Crew Energy Inc.

Crew Energy Inc.

March 14, 2005 08:00 ET

Crew Energy Presents 2004 Fourth Quarter and Annual Financial Results


NEWS RELEASE TRANSMITTED BY CCNMatthews

FOR: CREW ENERGY INC.

TSX SYMBOL: CR

MARCH 14, 2005 - 08:00 ET

Crew Energy Presents 2004 Fourth Quarter and Annual
Financial Results

CALGARY, ALBERTA--(CCNMatthews - March 14, 2005) - Crew Energy Inc.
(TSX:CR) of Calgary, Alberta is pleased to announce its operating and
financial results for the three month period and year ended December 31,
2004.

Highlights

- Cash flow in the fourth quarter totalled $8.3 million, a 118% increase
over the fourth quarter of 2003 and a 41% increase over the third
quarter of 2004;

- Net income in the fourth quarter was $3.4 million, a 167% increase
over the fourth quarter of 2003 and 62% greater than the third quarter
of 2004;

- Achieved top tier financial metrics with an earnings to cash flow
ratio of 40%, cash flow to revenue ratio of 65%, general and
administrative expenses per boe of $0.53 and cash flow netbacks of
$29.11 per boe;

- Maintained a strong balance sheet with no bank debt and a $3.8 million
working capital deficiency at year-end;

- Fourth quarter production averaged 3,112 boe/d, an increase of 63%
over the fourth quarter of 2003 and 28% over the third quarter of 2004;

- Maintained low operating costs of $3.98 per boe in the fourth quarter;

- Achieved annual finding and development costs of $8.49 per boe proved
plus probable and $11.56 per boe proved, before including the change in
future development costs and $9.34 per boe proved plus probable and
$12.75 per boe on a proved basis after including the change in future
development costs;

- High netbacks and low finding and development costs resulted in a high
return on capital with recycle ratios of 2.2 times proved reserves and
3.0 times proved plus probable reserves.

- Crew's reserve life index (RLI) increased to 8.2 years, an increase of
3 years or 58% over 2003.



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------------------------------------------------------------------------
Finance Period
Three Three from
months months Year Sept. 2,
ended ended ended 2003 to
($ thousands, except Dec. 31, Dec. 31, % Dec. 31, Dec. 31,
per share amounts) 2004 2003 Chg 2004 2003
------------------------------------------------------------------------
(note 1)
Petroleum and natural gas
sales 12,721 6,086 109 37,702 7,586
Cash flow from operations
(note 2) 8,330 3,814 118 24,076 4,612
Per share - basic 0.33 0.17 94 0.97 0.20
- diluted 0.28 0.15 87 0.84 0.18
Net income 3,358 1,258 167 8,948 1,565
Per share - basic 0.13 0.05 160 0.36 0.07
- diluted 0.11 0.05 120 0.31 0.06

Exploration and development 20,775 4,860 327 55,181 6,689

Working capital deficiency
(surplus) 3,822 (3,940)

Weighted average shares
(thousands)
Basic 26,233 22,981 14 24,946 22,981
Diluted 30,436 25,620 19 28,675 25,734
------------------------------------------------------------------------
------------------------------------------------------------------------

Notes:

(1) Crew was formed on September 2, 2003 as part of the Plan of
Arrangement (the "Plan") entered into by Baytex Energy Ltd.
("Baytex") and its associated companies under which certain
producing properties and exploratory assets of Baytex were
transferred to Crew, with the remaining assets being reorganized
into an income trust, Baytex Energy Trust. Under the Plan, Baytex
Energy Trust became the continuing issuer of Baytex and Crew was
registered as a new issuer. As a result, the financial information
included in this release comprises the operating results of Crew
for the three month periods ended December 31, 2004 and 2003 and
the year ended December 31, 2004 with comparative information for
the 121 day period ended December 31, 2003.

(2) Cash flow from operations is used before changes in non-cash working
capital to analyze operating performance and leverage. Cash flow
does not have a standardized measure prescribed by Canadian
Generally Accepted Accounting Principles and therefore may not be
comparable with the calculations of similar measures for other
companies.

------------------------------------------------------------------------
------------------------------------------------------------------------
Operations Period
Three Three from
months months Year Sept. 2,
ended ended ended 2003 to
Dec. 31, Dec. 31, % Dec. 31, Dec. 31,
2004 2003 Chg 2004 2003
------------------------------------------------------------------------

Daily production
Light oil and ngls (bbl/d) 772 486 59 569 454
Natural gas (mcf/d) 14,041 8,550 64 11,248 8,197
Oil equivalent (boe/d @ 6:1) 3,112 1,911 63 2,444 1,820
Average prices
Light oil and ngls ($/bbl) 53.31 34.46 55 47.47 34.92
Natural gas ($/mcf) 6.91 5.77 20 6.75 5.72
Oil equivalent ($/boe) 44.42 34.61 28 42.15 34.45
Operating expenses
Light oil and ngls ($/bbl) 4.06 3.04 34 3.84 3.39
Natural gas ($/mcf) 0.66 0.84 (21) 0.67 0.85
Oil equivalent ($/boe @ 6:1) 3.98 4.54 (12) 3.96 4.68
Operating netback ($/boe) 29.55 22.62 31 27.57 21.98
G&A and other cash items
($/boe) 0.44 0.93 (53) 0.66 1.05
Cash flow netback ($/boe) 29.11 21.69 34 26.91 20.93

Drilling Activity
Gross wells 16 9 78 39 10
Working interest wells 12.7 5.6 127 32.2 6.6
Success rate, net wells 92% 84% 91% 78%
------------------------------------------------------------------------
------------------------------------------------------------------------


Operational Update

Edson, Alberta

Crew drilled three gas wells at Edson in the fourth quarter and has
plans to drill three additional wells in the first quarter of 2005. The
production capability from this area now exceeds the 7 MMcf/d capacity
of the existing facility. The Company is currently installing another
810 bhp compressor that is expected to be operational by the end of
March, 2005, which will increase the capacity to 14 MMcf/d. Drilling
results from this area have been very encouraging as Crew has
experienced 100% success in the drilling of 10 wells and has encountered
multiple pay zones in 8 wells. The Company plans to drill 12 wells in
this area in 2005 out of a current inventory of 23 drilling locations.

Ferrier, Alberta

Crew was relatively inactive in Ferrier in 2004 drilling one cased gas
well. The Company anticipates increasing its level of activity in this
area in 2005. Currently Crew has plans to drill two development Rock
Creek tests, an Elkton exploration test and a Banff exploration test in
the area. The drilling of these wells is anticipated to occur in the
second and third quarter of 2005. Within the Ferrier area at Phoenix,
Alberta, Crew (58% W.I.) and its partner are constructing a gas plant
which is expected to begin production by the end of March.

Laprise, B.C.

The Company continued to develop its Coplin 45 API light oil play in the
fourth quarter with the drilling of two (1.5 net) oil wells and one (.97
net) gas well. Crew installed a 325 bhp compressor to conserve solution
gas from the two producing oil pools and to accommodate gas from the
fourth quarter gas discovery. Production from this area is now over 650
boe/d which is approximately 50 boe/d more than had been expected. The
Company's 2005 plans for the Coplin pool are to monitor production and
pