 2002

(1) Change in future development capital
--------------------------------------------------------
Proved Plus
($000s) Proved Change Probable Change
--------------------------------------------------------
2004 7,823 10,925
--------------------------------------------------------
-4,016 -1,884
--------------------------------------------------------
2003 11,839 12,809
--------------------------------------------------------


The following cautionary statements need to be considered when
evaluating finding and development costs; first, the aggregate of the
exploration and development costs incurred in the most recent financial
year and the change during that year in future development costs
generally will not reflect total finding and development costs related
to reserve additions for that year; and second, the term BOE may be
misleading, a Boe conversion ratio 6 mcf:1 bbl is based on an energy
equivalency conversion method primarily applicable at the burner tip and
does not represent a value equivalency at the wellhead.



Reserve Life Index

---------------------------------------------------------------------
Production (mboe) 1,329,906
---------------------------------------------------------------------
Proven reserves (mboe) 5,798,500
---------------------------------------------------------------------
Proven reserve life index (years) 4.4
---------------------------------------------------------------------
Proven plus probable reserves (mboe) 7,440,100
---------------------------------------------------------------------
Proven plus probable reserve life index (years) 5.6
---------------------------------------------------------------------


Recycle Ratio

The recycle ratio is a measure for evaluating the effectiveness of a
Company's reinvestment program. The ratio measures how well the Company
replaced every boe of production. The chart below depicts that Tempest
received a net $21.65 per boe it sold and it cost $16.89 to find a
replacement boe.



---------------------------------------------------------------------
2004 (6:1)
---------------------------------------------------------------------
Operating netback ($/boe) 21.65
---------------------------------------------------------------------
Proven finding and development costs ($/boe) 16.89
---------------------------------------------------------------------
Proven reinvestment efficiency ratio 1.3
---------------------------------------------------------------------
Proven + probable finding and development costs ($/boe) 19.29
---------------------------------------------------------------------
Proven + probable reinvestment efficiency ratio 1.1
---------------------------------------------------------------------


Reserves Replacement

---------------------------------------------------------------------
2004 2003
---------------------------------------------------------------------
Oil (bbls) 508,046 674,648
---------------------------------------------------------------------
Natural gas (mcf) 4,931,158 2,537,032
---------------------------------------------------------------------
---------------------------------------------------------------------
Equivalent barrels (boe) 1,329,906 985,045
---------------------------------------------------------------------

---------------------------------------------------------------------
Reserve addititions 2,544,000 3,382,000
---------------------------------------------------------------------
Reserves Replacement 1.9 3.4
---------------------------------------------------------------------

---------------------------------------------------------------------
Oil (bbls/day) 1,388 1,848
---------------------------------------------------------------------
Natural gas (mcf/day) 13,473 5,102
---------------------------------------------------------------------
Equivalent barrels (boe/day) 3,634 2,699
---------------------------------------------------------------------


Net Asset Value

Tempest presents one method for calculating net asset value below. This
calculation is presented for December 31, and incorporates estimates
that may not be comparable year-over-year and are only at a point in
time. An independent evaluation was performed for land and reserves for
both years. The reader is cautioned that the presentation does not
reflect all aspects of the Company and that reserve definitions changed
after 2002 (see MD&A discussion regarding new accounting and regulatory
requirements).



---------------------------------------------------------------------
($000s) 2004 2003
---------------------------------------------------------------------
Present value of reserves
(P+P discounted at 10%) 100,912 62,821
---------------------------------------------------------------------
Undeveloped acreage 22,139 15,869
---------------------------------------------------------------------
Working capital deficiency (32,167) (20,859)
---------------------------------------------------------------------
Option proceeds 5,533 7,161
---------------------------------------------------------------------
Tax pools at 10% 5,560 4,820
---------------------------------------------------------------------
Estimated value 101,977 69,812
---------------------------------------------------------------------

---------------------------------------------------------------------
Diluted shares 21,537 20,564
---------------------------------------------------------------------
Per diluted share 4.74 3.40
---------------------------------------------------------------------


Diluted shares includes all outstanding class A shares as well assuming
the full conversion of the class B shares at the year-end closing price
for Tempest's Class A shares (2004 - $6.69, 2003 - $5.85) and the
exercise of all stock options.



FINANCIAL AND OPERATING SUMMARY

Fourth Fourth Twelve Twelve
Quarter Quarter Months Months
Ended Ended Ended Ended
Dec. 31, Dec. 31, Dec. 31, Dec. 31,
2004 2003 % 2004 2003 %
(000s) (000s) Change (000s) (000s) Change
------------------------------------------------------------------------
Oil revenue 5,985 4,520 32% 23,438 23,995 -2%
Oil hedging - (560) -100% - (2,318) -100%
Natural gas revenue 8,581 3,327 158% 31,852 11,796 170%
Natural gas hedging 13 - 100% 74 - 100%
Oil and natural gas
revenue 14,579 7,287 100% 55,363 33,473 65%
Royalties
(net of ARTC) (2,536) (1,721) 47% (11,942) (7,716) 55%
Production expenses (4,507) (1,837) 145% (10,475) (7,276) 44%
Field netback 7,535 3,730 102% 32,946 18,481 78%
Interest expense (365) (79) 361% (1,262) (384) 229%
Interest income 1 1 -32% 3 12 -76%
General and
administrative cost (1,063) (733) 45% (3,823) (2,726) 38%
G & A recoveries 29 51 -43% 174 186 -6%
G & A capitalized 662 (299) -321% 1,140 825 38%
Reclamation (260) - -100% (260) - 100%
Income tax expense (31) (30) 2% (121) (120) 1%
Cash flow from
operations 6,508 2,641 146% 28,797 16,275 77%
Depletion depreciation
and accretion (5,956) (4,003) 49% (20,531) (12,529) 64%
Stock based (417) (482) -14% (1,802) (1,851) -3%
Earnings (loss) before
income tax 426 (1,815) -123% 6,845 2,015 240%
Future income tax
(expense) recovery 136 683 -80% (2,554) (928) 175%
Net earnings (loss) 531 (1,162) -146% 4,171 967 331%

Full Year 2004 Full Year 2003
(per boe @ 6:1) (per boe @ 6:1)
------------------------------------------------------------------------
Oil revenue 46.13 33.57
Oil hedging - (3.44)
Natural gas revenue 38.76 37.97
Natural gas hedging 0.09 -
Oil and natural gas revenue 41.63 33.98
Royalties (net of ARTC) (8.98) (7.83)
Production expenses (7.88) (7.39)
Field netback 24.77 18.76
Interest expense (0.95) (0.39)
Interest income 0.00 0.01
General and administrative cost (2.87) (2.82)
G & A recoveries 0.13 0.19
G & A capitalized 0.86 0.84
Reclamation (0.20) -
Income tax expense (0.09) (0.12)
Cash flow from operations 21.65 16.52
Depletion depreciation and accretion (15.44) (12.72)
Stock based (1.35) (1.88)
Earnings (loss) before income tax 5.15 2.04
Future income tax (expense) recovery (1.92) (0.94)
Net earnings (loss) 3.14 0.98


Management's Discussion and Analysis

The following discussion and analysis is a review of operations, current
financial position and outlook for the Company and should be read in
conjunction with the audited consolidated financial statements and
related notes. This discussion reflects the combined totals of Tempest
Energy Corp. and its wholly-owned subsidiaries 951554 Alberta Ltd. and
Point Bar Petroleums Ltd. as well as their combined Partnership
arrangement, the Tempest Energy Production Partnership which
collectively are referred to as "Tempest" or the "Company".

The terms "cash flow from operations", "cash flow", "cash flow per
share" and "debt-to- cash-flow ratio" in this discussion are not
recognized measures under Canadian generally accepted accounting
principles (GAAP). Management believes that in addition to net earnings,
cash flow is a useful supplemental measure as it provides an indication
of the results generated by the Company's principal business activities
before the consideration of how those activities are financed or how the
results are taxed. Investors are cautioned, however, that this measure
should not be construed as an alternative to net earnings determined in
accordance with GAAP, as an indication of Tempest's performance.

Tempest's method of calculating cash flow may differ from other
companies, and accordingly it may not be comparable to measures used by
other companies. Tempest calculates cash flow from operations as "funds
from operations" before the change in non-cash working capital related
to operating activities. In addition, the terms "cash flow" and "funds
from" are used interchangeably. The consolidated statements of cash
flows in the audited consolidated financial statements present the
reconciliation between earnings and cash flow. All boe numbers are
calculated converting natural gas mcf to boe at 6:1.

Forward-Looking Statements

Statements in this document may contain forward-looking information.
Estimates provided for 2005 and beyond are based on assumptions of
future events and actual results could vary significantly from these
estimates. The reader is cautioned that assumptions used in the
preparation of such information may prove to be incorrect. Events or
circumstances may cause actual results to differ materially from those
predicted as a result of numerous known and unknown risks,
uncertainties, and other factors, many of which are beyond the control
of the Company. The reader is cautioned not to place undue reliance on
this forward-looking information. Additional information relating to
Tempest, including the Annual Information Form (AIF) is available at
www.sedar.com or the Company's website www.tempestenergy.com.



Production
------------------------------------------------------------------------
Quarter Ended December 31 Year Ended December 31
2004 2003 % Change 2004 2003 % Change
------------------------------------------------------------------------

Production
Oil (bbls/d) 1,284 1,384 (7) 1,388 1,848 (25)
Gas (mcf/d) 14,694 6,484 127 13,473 5,102 164
Total (boe/d) 3,733 2,464 52 3,634 2,699 35
Price
Oil ($/bbl) 50.67 24.07 111 46.13 30.04 54
Gas ($/mcf) 6.35 5.17 23 6.47 6.18 5
Total ($/boe) 42.45 27.11 57 41.63 32.25 29

% oil 34 56 38 68


Tempest's 2004 production rose 35 percent to an average 3,634 boe per
day (38 percent oil) versus 2,699 boe per day (68 percent oil) in 2003.
This equates to a 25 percent decrease in oil production and a 164
percent increase in natural gas production. The new natural gas
production came mainly from Otter, Fort Saskatchewan and Joarcam.

In the fourth quarter of 2004, production was 52 percent higher at 3,733
boe per day compared to the same period in 2003, but was down from the
4,001 boe per day in the third quarter of 2004, mainly due to temporary
difficulties with Tempest's production base at Otter.

The Central area continues to be a major focus for Tempest, contributing
2,509 boe per day or 69 percent of total corporate production. In 2003
flush oil production from the horizontal oil wells came off and 2004
depicted the more sustainable production profile that is characteristic
of these types of wells. The Central area provides year-round access for
exploration and continued development. At year-end 2004, Tempest had
more than 2.0 mmcf per day behind pipe and anticipates being active in
the region in the third and fourth quarters of 2005. This will include
drilling locations that are identified on 212 square kilometres of new
3-D seismic.

For 2004, the Northern area generated significant growth over 2003 with
volumes of 1,115 boe per day versus the prior year's 571 boe per day.
Oil accounted for 294 barrels per day in 2004 (2003 - 121 barrels per
day), while gas was 4.9 mmcf per day (2003 - 2.7 mmcf per day). This
represented a 143 percent and 81 percent growth respectively. Due to the
success of the oil drilling, 2005 will be a transition year for the
Northern area as we shift production to long- life light oil.

Oil and Natural Gas Revenues

Revenues were up 65 percent in 2004 to $55.4 million compared to $33.5
million in 2003. The growth is mainly attributable to a 35 percent
increase in production and a 23 percent increase in commodity prices.
Increased natural gas prices contributed 5 percent to revenue growth
whereas oil prices were up 54 percent from the previous year. In 2004,
the Central area accounted for 69 percent (2003 - 75 percent) of total
revenue. The significant oil price increase reflects the strength of the
benchmark WTI crude oil price which gained 33.3 percent on a
year-over-year basis to average US$41.44. This more than offset the 9
percent increase in the Canadian/U.S. exchange rate which rose to 0.83
from 0.76 year-over-year.

In the fourth quarter of 2004, revenues from crude oil and natural gas
increased 100 percent to $14.6 million, compared to $7.3 million for the
fourth quarter of 2003. The increase was due to a 52 percent production
volume increase and a 57 percent increase in the realized selling price.
Although oil production was 25 percent lower, natural gas was 165
percent higher year-over-year.

For 2005 Tempest anticipates a 25 percent increase in revenues, based on
the strength of oil and natural gas prices and no change in the value of
the Canadian dollar over 2004.

Financial Instruments (Hedging)

Tempest realized a $73,494 gain (2003 - $2,318,114 loss) on hedging in
2004 based on 5,000 GJs from July-December on a floor price of $6.21 per
GJ, the sale of a $7.00 per GJ call and the purchase of an $8.68 per GJ
call (2003 - 800 barrels of oil per day at $25.40 WTI). The gas hedge is
in place until July 2005 and at December 31, 2004 Tempest had an
unrealized mark-to-market gain of $395,166.

Management considers hedging a valuable tool to offset the risk related
to leveraged capital. Tempest will hedge periodically when price
volatility would put its capital program or internal debt guidelines at
risk. Following new accounting guidelines, Tempest has documented the
gas hedge and has demonstrated its effectiveness. Hedge accounting would
be discontinued for any hedging relationships that no longer meet the
requirements of the guideline and mark-to-market with income statement
impacts would be required.

Royalties

Royalty costs as a percentage of sales are trending down as maturing
wells with lower production receive a lower royalty rate. As well, the
average royalty rate reflects a royalty holiday on a portion of
Tempest's Northern oil production. Royalty costs were $11.9 million, or
$8.98 per boe, compared to $7.7 million, or $7.83 per boe in 2003.
Royalty charges were 22 percent of revenue in 2004 compared to 23
percent in 2003. After deducting $500,000 in Alberta Royalty Tax
Credits, the Company had net revenue of $43.4 million in 2004, an
increase of 69 percent from 2003's net revenue of $25.8 million.

In the fourth quarter royalty costs were $2.5 million or $7.39 per boe,
compared to $1.8 million or $7.59 per boe in the fourth quarter of 2003.
Fourth quarter royalties of 17 percent of sales reflect a royalty
holiday status on some Red Earth oil production late in the year.

Tempest's core properties were developed through exploration and are
therefore eligible for Alberta Royalty Tax Credits ("ARTC"). Based on
current commodity prices ARTC is set at 25 percent of Crown royalties
paid to a maximum of $500,000, which was achieved in both 2004 and 2003.
ARTC is maximized early in the year so first-quarter net royalty rates
are below those incurred for the balance of the year when ARTC is no
longer available. Royalty rates for 2004 were as anticipated and Tempest
expects that the corporate royalty rate will remain in the 20-25 percent
range for 2005.



($000s) 2004 2003 % Change
------------------------------------------------------------------------
Oil 4,813 5,475 -12
Gas 7,629 2,741 178
ARTC (500) (500) -
Total 11,942 7,716 55

Per boe ($) 8.98 7.83 15

% of sales 22% 23% -4


Transportation costs

During the year Tempest separated out transportation costs on its income
statement to provide a gross sales number. Transportation costs per unit
of production averaged $1.41 per boe in 2004, compared to $1.73 per boe
in 2003. The decrease is reflective of the Company's production becoming
more gas weighted and the ownership of facilities in our Northern area.
As well, the decrease on a boe basis reflects the stabilized oil
production at Chipman where emulsion hauling has decreased. In the
fourth quarter of 2004 these costs declined to $1.22 per boe (Q4, 2003 -
$1.75). We anticipate transportation costs will be approximately $2.00
per boe in 2005, as a larger portion of gas volumes are derived from our
Central Area where more third-party transportation is utilized.



2004 2003 % Change
------------------------------------------------------------------------
Expenses ($000s) 1,869 1,702 10
Per boe ($) 1.41 1.73 (18)


Operating expenses

Operating costs per unit of production averaged $6.47 per boe in 2004,
compared to $5.66 per boe in 2003. The $8.6 million in operating costs
(2003 - $5.6 million) resulted in operating income of $32.9 million
(2003 - $18.5 million). Tempest had anticipated operating costs closer
to $4.50 per boe in 2004, however, rising operating costs reflect the
higher cost of supplies and field services due to drilling activity. The
Company rented seven compressors in 2004 to accommodate our increased
emphasis on shallow gas wells in Central Alberta.

In the fourth quarter of 2004 operating costs were anomalous at $11.90
per boe (Q4, 2003 - $6.35) reflecting lower production, issues at Otter,
service provider shortages as well as additional costs associated with
colder weather operations. Tempest benefits from its investment in
infrastructure; we have lower operating costs than our peers on a unit
basis. We anticipate operating costs will be $5.50-$6.50 per boe in
2005, as higher volumes offset further cost increases.



2004 2003 % Change
------------------------------------------------------------------------
Expenses ($000s) 8,606 5,573 54
Per boe ($) 6.47 5.66 14


General and Administrative Expenses

General and administrative expenses ("G&A") for 2004 were $1.89 per boe
versus $1.74 in 2003. The net $2.5 million (2003 - $1.7 million) was
after overhead recoveries and capitalization. Management had expected
2004 G&A to remain flat on a boe basis as volume increases offset gross
G&A cost increases. The year-over-year increase reflects bonuses paid in
January 2004. The bonuses amounted to $450,000 compared to $40,000 in
2003. As well, fees associated with the bank syndication and higher
levels of debt were $249,387 compared to $47,813 in bank fees in 2003.
Finally, reserve report costs were significantly higher due to N.I.
51-101 and our mid-year reserves update, totaling $163,925 compared to
$31,843 in the prior year.

Salaries and office rent comprised approximately 61 percent (2003 - 63
percent) of the gross administrative costs. At year-end 2004 Tempest had
employed 13 employees compared to 14 employees at the end of 2003. All
senior staff were paid salaries of $100,000-$140,000 plus bonuses. See
the AIF for additional details regarding executive compensation.

For the fourth quarter net G&A was $1.08 per boe, versus $4.55 in 2003.
The $371,618 (2003 - $1.0 million) variance was largely a result of no
capitalization in the fourth quarter of 2003.

Management expects 2005 G&A expenses to remain flat on a boe basis as
volume increases offset gross G&A cost increases. Tempest has budgeted
higher G&A of $4.9 million for 2005 versus $3.8 million in 2004, with
the additional amount reflecting increased staffing and consulting
levels to accommodate higher levels of activity. Overhead recoveries and
capitalization should be approximately the same as 2004, based on
budgeted capital expenditures for 2005. Tempest continues to closely
monitor and control these costs and expects to maintain net G&A costs of
$1.50-$2.00 per boe produced.



($000s) 2004 2003 % Change
------------------------------------------------------------------------
Gross 3,823 2,726 40
Partner recovery (174) (186) (6)
Capitalized (1,140) (825) 38
Net G&A 2,509 1,715 46

Per boe gross ($) 2.87 2.82 2
Per boe net ($) 1.89 1.79 6


Stock-Based Compensation

The adoption of the fair value method of stock option accounting in the
first quarter of 2004 resulted in income and retained earnings being
restated for 2003 and the recognition of a separate line item expense in
2004. In 2004, and retroactively, Tempest calculates a value for stock
options granted and expenses the corresponding amounts over the option
vesting period. The weighted average estimate of value for the 40,000
options granted in 2004 was $5.00 (2003 - $3.52) per share. (See MD&A
discussion regarding new accounting and regulatory requirements and
notes 2 and 3 in the Notes to the Financial Statements for additional
details).



Number of Average Expense Annual
Options Exercise per Option
Vesting Price ($) Option ($) Expense ($)
------------------------------------------------------------------------
2003 780,822 2.67 2.37 1,850,796
2004 884,707 2.92 2.10 1,856,210
2005 548,333 4.00 2.26 1,238,710
2006 120,000 4.96 0.92 110,375
2007 13,333 6.45 4.32 57,560


This table excludes the 440,000 options granted to date in 2005, which
will have an estimated impact of approximately $175,000 per quarter for
the next three years.

Interest Expense

As expected net interest costs to the Company increased in 2004 with
higher levels of bank debt to $0.95 per boe compared to $0.39 in 2003.
As Tempest grows and continues to be more active, we anticipate using
higher levels of debt and working capital deficiencies. In turn, higher
debt will translate to higher interest expense which we expect will be
$1.00-$1.50 per boe in 2005. The higher interest costs would in turn
reduce earnings.



($000s) 2004 2003 % Change
------------------------------------------------------------------------
On debt 1,184 383 209
On flow-through 78 1 7700
Interest expense 1,262 384 229

Interest income 3 12 (76)
Net interest 1,259 372 238

Per boe ($) 0.95 0.39 144


Depletion and Depreciation

Depreciation and depletion are calculated based upon capital
expenditures, production rates and reserves. Tempest recorded $20.3
million (2003 - $12.4 million) or $15.44 per boe (2003 - $12.72 per boe)
in depletion and depreciation for the year ended December 31, 2004 on
production volumes of 1,329,906 (2003 - 985,045) boe. Costs per each boe
discovered were higher in 2004 than in past years due to increased costs
arising from the tight supply of services in the industry and Tempest's
investment in facilities. Costs include all capital items including
facilities which are constructed by the Company to control operating
costs and expand land positions. Strong commodity prices allow the
Company to develop smaller reserves with lower economic thresholds as
they provide positive net present value to the Company.

Tempest estimates depletion on a quarterly basis throughout the year
using independent inputs such as reserve and land reports when
available. Tempest excludes undeveloped land and seismic and includes
salvage value from the capital base in the calculation. In the fourth
quarter of 2004 these amounts totaled $22.1 million and when combined
with the independent reserves and independent land values, the depletion
was calculated at $17.17 per boe.

For 2004, Tempest anticipates that depletion, depreciation and site
restoration will be $15-$20 per boe, which is in line with new cost
levels we are seeing in the industry.



($000s) Q4/2004 2004 2003 % Change
------------------------------------------------------------------------
Depletion 5,896 20,327 12,420 64
Retirement obligation 60 204 109 86
Total 5,956 20,531 12,569 64

Depletion per boe ($) 17.17 15.28 12.61 21
Retirement obligation ($/boe) 0.17 0.15 0.11 38
Total ($/boe) 17.34 15.44 12.72 21


Asset Retirement Obligations

Tempest adopted the asset retirement obligation method of accounting for
its future abandonment obligations in the first quarter of 2004, which
involved restating prior years. (See MD&A discussion regarding new
accounting and regulatory requirements and notes 2 and 3 in the Notes to
the Consolidated Financial Statements for details). This method records
the present value of estimated clean-up and restoration costs for all of
Tempest's facilities, including well sites and pipelines. The liability
amount is increased each reporting period due the passage of time and
the amount of accretion is charged to earnings in the period. Tempest
expensed $203,745 of accretion in 2004 (2003-$109,262). The result is a
$3.4 million (2003 - $2.1 million) liability on the balance sheet with a
similar increase in capital assets.

Income and Other Taxes

Tempest expended $51.0 million in capital in 2004 (2003 - $47.5 million)
of which $12.0 million had no associated tax pools due to the
flow-through share tax pool renouncements. The balance was comprised of
$11.0 million relating to the September 2003 renouncement and $1.0
million of expenditures related to the $10.0 million December 2004
flow-through. With budgeted expenditures of $40.0-$50.0 million in 2005,
Tempest expects that it will have sufficient tax pools to offset the
related 2004 and 2005 current tax liability. Of the budgeted capital,
$9.0 million will have no associated tax pools as this represents the
unexpended December 31, 2004 balance related to the flow-through share
offering which closed on December 13, 2004. Taxes payable beyond 2005
will become a function of commodity prices, production volumes and
capital expenditures.

Corporations currently pay a 0.0175 percent Large Corporations Tax (LCT)
when their stated capital exceeds $50 million. There was a $120,617
liability in 2004 (2003 - $120,000) and Tempest does not anticipate a
significant change in the amount of this tax for 2005. Tax beyond this
point will be a function of rates and capital employed.

The provision for income taxes differs from the amount obtained by
applying the combined Federal and Provincial income tax rate of 2004 -
38.6 percent (2003 - 40.6 percent) to income before income taxes mainly
due to non-deductible crown charges and resource allowance.



Estimated Tax Pools

($ millions)
------------------------------------------------------------------------
Dec. 31, Dec. 31, Rate of
Type 2004 2003 Claim (%)
------------------------------------------------------------------------
Canadian exploration expense - 2.9 100
Non-capital loss - 4.0 100
Canadian development expense 7.6 6.5 30
UCC 27.4 20.7 20-100
Share issue 2.0 2.3 20
Canadian oil and natural gas property
expense 18.6 11.8 10
-------- --------
Total (1) 55.6 (1) 48.2

(1) This includes tax pool usage required in 2005 to offset $45.5
million (2003 - $20.1 million) of taxable income that is included
for financial statement purposes but delayed one year for tax
purposes. As well, the 2004 number includes the reduction of $1.0
million (2003 -$ 5.0 million) of tax pools renounced under
flow-through.


Earnings

Earnings increased by 331 percent to $4.2 million in 2004 (2003 - $1.0
million) or $0.23 (2003 - $0.06) per basic share. This is after future
income taxes of $2.6 million (2003 - $927,620) and $120,617 in current
taxes related to LCT (2003 - $120,000). The 65 percent increase in
revenues for 2004 was partially offset by the increase in
across-the-board costs, as previously discussed.

For 2005, Tempest anticipates that volume increases and firm commodity
prices will provide positive earnings growth.

Earnings for 2003 were retroactively restated in 2004 to account for the
adoption of the Asset Retirement Obligation change as well as the
adoption of the change to stock-based compensation. (See the Notes to
the Consolidated Financial Statements.)



Fourth Fourth
Quarter Quarter
Ended Ended
Dec. 31, Dec. 31, %
($000s) 2004 2003 2004 2003 Change
------------------------------------------------------------------------
Earnings (loss) ($000s) 531 (1,162) 4,171 967 331

Earnings (loss) ($/boe) 1.55 (5.13) 3.14 0.98 220

Earnings ($/ basic share) 0.03 (0.06) 0.23 0.06 283

Earnings
($/ fully diluted share) 0.03 (0.06) 0.22 0.06 266


Cash Flow

Tempest generated cash flow from operations of $28.8 million, up 77
percent from 2003 cash flow of $16.3 million, of which $6.5 million
(2003 - $2.6 million ) was generated in the fourth quarter. This
increased cash flow translated to $1.55 per basic share, which is 60
percent higher than the previous year. The higher cash flow is
attributable to the 35 percent increase in production volumes and the 23
percent gain in commodity prices.

Based on our projected production of 4,500-5,000 boe per day, Tempest
anticipates 2005 cash flow will be approximately $35.0-$40.0 million or
$1.70-$1.90 per basic share. These projections translate into earnings
before tax of $7.0-$9.0 million or approximately $0.30-$0.40 per basic
share.



Fourth Fourth
Quarter Quarter
Ended Ended
Dec. 31, Dec. 31, %
2004 2003 2004 2003 Change
------------------------------------------------------------------------
Cash flow 6,508 2,641 28,797 16,275 77

Cash flow per Boe 18.95 11.65 21.65 16.52 31

Cash flow per basic Share 0.35 0.14 1.55 0.97 60

Cash flow per fully
diluted Share 0.33 0.14 1.52 0.97 57



Capital Expenditures

------------------------------------------------------------------------
Fourth
Quarter
ended Year ended Year ended Year
December December December 2005
($000s) 31, 2004 31, 2004 31, 2003 Estimated
------------------------------------------------------------------------
Drilling &
completions 6,502 20,956 41% 23,002 49% 22,000
------------------------------------------------------------------------
Equipment &
facilities 2,220 15,804 31% 13,884 29% 10,000
------------------------------------------------------------------------
Land 759 5,374 10% 7,185 15% 8,000
------------------------------------------------------------------------
Acquisitions - 6,000 12% - - -
------------------------------------------------------------------------
Geological &
geophysical 156 2,828 6% 3,428 7% 5,000
------ ------ ---- ------ ---- ----------
------------------------------------------------------------------------
Total capital
expended 9,637 50,962 100% 47,499 100% 40-50,000
------------------------------------------------------------------------


For 2004, Tempest posted finding and development costs on capital spent
of $19.29 per proved plus probable boe, compared to $32.81 in 2003. To
some extent, the results in both years reflect revisions required as a
result of the N.I. 51-101 reserve reporting regulations.



------------------------------------------------------------------------
2004 2003 LTD
------------------------------------------------------------------------
Reserve adds (mboe) 2,544 1,447.5 9,647
------------------------------------------------------------------------
Capital spent ($ millions) 51.0 47.5 163.3
------------------------------------------------------------------------
Tax accrual on acquisition ($ millions) - - 2.4
------------------------------------------------------------------------
Total capital ($ millions) 51.0 47.5 165.7
------------------------------------------------------------------------
F&D cost on capital ($/boe) 19.29 32.81 17.18
------------------------------------------------------------------------


Tempest drilled 39 (32.8 net) wells in 2004 compared to 41 (38.2 net)
wells in 2003 and at December 31, 2004 had gained an additional 38,333
net acres of undeveloped land. Tempest expended $20.6 million in total
capital in the Central area in 2004, comprised of $6.0 million for the
Bon Accord acquisition with the balance allocated to drilling,
completion and tie-in of 19 (18.9 net) wells. In the Northern area,
Tempest expended $19.4 million to finalize construction of the Otter
gathering system and to drill 20 (13.9 net) wells including the
development wells which delineated the Company's Keg River light oil
discovery.

Tempest's 2005 capital program is estimated to be $40.0-$50.0 million of
which $40 million will be funded through cash flow, and the balance from
our banking facility, working capital and equity. The bank provides
development funds based on the Company's proved reserves from successful
exploration and exploitation efforts. The 2005 budget is based on:

- Extensive drilling in the Northern area for light oil in the first
quarter with one or two locations in late summer;

- 20 exploration gas wells in the Central area identified on new 3-D
seismic;

- Five shallow gas wells and five deep gas wells at our West 5 Central
area;

- Three large 3-D seismic programs in the Central area in the first
quarter;

- Completion of the $9.0 million outstanding flow-through obligation, and

- Other exploration.



2004 Drilling Activity
------------------------------------------------------------------------
Exploration Development Total Success % W.I.%
------------------------------------------------------------------------
Gross Net Gross Net Gross Net
------------------------------------------------------------------------
Q1 10.0 9.9 7.0 3.5 17.0 13.4 88 79
------------------------------------------------------------------------
Q2 4.0 4.0 0.0 0.0 4.0 4.0 100 100
------------------------------------------------------------------------
Q3 3.0 2.5 0.0 0.0 3.0 2.5 67 83
------------------------------------------------------------------------
Q4 10.0 9.9 5.0 3.0 15.0 12.9 93 86
----- ---- ---- --- ---- ---- --- ---
------------------------------------------------------------------------
Total 27.0 26.3 12.0 6.5 39.0 32.8 87 84
------------------------------------------------------------------------


When a Company follows the full cost method of accounting as Tempest
does, the cost of all wells, both successful and unsuccessful are added
to the capital base and depleted at the rate of production over the
remaining oil and gas reserves. A ceiling test is then employed to
ensure that the carrying value of capital assets in the financial
statements does not exceed their fair value. For the year ended December
31, 2004 no write-down was required as Tempest's carrying value of
capital assets exceeded the undiscounted estimated future net revenue
from proved reserves.

In the first quarter of 2004, and for all subsequent quarters and
year-end 2004, Tempest applied the new method for calculating the
ceiling test as required by accounting standards. (See MD&A discussion
regarding new accounting and regulatory requirements.) Had the Company
adopted this new method for calculating the ceiling test as required by
accounting standards at December 31, 2003 no impairment would have been
recognized.

Equity

Since January 1, 2005 to the date of the MD&A Tempest has granted
440,000 new stock options at $6.31 to $6.36 and issued 162,335 shares on
the exercise of 162,335 outstanding stock options.

On December 13, 2004 Tempest raised $10.0 million in flow-through
shares, incurring share issue costs of $689,593 issuing 1,162,791 Class
A shares at $8.60 each. The Company renounced tax pools worth $10.0
million (CEE) to the holders of these new flow-through Class A shares
effective December 31, 2004. The Company incurred $986,709 up to
year-end 2004 and has until year-end 2005 to incur the remaining $9.0
million of CEE on appropriate expenditures.

The Company pays interest to the government on funds that remain
unexpended at the end of each month in 2005. Tempest estimates that the
majority of the remaining expenditures will be incurred by the end of
April 2005 leaving very little for accrued interest costs which would be
payable by March 2006. The associated future tax liability entry on the
flow-through shares will be recorded in the first quarter of 2005.

On September 15, 2003 Tempest raised $16.0 million in flow-through
shares, incurring share issue costs of $1.1 million and issuing an
additional 2,285,714 Class A shares at $7.00 each. The Company renounced
tax pools worth $16.0 million (CEE) to the holders of the new Class A
flow-through shares effective December 31, 2003. The Company incurred
$5.0 million up to year-end 2003 and expended the balance of $11.0
million by the end of August 2004, accruing $78,165 of related interest
to the government.

Tempest's Class B shares can be converted at the option of the Company
at any time up to December 31, 2005. If conversion has not occurred by
the close of business on December 31, 2005 the Class B shares become
convertible (at the option of the shareholder) into Class A shares on
the same basis. Effective February 1, 2006 all remaining Class B shares
will automatically be converted to Class A shares.

Tempest's shares were listed on the Venture Stock Exchange on February
9, 2001 and were subsequently listed on the Toronto Stock Exchange on
September 4, 2002 under the symbols TMY.A for the Class A shares and
TMY.B for the Class B shares.



Share Capital
------------------------------------------------------------------------
Class A Shares
------------------------------------------------------------------------
Closing December 31, 2003 17,370,319
------------------------------------------------------------------------
December 13 @ $8.60 flow-through 1,162,791
------------------------------------------------------------------------
Exercise of stock options 527,700
------------------------------------------------------------------------
Closing December 31, 2004 19,060,810
------------------------------------------------------------------------
Exercise of stock options 162,335
------------------------------------------------------------------------
Closing March 4, 2005 19,223,145
------------------------------------------------------------------------
Held by management and directors 11%
------------------------------------------------------------------------

------------------------------------------------------------------------
2004 2003
------------------------------------------------------------------------
Weighted Class A Shares 17,536,445 15,639,092
------------------------------------------------------------------------
Weighted Class B Shares 653,476 653,476
------------------------------------------------------------------------
Conversion of Class B shares 323,319 463,577
------------------------------------------------------------------------
Basic shares outstanding (1) 18,513,240 16,756,145
------------------------------------------------------------------------

------------------------------------------------------------------------
Stock option dilution (treasury method) 411,074 311,277
------------------------------------------------------------------------
Weighted diluted shares outstanding 18,924,314 17,067,422
------------------------------------------------------------------------
(1) For December 31, 2004 the Class B shares are converted at the
year-end Class A share price of $6.69 (2003 - $5.85) and added to
the Class A shares to calculate basic shares outstanding.


During 2004 the Company granted 40,000 Class A stock options at $6.45
per share to employees of the Company, 527,700 stock options were
exercised and 90,000 stock options were cancelled, bringing the total
number of outstanding options at year-end 2004 to 1,499,004, (2003 -
2,076,704). There were 162,335 stock options exercised between January
1, 2005 and March 4, 2005 and an additional 440,000 options granted
during that same period.



2004 Stock Option Activity

------------------------------------------------------------------------
Opening Issued Exercised Cancelled Closing
------------------------------------------------------------------------
2,076,704 40,000 527,700 90,000 1,499,004
------------------------------------------------------------------------
Average Average Average
price price price
of $3.45 of $6.45 of $3.69
------------------------------------------------------------------------
5.5 years 4.8 years
weighted weighted
average average
contractual contractual
life life
------------------------------------------------------------------------


Class A Share Trading Summary
Toronto Stock Exchange - TMY.A
($ except volume)

------------------------------------------------------------------------
2004 High Low Average Volume
------------------------------------------------------------------------
Q1 6.00 5.00 5.61 517,288
------------------------------------------------------------------------
Q2 5.40 4.80 5.13 840,995
------------------------------------------------------------------------
Q3 5.85 4.75 5.40 1,047,952
------------------------------------------------------------------------
Q4 7.19 5.60 6.63 2,073,179
------------------------------------------------------------------------
2004 total 7.19 4.75 5.94 4,479,414
------------------------------------------------------------------------
Year-end closing price 6.69
------------------------------------------------------------------------

------------------------------------------------------------------------
2003 High Low Average Volume
------------------------------------------------------------------------
Q1 5.60 4.80 5.21 1,730,515
------------------------------------------------------------------------
Q2 5.76 4.25 5.07 1,788,220
------------------------------------------------------------------------
Q3 6.13 5.15 5.66 764,398
------------------------------------------------------------------------
Q4 5.90 4.91 5.30 840,446
------------------------------------------------------------------------
2003 total 6.13 4.25 5.26 5,123,579
------------------------------------------------------------------------
Year-end closing price 5.85
------------------------------------------------------------------------

------------------------------------------------------------------------
2002 High Low Average Volume
------------------------------------------------------------------------
Q1 4.20 2.95 3.43 174,864
------------------------------------------------------------------------
Q2 5.00 3.50 4.10 485,010
------------------------------------------------------------------------
Q3 5.00 3.71 4.06 191,239
------------------------------------------------------------------------
Q4 5.90 3.70 4.33 1,437,138
------------------------------------------------------------------------
2002 total 5.90 2.95 4.19 2,288,221
------------------------------------------------------------------------
Year-end closing price 4.75
------------------------------------------------------------------------

------------------------------------------------------------------------
2001
------------------------------------------------------------------------
Q1 - listed Feb. 9, 2001 1.90 0.90 1.61 216,229
------------------------------------------------------------------------
Q2 3.00 1.65 2.38 464,420
------------------------------------------------------------------------
Q3 3.10 2.00 2.58 175,400
------------------------------------------------------------------------
Q4 3.25 2.45 2.77 268,650
------------------------------------------------------------------------
2001 total 3.25 0.90 2.36 1,124,699
------------------------------------------------------------------------
Year-end closing price 2.90
------------------------------------------------------------------------

Related Party and Off Balance Sheet Transactions

Tempest was not involved in any related party or off balance sheet
transactions during the year.

Quarterly Data

2004
Q4 Q3 Q2 Q1
------------------------------------------------------------------------
Production
------------------------------------------------------------------------
Total (boe/d) 3,733 4,001 3,862 2,934
------------------------------------------------------------------------
Oil (bbls/d) 1,284 1,455 1,461 1,353
------------------------------------------------------------------------
Gas (mcf/d) 14,694 15,274 14,409 9,481
------------------------------------------------------------------------
% Oil 34 36 38 46
------------------------------------------------------------------------

Financial
($000s, except per
share data)
------------------------------------------------------------------------
Revenue 14,579 15,365 15,394 10,026
------------------------------------------------------------------------
Earnings (Loss)
before tax 426 2,133 3,352 934
------------------------------------------------------------------------
Earnings Per
before tax share $ 0.02 $ 0.11 $ 0.18 $ 0.05
------------------------------------------------------------------------
Earnings Per
(Loss) diluted
before tax share $ 0.02 $ 0.11 $ 0.18 $ 0.05
------------------------------------------------------------------------
Net Earnings
(Loss) 531 1,058 1,626 955
------------------------------------------------------------------------
Net Earnings Per
(Loss) share $ 0.03 $ 0.06 $ 0.09 $ 0.05
------------------------------------------------------------------------
Net Per
Earnings diluted
(Loss) share $ 0.03 $ 0.06 $ 0.09 $ 0.05
------------------------------------------------------------------------
Cash flow 6,508 8,180 8,763 5,347
------------------------------------------------------------------------
Per
Cash flow share $ 0.35 $ 0.43 $ 0.46 $ 0.28
------------------------------------------------------------------------
Per
diluted
Cash flow share $ 0.33 $ 0.44 $ 0.47 $ 0.29
------------------------------------------------------------------------
Capital spent 9,637 12,933 4,104 24,288
------------------------------------------------------------------------
Basic shares 18,860 18,579 18,730 18,637
------------------------------------------------------------------------
Diluted shares 19,499 18,973 18,999 18,977
------------------------------------------------------------------------


2003
Q4 Q3 Q2 Q1
------------------------------------------------------------------------
Production
------------------------------------------------------------------------
Total (boe/d) 2,464 2,704 2,929 2,721
------------------------------------------------------------------------
Oil (bbls/d) 1,384 1,776 2,003 2,243
------------------------------------------------------------------------
Gas (mcf/d) 6,484 5,566 5,556 2,870
------------------------------------------------------------------------
% Oil 56 66 68 83
------------------------------------------------------------------------

Financial
($000s, except per
share data)
------------------------------------------------------------------------
Revenue 7,287 7,784 8,698 9,704
------------------------------------------------------------------------
Earnings (Loss)
before tax (1,815) 402 441 2,986
------------------------------------------------------------------------
Earnings Per
before tax share $(0.10) $ 0.02 $ 0.03 $ 0.18
------------------------------------------------------------------------
Earnings Per
(Loss) diluted
before tax share $(0.10) $ 0.02 $ 0.03 $ 0.18
------------------------------------------------------------------------
Net Earnings
(Loss) (1,162) 623 (60) 1,566
------------------------------------------------------------------------
Net Earnings Per
(Loss) share $(0.06) $ 0.04 $ - $ 0.10
------------------------------------------------------------------------
Net Per
Earnings diluted
(Loss) share $(0.06) $ 0.04 $ - $ 0.09
------------------------------------------------------------------------
Cash flow 2,641 3,658 3,982 5,994
------------------------------------------------------------------------
Per
Cash flow share $ 0.14 $ 0.22 $ 0.24 $ 0.36
------------------------------------------------------------------------
Per
diluted
Cash flow share $ 0.14 $ 0.22 $ 0.25 $ 0.37
------------------------------------------------------------------------
Capital spent 12,907 11,999 9,358 13,235
------------------------------------------------------------------------
Basic shares 18,417 16,612 16,156 16,166
------------------------------------------------------------------------
Diluted shares 18,713 16,954 16,436 16,494
------------------------------------------------------------------------


The relatively large capital expenditures in Q1, 2004 and the increase
in volumes in Q2, 2004 were as a result of the natural gas development
at Otter.

Risk, Liquidity and Capital Resources

The $1.4 million source of funds in the change in non-cash operating
working capital was due mainly to higher revenues and therefore
increased accounts receivables until those revenues were settled on the
25th day of the following month, as per standard industry practice. The
$1.4 million use of funds in the change in non-cash operating working
capital was due mainly to lower capital expenditures, offset by a
reduction in the number of days that accounts payables were outstanding
in the fourth quarter of 2004 versus the fourth quarter of 2003.

Tempest's business plan has been to grow by exploring for oil and
natural gas. As an exploration company, Tempest's principle risks are
finding and developing economic petroleum reserves efficiently and being
able to fund the capital program. Tempest relies on cash flow, bank debt
and equity markets to fund its capital programs. Tempest anticipates a
$40-$50 million capital program in 2005, with $15-20 million expended in
the first quarter. This will be funded by the $40 million of estimated
cash flow as well as credit facilities and equity if required. Tempest's
credit facility will be reviewed at the end of March and updated based
on the new reserve report prepared by the Company's independent
evaluation engineers. If any components of the business plan are
missing, the Company may not be able to execute the entire business plan.

Tempest mitigates exploration risk by employing a team of highly
qualified and experienced professionals to pursue exploration and
exploitation activities and to carry out and control the capital
spending program. All aspects of exploration projects are reviewed at a
very early stage, including; corporate fit, environmental issues,
timing, costs and reward potential. Identified risks are addressed and
excessive risks are mitigated before any project is approved.

Operational risk is mitigated by having Tempest staff address the
continued development of a new or established reservoir, on a go-forward
basis, using the same careful and calculated manner that is used to
address exploration risk. Reserves are produced based on the amount of
capital employed, production practices and reservoir quality. Tempest
evaluates reservoir development based on timing and amount of additional
capital required and the expected change in production volumes. Finding
and development costs are controlled when capital is employed
cost-effectively.

The financial risks of commodity prices and interest rates are largely
beyond Tempest's control. The Company's approach to managing these risks
is to maintain a prudent level of debt and to employ conservative
forecasting and budgeting projections. As a guideline for monitoring
maximum debt leverage, Tempest uses a 1:1 debt-to-equity ratio or a 1.5x
debt-to-forward cash flow. In order to facilitate the development of
Tempest's reserves, the Company has a $35.0 million extendible
revolving-credit facility and a $5.0 million operating demand facility.
These facilities are with a Canadian chartered banking syndicate. At
December 31, 2004, a balance of $24.1 million had been drawn on this
facility with an effective bank rate of prime plus 130 basis points.
Tempest has a $32.2 million debt and working capital deficiency at the
end of 2004 (2003 - $20.9 million). This represents 28% of capital
relatively unchanged from the 25% of capital in 2003. Tempest
anticipates that these amounts will fluctuate based on cash flow and
exploration and development activities. Tempest is very mindful of the
ongoing liability levels attributed to a working capital deficit.
Tempest uses bank lines to facilitate short-term liquidity management
and has raised equity to reduce debt leverage and stabilize the balance
sheet. Tempest believes that the working capital deficit will continue
to grow as the enterprise becomes larger; however, leverage limits will
be closely monitored on a debt-to-cash flow basis.

Corporate assets are protected through adequate corporate insurance as
well as a proactive approach to all safety and environmental issues.



Sensitivity Analysis

------------------------------------------------------------------------
Estimated Impact in 2005 $ $/Basic Share
------------------------------------------------------------------------
Natural Gas (6:1)
------------------------------------------------------------------------
Change of $0.10Cdn/mcf in average price 299,097 0.01
------------------------------------------------------------------------
Change of 1 mmcf/d production 1,686,177 0.08
------------------------------------------------------------------------
Oil and NGL - WTI
------------------------------------------------------------------------
Change of $1.00/bbl in average price 980,445 0.05
------------------------------------------------------------------------
Change of 100 bbls/d production 1,325,487 0.07
------------------------------------------------------------------------


Critical Accounting Estimates

Proved Oil and Gas Reserves

Under National Instrument 51-101 (N.I. 51-101), "proved" reserves are
those reserves that can be estimated with a high degree of certainty to
be recoverable. (It is likely that the actual remaining quantities
recovered will exceed the estimated proved reserves.) In accordance with
this definition, the level of certainty targeted by the reporting
company should result in at least a 90 percent probability that the
quantities actually recovered will equal or exceed the estimated
reserves. In the case of "probable" reserves, which are obviously less
certain to be recovered than proved reserves, N.I. 51-101 states that it
must be equally likely that the actual remaining quantities recovered
will be greater or less than the sum of the estimated proved plus
probable reserves. With respect to the consideration of certainty, in
order to report reserves as proved plus probable, the reporting company
must believe that there is at least a 50 percent probability that the
quantities actually recovered will equal or exceed the sum of the
estimated proved plus probable reserves. The implementation of N.I.
51-101 has resulted in a more rigorous and uniform standardization of
reserve evaluation.

The oil and gas reserve estimates are made using all available
geological and reservoir data as well as historical production data.
Estimates are reviewed and revised as appropriate. Revisions occur as a
result of changes in prices, costs, fiscal regimes, reservoir
performance or a change in the Company's plans. The effect of changes in
proved oil and gas reserves on the financial results and position of the
Company is described next under depletion expense and impairment of
petroleum and natural gas properties.

Depletion Expense

The Company uses the full cost method of accounting for exploration and
development activities. In accordance with this method of accounting,
all costs associated with exploration and development are capitalized
whether or not the activities funded were successful. The aggregate of
net capitalized costs and estimated future development costs, less
estimated salvage values, is amortized using the unit-of-production
method based on estimated proved oil and gas reserves.

An increase in estimated proved oil and gas reserves would result in a
corresponding reduction in depletion expense. A decrease in estimated
future development costs would result in a corresponding reduction in
depletion expense.

Withheld Costs

Certain costs related to unproved properties may be excluded from costs
subject to depletion until proved reserves have been determined or their
value is impaired. These properties are reviewed quarterly and any
impairment is transferred to the costs being depleted.

Impairment of petroleum and natural gas assets

The Company is required to review the carrying value of all petroleum
and natural gas assets for potential impairment. Impairment is indicated
if the carrying value of the petroleum and natural gas assets are not
recoverable by the future undiscounted cash flows. If impairment is
indicated, the amount by which the carrying value exceeds the estimated
fair value of the property, plant and equipment is charged to earnings.
The assessment of impairment is dependent on estimates of reserves,
production rates, prices, future costs and other relevant assumptions.

Asset Retirement Obligations

The Company is required to provide for future removal and site
restoration costs. The Company must estimate these costs in accordance
with existing laws, contracts or other policies. The fair value of the
liability of $3.4 million (2003 - $2.1 million) for the Corporation's
asset retirement obligation is recorded in the period in which it is
expected to be incurred between 2006 and 2019, discounted to its present
value using the Corporation's 4% credit premium added to the 4%
risk-free interest rate and 2% inflation rate. The offset to the
liability is recorded in the carrying amount of petroleum and natural
gas properties. The liability amount is increased each reporting period
due to the passage of time and the amount of accretion is charged to
earnings in the period. Revisions to the estimated timing of cash flows
or to the original estimated undiscounted cost could also result in an
increase or decrease to the obligation. Actual costs incurred upon
settlement of the retirement obligation are charged against the
obligation to the extent of the liability recorded.

Stock Based Compensation

The Corporation uses the fair value method for valuing stock option
grants. The fair value of each option grant is estimated on the date of
grant using the Black-Scholes option pricing model with the following
weighted average assumptions used for grants in 2004: zero dividend
yield; expected volatility of 103 percent; risk-free rate of 3.92
percent; and expected life of 5 years. The following assumptions were
used in 2003: zero dividend yield; expected volatility of 94 percent;
risk-free rate of 3.6 - 4.2 percent; and expected life of 5 years. The
weighted average fair value of stock options granted during the year was
$5.00 (2003 - $3.52) per option. A zero dividend yield is used as the
Company does not issue dividends, the volatility is a calculation based
on past trading history and the risk free rate is from the Bank of
Canada. An increase in dividends would decrease the option expense and
an increase volatility or the risk free rate would increase the
calculated expense.

Legal, Environmental Remediation and Other Contingent Matters

The Company is required to determine whether a loss is probable based on
judgment and interpretation of laws and regulations and whether the loss
can reasonably be estimated. When the loss is determined, it is charged
to earnings.

The Company's management must continually monitor known and potential
contingent matters and make appropriate provisions by charges to
earnings when warranted by circumstance.

Income Tax Accounting

The determination of the Company's income and other tax liabilities
requires interpretation of complex laws and regulations often involving
multiple jurisdictions. All tax filings are subject to audit and
potential reassessment after the lapse of considerable time.
Accordingly, the actual income tax liability may differ significantly
from that estimated and recorded by management.

New Accounting Standards for 2004

The following new and amended standards impacted Tempest in 2004 as
follows:

Asset Retirement Obligations

Effective January 1, 2004, the Corporation retroactively adopted, with
restatement to prior periods, a new accounting standard relating to
asset retirement obligations, as outlined in Note 2 in the Notes to the
consolidated financial statements. Prior to adopting the standard, the
Corporation recognized a provision for future site restoration costs
over the life of the oil and gas properties and facilities using a unit
of production method. As a result of implementation, the liability on
the balance sheet for future abandonment costs increased to $2.1 million
for 2003 from $0.6 million with the majority of the balance recorded to
property, plant and equipment. The transitional provisions of this
section require that the standard be applied retroactively with
restatement of comparative periods. As a result of the retroactive
application, 2003 comparative numbers have been restated to reflect the
impact of this standard on the 2004 financial statements. See note 6 in
the Notes to the consolidated financial statements for a continuity.

Stock-Based Compensation and Other Stock-Based Payments

Effective January 1, 2004, the Corporation retroactively adopted, with
restatement of prior periods, a new accounting standard relating to
stock-based compensation. As a result of adopting the new accounting
standard, net earnings for the year ended December 31, 2003 decreased by
$1,752,520, a $0.10 impact on basic and diluted earnings per share,
contributed surplus increased by $1,849,137 and share capital increased
$257,243. Opening 2003 retained earnings decreased by $353,860 to
reflect the impact of the 2002 stock-based compensation expense, and
opening 2004 retained earnings decreased by $2,106,380 to reflect the
cumulative impact of 2002 and 2003 stock-based compensation expense. Had
the Company adopted this standard earlier the impact would have been the
same as prior periods have been restated to reflect these changes.

Full Cost Accounting

Effective January 1, 2004, the Corporation adopted the new accounting
standard relating to full cost accounting. The guideline requires that
oil and natural gas assets are evaluated in each reporting period to
determine that the carrying amount in a cost centre is recoverable and
does not exceed the fair value of the properties in the cost centre. The
carrying amounts are assessed to be recoverable when the sum of the
undiscounted cash flows expected from the production of proved reserves,
the lower of cost and market of unproved properties and the cost of
major development projects exceeds the carrying amount of the cost
centre. The adoption of this new policy on January 1, 2004 resulted in
no write-down to the carrying value of petroleum and natural gas
properties. Prior to January 1, 2004 the ceiling test amount was the sum
of the undiscounted cash flows expected from the production of proved
reserves, the lower of cost or market of unproved properties and the
cost of major development projects less estimated future costs for
administration, financing, site restoration and income taxes.

The Corporation could have adopted this method on December 31, 2003 and
had it done so no impairment would have been recognized.

The successful efforts method is the other acceptable method of
accounting. Under the successful efforts method any wells that were
un-successful would be expensed as incurred.

Accounting for Derivative Instruments and Hedging Activities

The Corporation currently accounts for derivatives using hedge
accounting, resulting in unrealized gains or losses on these derivatives
not being recognized on the balance sheet. If the corporation did not
elect for hedge accounting the gain of $395,166 on derivatives would
have been recorded at fair value at the balance sheet date and future
changes in fair value would be recognized in income.



Contractual Obligations

Less than
As at December Total 1 Year 1-3 4-5 After
31, 2004 ($000s) ($000s) Years Years 5 Years
------------------------------------------------------------------------
Additions to property
and equipment
classified as
Canadian Exploration
Expense renounced
to shareholders
under the
flow-through
share program $9,000 $9,000 $- $- $-
------------------------------------------------------------------------
Payments for
office space,
related operating
expenses and taxes 255 255 - - -
------------------------------------------------------------------------
Operating Leases 517 517 - - -
------------------------------------------------------------------------
Obligation to
issue Class A
shares in exchange Up to
for Class B shares 6,535 - 6,535 - -
------------------------------------------------------------------------
In addition, the Company has entered into farm-in agreements in the
normal course of its business.



TEMPEST ENERGY CORP.
Consolidated Balance Sheets

December 31, 2004 and 2003

------------------------------------------------------------------------
2004 2003
------------------------------------------------------------------------

Assets

Current assets:
Accounts receivable $ 6,847,540 $ 4,547,139
Prepaid expenses and deposits 248,617 415,460
-----------------------------------------------------------------------
7,096,157 4,962,599

Petroleum and natural gas properties
(note 4) 116,261,646 84,291,688

------------------------------------------------------------------------
$ 123,357,803 $ 89,254,287
------------------------------------------------------------------------
------------------------------------------------------------------------

Liabilities and Shareholders' Equity

Current liabilities:
Outstanding cheques $ - $ 627,548
Accounts payable and accrued liabilities 15,117,756 15,294,522
Bank debt (note 5) 24,145,439 9,900,000
------------------------------------------------------------------------
39,263,195 25,822,070

Future income taxes (note 8) 19,606,659 17,284,500

Asset retirement obligations (note 6) 3,384,304 2,105,719

Shareholders' equity:
Share capital (note 7) 51,215,640 39,155,972
Contributed surplus (note 7) 2,778,557 1,947,413
Retained earnings 7,109,448 2,938,613
------------------------------------------------------------------------
61,103,645 44,041,998

Commitments (note 9)

------------------------------------------------------------------------
$ 123,357,803 $ 89,254,287
------------------------------------------------------------------------
------------------------------------------------------------------------

See accompanying notes to consolidated financial statements.


Approved on behalf of the Board:

(Signed) A. Scott Dawson Director
-------------------------

(Signed) Harley L. Winger Director
-------------------------


TEMPEST ENERGY CORP.
Consolidated Statements of Operations and Retained Earnings

Years ended December 31, 2004 and 2003

------------------------------------------------------------------------
2004 2003
------------------------------------------------------------------------

Revenues:
Petroleum and natural gas $ 55,363,240 $ 33,473,248
Royalties (net of Alberta Royalty
Tax Credit) (11,942,054) (7,716,219)
------------------------------------------------------------------------
43,421,186 25,757,029

Expenses:
Operating 8,605,734 5,573,468
Transportation 1,869,347 1,702,183
Interest 1,259,299 372,086
General and administrative 2,508,621 1,714,745
Stock-based compensation 1,801,983 1,850,796
Depletion, depreciation and accretion 20,530,750 12,529,135
------------------------------------------------------------------------
36,575,734 23,742,413

------------------------------------------------------------------------
Earnings before income taxes 6,845,452 2,014,616

Income taxes (note 8):
Current 120,617 120,000
Future 2,554,000 927,620
------------------------------------------------------------------------
2,674,617 1,047,620

------------------------------------------------------------------------
Net earnings 4,170,835 966,996

Retained earnings, beginning of year,
as previously reported 4,983,256 2,304,053

Retroactive effect of changes in
accounting policy (note 3) (2,044,643) (332,436)
------------------------------------------------------------------------
Retained earnings, beginning of year,
as restated 2,938,613 1,971,617

------------------------------------------------------------------------
Retained earnings, end of year $ 7,109,448 $ 2,938,613
------------------------------------------------------------------------
------------------------------------------------------------------------

Earnings per share (note 7):
Basic $ 0.23 $ 0.06
Diluted $ 0.22 $ 0.06
------------------------------------------------------------------------
------------------------------------------------------------------------

See accompanying notes to consolidated financial statements.



TEMPEST ENERGY CORP.
Consolidated Statements of Cash Flows

Years ended December 31, 2004 and 2003

------------------------------------------------------------------------
2004 2003
------------------------------------------------------------------------

Cash provided by (used in):

Operations:
Net earnings $ 4,170,835 $ 966,996
Items not involving cash:
Depletion, depreciation and accretion 20,530,750 12,529,135
Future income tax expense 2,554,000 927,620
Stock-based compensation 1,801,983 1,850,796
Reclamation costs (260,367) -
------------------------------------------------------------------------
Funds from operations 28,797,201 16,274,547
Change in non-cash working capital 1,372,044 (520,028)
------------------------------------------------------------------------
30,169,245 15,754,519

Financing:
Issue of Class A shares, net of issue costs 10,856,988 15,449,953
Bank debt 14,245,439 9,900,000
------------------------------------------------------------------------
25,102,427 25,349,953
Investments:
Petroleum and natural gas properties (50,961,756) (47,499,290)
Change in non-cash working capital (3,682,368) 3,599,202
------------------------------------------------------------------------
(54,644,124) (43,900,088)

------------------------------------------------------------------------
Increase (decrease) in cash 627,548 (2,795,616)

Cash (outstanding cheques), beginning of year (627,548) 2,168,068

------------------------------------------------------------------------
Cash (outstanding cheques), end of year $ - $ (627,548)
------------------------------------------------------------------------
------------------------------------------------------------------------

Cash is defined as cash and cash equivalents.

See accompanying notes to consolidated financial statements.


TEMPEST ENERGY CORP.
Notes to Consolidated Financial Statements
Years ended December 31, 2004 and 2003


1. Incorporation:

Tempest Energy Corp. (the "Corporation") is incorporated under the laws
of the Province of Alberta.

2. Significant accounting policies:

(a) Consolidation:

The consolidated financial statements include the accounts of the
Corporation and its wholly owned subsidiaries and a partnership. All
inter-entity transactions and balances have been eliminated.

(b) Petroleum and natural gas properties:

The Corporation's activities are related to acquisition of, exploration
for and development of petroleum and natural gas properties. The
Corporation follows the full cost method of accounting for petroleum and
natural gas operations.

All costs of exploring for and developing petroleum and natural gas
properties and related reserves are capitalized into a cost centre. Such
costs include those related to lease acquisition, geological and
geophysical activities, lease rentals on non-producing properties,
drilling of productive and non-productive wells, tangible production
equipment, asset retirement costs, and that portion of general and
administrative expenses directly attributable to exploration and
development activities. Proceeds received from the disposal of
properties are normally deducted from the full cost pool without
recognition of a gain or loss. When a significant portion of properties
is sold, resulting in a change to the depletion rate of 20% or more, a
gain or loss is recorded and reflected in the statement of operations.

Costs of acquiring unproved properties are initially excluded from the
full cost pool and are assessed yearly to ascertain whether impairment
has occurred. When proved reserves are assigned to the property or the
property is considered to be impaired, the cost of the property or the
amount of impairment is added to the full cost pool. Depletion of
petroleum and natural gas properties and depreciation of production
equipment are calculated using the unit-of-production method based upon
estimated proved reserves, before royalties, as determined by an
independent engineer. For purposes of the calculation, natural gas
reserves and production are converted to equivalent volumes of petroleum
based upon relative energy content.

Petroleum and natural gas properties are evaluated in each reporting
period to determine that the carrying amount in a cost centre is
recoverable and does not exceed the fair value of the properties in the
cost centre.

The carrying amounts are assessed to be recoverable when the sum of the
undiscounted cash flows expected from the production of proved reserves,
the lower of cost and market of unproved properties and the cost of
major development projects exceeds the carrying amount of the cost
centre. When the carrying amount is not assessed to be recoverable, an
impairment loss is recognized to the extent that the carrying amount of
the cost centre exceeds the sum of the discounted cash flows expected
from the production of proved and probable reserves, the lower of cost
and market of unproved properties and the cost of major development
projects of the cost centre. The cash flows are estimated using expected
future product prices and costs and are discounted using a risk-free
interest rate.

A portion of the Corporation's exploration and development activities
are conducted jointly with others and, accordingly, the financial
statements reflect only the Corporation's proportionate interest in such
activities.

(c) Cash and cash equivalents:

Cash and cash equivalents are comprised of cash and all investments that
are highly liquid in nature and generally have a maturity date of three
months or less.

(d) Asset retirement obligations:

The Corporation uses the asset retirement obligation method of recording
the future cost associated with removal, site restoration and asset
retirement costs. The fair value of the liability for the Corporation's
asset retirement obligation is recorded in the period in which it is
incurred, discounted to its present value using the Corporation's credit
adjusted risk-free interest rate and the corresponding amount is
recognized by increasing the carrying amount of petroleum and natural
gas properties. The liability amount is increased each reporting period
due to the passage of time and the amount of accretion is charged to
earnings in the period. Revisions to the estimated timing of cash flows
or to the original estimated undiscounted cost could also result in an
increase or decrease to the obligation. Actual costs incurred upon
settlement of the retirement obligation are charged against the
obligation to the extent of the liability recorded.

(e) Future income taxes:

The Corporation uses the liability method for calculating future income
taxes. Temporary differences arising from the differences between the
tax basis of an asset or liability and the carrying amount on the
balance sheet are used to calculate future income tax assets or
liabilities. Future income tax assets or liabilities are calculated
using the currently enacted, or substantively enacted tax rates
anticipated to apply in the periods that the temporary differences are
expected to reverse.

(f) Flow-through shares:

The resource expenditure deductions for income tax purposes related to
exploratory and development activities funded by flow-through share
arrangements are renounced to investors in accordance with tax
legislation. Future tax liabilities and share capital are adjusted by
the estimated cost of the renounced tax deductions when the expenditures
are renounced.

(g) Stock-based compensation plans:

The Corporation uses the fair value method for valuing stock option
grants. Under this method, compensation cost attributable to all share
options granted is measured at fair value at the grant date and expensed
over the vesting period with a corresponding increase to contributed
surplus. Upon the exercise of the stock options, consideration received
together with the amount previously recognized in contributed surplus is
recorded as an increase to share capital.

The Corporation has not incorporated an estimated forfeiture rate for
stock options that will not vest, rather, the Corporation accounts for
actual forfeitures as they occur.

(h) Revenue recognition:

Petroleum and natural gas revenues are recognized when the title and
risks pass to the purchaser.

(i) Per share amounts:

Basic per share amounts are calculated using the weighted average number
of Class A and Class B common shares outstanding during the year. Class
B common shares are converted to Class A common shares at $10 divided by
the greater of $1 and the Class A market price for the period. Diluted
per share amounts are calculated based on the treasury stock method. The
weighted average number of shares is adjusted for the dilutive effect of
options. The dilutive effect of options uses proceeds received on
exercise of options to purchase Class A shares at the average price
during the period. The weighted average number of shares outstanding is
then adjusted by the net change.

(j) Measurement uncertainty:

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

(k) Financial instruments:

The Corporation uses, from time to time, derivative financial
instruments to manage exposure related to changes in oil and natural gas
commodity prices. They are not used for trading or speculative purposes.

The Corporation formally documents all relationships between hedging
instruments and hedged items, as well as its risk management objective
and strategy for undertaking various hedge transactions. This process
includes linking all derivatives to specific assets and liabilities on
the balances sheet or to specific firm commitments or anticipated
transactions.

The Corporation also formally assesses, both at the hedge's inception
and on a ongoing basis, whether the derivatives that are used in hedging
transactions are highly effective in offsetting changes in fair values
or cash flows of hedged items. For cash flow hedges, effectiveness is
achieved if the changes in the cash flows of the derivative
substantially offset the changes in the cash flows of the hedged
position and the timing of the cash flows is similar. Effectiveness for
fair value hedges is achieved if the fair value of the derivative
substantially offsets changes in the fair value attributable to the
hedged item. In the event that a derivative does not meet the
designation or effectiveness criterion, the gain or loss on the
derivative is recognized in income. If a derivative that qualifies as a
hedge is settled early, the gain or loss at settlement is deferred and
recognized when the gain or loss on the hedged transaction is
recognized. Premiums paid or received with respect to derivatives that
are hedges are deferred and amortized to income over the term of the
hedge.

Realized gains or losses on changes in oil and natural gas commodity
prices are recognized in income in the same period and in the same
financial statement category as the income or expense arising from
corresponding commodity swap contracts (see Note 10).

(l) Comparative figures:

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

3. Changes in accounting policy:

Effective January 1, 2004, the Corporation adopted the new accounting
standard relating to full cost accounting. The adoption of this new
policy on January 1, 2004 resulted in no write-down to the carrying
value of petroleum and natural gas properties. Prior to January 1, 2004
the ceiling test amount was the sum of the undiscounted cash flows
expected from the production of proved reserves, the lower of cost or
market of unproved properties and the cost of major development projects
less estimated future costs for administration, financing, site
restoration and income taxes.

Effective January 1, 2004, the Corporation retroactively adopted, with
restatement to prior periods, a new accounting standard relating to
asset retirement obligations, as outlined in Note 2. Prior to adopting
the standard, the Corporation recognized a provision for future site
restoration costs over the life of the oil and gas properties and
facilities using a unit of production method. The effect of the adoption
is presented below as increases (decreases):



------------------------------------------------------------------------
------------------------------------------------------------------------
Balance Sheets 2003 2002
------------------------------------------------------------------------

Asset retirement costs,
included in petroleum
and natural gas properties $ 1,527,721 $ 1,075,681
Asset retirement obligations 2,105,719 1,159,545
Provision for future site
restoration costs (639,735) (287,277)
------------------------------------------------------------------------
Retained earnings $ 61,737 $ 21,424
------------------------------------------------------------------------
------------------------------------------------------------------------

------------------------------------------------------------------------
------------------------------------------------------------------------
Statement of Operations 2003
------------------------------------------------------------------------
Accretion expense $ 109,262
Depletion and depreciation on asset retirement costs 202,883
Amortization of estimated future
removal and site restoration liability (352,458)
------------------------------------------------------------------------
Net earnings impact $ 40,313
------------------------------------------------------------------------
------------------------------------------------------------------------

Earnings per share - basic $ -
Earnings per share - diluted $ 0.01
------------------------------------------------------------------------
------------------------------------------------------------------------


Effective January 1, 2004, the Corporation retroactively adopted, with
restatement of prior periods, a new accounting standard relating to
stock-based compensation. As a result of adopting the new accounting
standard, net earnings for the year ended December 31, 2003 decreased by
$1,752,520, a $0.10 impact on basic and diluted earnings per share,
contributed surplus increased by $1,849,137 and share capital increased
$257,243. Opening 2003 retained earnings decreased by $353,860 to
reflect the impact of the 2002 stock-based compensation expense, and
opening 2004 retained earnings decreased by $2,106,380 to reflect the
cumulative impact of 2002 and 2003 stock-based compensation expense.



4. Petroleum and natural gas properties:

------------------------------------------------------------------------
------------------------------------------------------------------------
Accumulated Net Book
2004 Cost Depletion Value
------------------------------------------------------------------------
Petroleum and natural
gas properties $ 158,044,274 $ 41,782,628 $ 116,261,646
------------------------------------------------------------------------
------------------------------------------------------------------------
2003
------------------------------------------------------------------------
Petroleum and natural
gas properties $ 105,747,311 $ 21,455,623 $ 84,291,688
------------------------------------------------------------------------
------------------------------------------------------------------------


During 2004, the Corporation capitalized $1,140,370 (2003 - $824,555) of
overhead-related costs to petroleum and natural gas properties.

Costs associated with unproven properties excluded from costs subject to
depletion for 2004 totaled $22,100,000 (2003 - $20,200,000).

The Corporation performed a ceiling test calculation at December 31,
2004 to assess the recoverable value of the property, plant and
equipment and other assets. The oil and gas future prices are based on
the January 1, 2005 commodity price forecast of our independent reserve
evaluators. The following table summarizes the benchmark prices used in
the ceiling test calculation.



------------------------------------------------------------------------
------------------------------------------------------------------------
WTI Foreign WTI Tempest AECO Tempest
Oil Exchange Oil Price Gas Price
($US/bbl) Rate ($Cdn/bbl) Oil ($Cdn/mcf) Gas
------------------------------------------------------------------------
2005 $ 42.00 0.82 $ 51.22 $ 43.90 $ 6.60 $ 6.37
2006 40.00 0.82 48.78 43.08 6.35 6.12
2007 38.00 0.82 46.34 41.59 6.15 5.91
2008 36.00 0.82 43.90 39.42 6.00 5.76
2009 34.00 0.82 41.46 37.18 6.00 5.76
2010 33.00 0.82 40.24 35.95 6.00 5.76
2011 33.00 0.82 40.24 35.81 6.00 5.75
2012 33.00 0.82 40.24 35.74 6.00 5.75
2013 33.50 0.82 40.85 35.95 6.10 5.85
2014 34.00 0.82 41.46 36.49 6.20 5.95
2015 34.50 0.82 42.07 36.67 6.30 6.05
2016 35.19 0.82 42.91 37.22 6.43 6.20
------------------------------------------------------------------------
------------------------------------------------------------------------


5. Bank debt:

The Corporation has a $35,000,000 extendible revolving credit facility
and a $5,000,000 operating demand facility. These facilities are with a
Canadian chartered banking syndicate and bear interest at bank prime
rates adjusted quarterly based on debt to cash flow ratios as defined in
the agreement. The credit facilities are secured by a first fixed and
floating charge debenture in the minimum face amount of $75,000,000 and
a general security agreement. A semi-annual re-determination of the
borrowing base will occur on or before March 31 and November 30 of each
year. Letters of credit amounting to $361,000 are held against the
operating demand facility. As at December 31, 2004, a balance of
$24,145,439 had been drawn on this facility with an effective rate of
5.55% at December 31, 2004.

Interest paid during the year was $1,079,556 (2003 - $390,682).

6. Asset retirement obligations:

The Corporation's asset retirement obligations result from net ownership
interests in petroleum and natural gas assets including well sites,
gathering systems and processing facilities. The Corporation estimates
the total undiscounted amount of cash flows required to settle its asset
retirement obligations is approximately $5,900,000. The majority of the
costs will be incurred between 2006 and 2019. A credit-adjusted risk
free rate of eight percent was used to calculate the fair value of the
asset retirement obligations.

A reconciliation of the asset retirement obligations is provided below:



------------------------------------------------------------------------
------------------------------------------------------------------------
2004 2003
------------------------------------------------------------------------
Balance, beginning of year $ 2,105,719 $ 1,159,545

Accretion expense 203,745 109,262
Liabilities incurred 1,335,207 836,912
Restoration costs (260,367) -
------------------------------------------------------------------------
Balance, end of year $ 3,384,304 $ 2,105,719
------------------------------------------------------------------------
------------------------------------------------------------------------


7. Share capital:

(a) Authorized:

Unlimited number of preferred shares.

Unlimited number of voting Class A shares.

Unlimited number of voting Class B shares, convertible at the option of
the Corporation at any time after December 31, 2003 and before December
31, 2005, into Class A shares. The fraction 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
December 31, 2005, the Class B shares become convertible at the option
of the shareholder into Class A shares on the same basis. Effective
February 1, 2006, all remaining Class B shares will automatically be
converted to Class A shares.



(b) Issued and outstanding:

------------------------------------------------------------------------
Number of
Shares Amount
------------------------------------------------------------------------
Class A shares:
Balance, December 31, 2002 14,737,933 $ 25,476,187
For cash pursuant to flow-through
share offering 2,285,714 15,999,998
Tax effect of flow-through shares - (6,028,799)
Share issue costs - (1,064,910)
Tax effect of the share issue costs - 381,131
For cash on exercise of share options 346,672 514,865
Stock-based compensation - 257,243

------------------------------------------------------------------------
Balance, December 31, 2003 17,370,319 35,535,715
For cash pursuant to flow-through
share offering 1,162,791 10,000,003
Share issue costs - (689,593)
Tax effect of share issue costs 231,841
For cash on exercise of share options 527,700 1,546,578
Stock-based compensation - 970,839

------------------------------------------------------------------------
Balance, December 31, 2004 19,060,810 $ 47,595,383
------------------------------------------------------------------------
------------------------------------------------------------------------

Class B shares:

------------------------------------------------------------------------
Balance, December 31, 2003 and 2004 653,476 $ 3,620,257
------------------------------------------------------------------------
------------------------------------------------------------------------

Total share capital on December 31, 2004 $ 51,215,640
------------------------------------------------------------------------
------------------------------------------------------------------------


(c) Share Option Plan:

Under the Corporation's share option plan it may grant options to its
employees for up to 1,726,749 shares of Class A shares of which 40,000
were granted in 2004. The exercise price of each option equals the
market price of the Corporation's stock on the date of grant and options
have varying terms of 5 to 10 years and vest 1/3 per year over 3 years.



2004 2003
-------------------------------------------
Weighted Weighted
Number average Number average
of exercise of exercise
options price options price
-------------------------------------------

Stock options outstanding,
beginning of year 2,076,704 $ 3.45 2,116,867 $ 2.92
Granted 40,000 6.45 320,000 4.77
Exercised (527,700) 2.93 (346,672) 1.49
Cancelled or expired (90,000) 3.77 (13,491) 3.07
------------------------------------------------------------------------

Stock options outstanding,
end of year 1,499,004 $ 3.69 2,076,704 $ 3.45
------------------------------------------------------------------------
------------------------------------------------------------------------

Exercisable at year-end 817,337 $ 3.25 468,372 $ 3.46
------------------------------------------------------------------------
------------------------------------------------------------------------

The following table summarizes information about the fixed stock
options outstanding at December 31, 2004:

------------------------------------------------------------------------
Options Outstanding Options Exercisable
------------------------------------------------------------------------
Weighted
Weighted average Weighted
Range of average remaining average
Exercise Number exercise contractual Number exercise
Prices outstanding price life (years) exercisable price
------------------------------------------------------------------------

$ 0.40 141,670 $ 0.40 1.0 141,670 $ 0.40
$ 2.86-$2.90 5,000 2.90 2.0 5,000 2.90
$ 3.60-$5.20 1,312,334 3.97 5.2 670,667 3.86
$ 6.45 40,000 6.45 4.9 - -
------------------------------------------------------------------------
1,499,004 $ 3.69 4.8 817,337 $ 3.25
------------------------------------------------------------------------
------------------------------------------------------------------------


(d) Stock-based compensation:

The fair value of each option grant is estimated on the date of grant
using the Black-Scholes option pricing model with the following weighted
average assumptions used for grants in 2004: zero dividend yield;
expected volatility of 103 percent; risk-free rate of 3.92 percent; and
expected life of 5 years. The following assumptions were used in 2003:
zero dividend yield; expected volatility of 94 percent; risk-free rate
of 3.6 - 4.2 percent; and expected life of 5 years. The weighted average
fair value of stock options granted during the year was $5.00 (2003 -
$3.52) per option.



(e) Contributed surplus:

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

Balance, December 31, 2002 $ 353,860
Compensation expense 1,850,796
Exercise of share options (257,243)
------------------------------------------------------------------------
Balance, December 31, 2003 1,947,413
Compensation expense 1,856,210
Exercise of share options (970,839)
Cancellation of share options (54,227)

------------------------------------------------------------------------
Balance, December 31, 2004 $ 2,778,557
------------------------------------------------------------------------
------------------------------------------------------------------------


(f) Per share amounts:

Per share amounts have been calculated using the weighted average number
of shares outstanding. The weighted average shares outstanding for the
year ended December 31, 2004 were 18,513,240 (2003 - 16,756,145).

In computing diluted per share amounts, 411,074 (2003 - 311,277) shares
were added to the weighted average number of shares outstanding during
the year ended December 31, 2004 for the dilutive effect of employee
stock options.

In 2004, options to purchase 40,000 (2003 - 1,169,000) common shares
were not included in the computation because they were anti-dilutive.

8. Income taxes:

The provision for income taxes differs from the amount obtained by
applying the combined Federal and Provincial income tax rate of 2004 -
38.6 percent (2003 - 40.6 percent) to income before income taxes. The
difference relates to the following items:



------------------------------------------------------------------------
2004 2003
------------------------------------------------------------------------

Statutory tax rate 38.6% 40.6%
------------------------------------------------------------------------
------------------------------------------------------------------------

Computed "expected" income tax expense $ 2,642,344 $ 817,934
Non-deductible Crown charges and
other expenses 2,546,187 1,741,171
Resource allowance (2,124,520) (965,372)
Alberta Royalty Tax Credit (147,278) (203,100)
Stock-based compensation 695,926 751,423
Future tax rate reduction (297,510) (1,191,780)
Revisions to tax pools (602,200) -
Other (158,949) (22,656)
------------------------------------------------------------------------
Future income taxes 2,254,000 927,620
Capital tax 120,617 120,000
------------------------------------------------------------------------
$ 2,674,617 $ 1,047,620
------------------------------------------------------------------------
------------------------------------------------------------------------


The components of the net future income tax liability at December 31,
2004 and 2003 are as follows:

------------------------------------------------------------------------
2004 2003
------------------------------------------------------------------------
Future tax liabilities:
Petroleum and natural gas assets $ 24,884,619 $ 19,930,294

Future tax assets:
Asset retirement obligations (1,137,803) (221,476)
Share issue costs (755,816) (836,476)
Non-capital losses (3,384,341) (1,587,842)
------------------------------------------------------------------------
(5,277,960) (2,645,794)

------------------------------------------------------------------------
Future income tax liability $ 19,606,659 $ 17,284,500
------------------------------------------------------------------------
------------------------------------------------------------------------


Non-capital losses of $7,900,000 will expire between 2009 and 2011.

Taxes paid during the year were $196,557 (2003 - $89,276).

9. Commitments:

(a) Pursuant to the flow-through share offering which closed on December
13, 2004, the Corporation issued 1,162,791 Class A common shares for
gross proceeds of $10,000,003. The Corporation renounced $10,000,003 to
Class A shareholders, effective December 31, 2004. The Corporation has
incurred $986,709 to December 31, 2004 and has until December 31, 2005
to expend $9,013,294 on qualified expenditures.

On September 15, 2003, the corporation issued 2,285,714 flow-through
Class A common shares for gross proceeds of $15,999,998. During 2004,
the Corporation incurred the remaining $11,049,855 of eligible
exploration expenditures to satisfy the terms of the flow-through share
offering.



(b) Future minimum lease payments relating to operating lease
commitments on the building are:

------------------------------------------------------------------------
------------------------------------------------------------------------
2005 $ 771,925
------------------------------------------------------------------------
$ 771,925
------------------------------------------------------------------------
------------------------------------------------------------------------


10. Financial instruments:

(a) Commodity price risk management:

In July 2004 the Corporation entered into a natural gas hedging
transaction for 5,000 gigajoules per day for the period August 2004 to
July 2005. This transaction consisted of the purchase of a $6.21 per
gigajoule put and an $8.68 per gigajoule call and the sale of a $7.00
per gigajoule call. The Corporation received net settlement payments of
$73,494 during the year ended December 31, 2004 which are included in
petroleum and natural gas revenues. The Corporation would have received
$395,166 if the hedge had been settled at December 31, 2004.

(b) Foreign currency exchange risk:

The Corporation is exposed to foreign currency fluctuations as crude oil
and natural gas prices received are referenced to U.S. dollar
denominated prices.

(c) Credit risk:

A substantial portion of the Corporation's accounts receivable are with
customers and joint venture partners in the oil and natural gas industry
and are subject to normal industry credit risks. Purchasers of the
Corporation's natural gas, crude oil and natural gas liquids are subject
to an internal credit review to minimize the risk of non-payment.

(d) Interest rate risk:

The Corporation is exposed to interest rate risk to the extent that bank
debt is at a floating rate of interest.

(e) Fair value of financial instruments:

The fair values of accounts receivable, prepaid expenses and deposits
and accounts payable and accrued liabilities approximate their carrying
values due to their short-terms to maturities. The Corporation's bank
debt bears interest at a floating market rate and accordingly the fair
market value approximates the carrying value.

NOT FOR DISTRIBUTION TO UNITED STATES NEWSWIRE SERVICES OR FOR
DISSEMINATION IN THE UNITED STATES.

Reader Advisory

This disclosure contains certain forward looking statements that involve
substantial known and unknown risks and uncertainties, certain of which
are beyond Tempest'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 foreign exchange or interest
rates, stock market volatility and market valuations of companies with
respect to announced transactions and the final valuations thereof, and
obtaining required approvals of regulatory authorities. Tempest's actual
results, performance or achievement could differ materially from those
expressed in, or implied by, these forward looking statements and,
accordingly, no assurances can be given that any of the events
anticipated by the forward looking statements will transpire or occur,
or if any of them do so, what benefits, including the amount of
proceeds, that Tempest will derive there from.

-30-

Contact Information

  • FOR FURTHER INFORMATION PLEASE CONTACT:
    Tempest Energy Corp.
    A. Scott Dawson, P.Eng.
    President and Chief Executive Officer
    (403) 205-3704
    Website: www.tempestenergy.com
    The Toronto Stock Exchange has neither approved nor disapproved of the
    information contained herein.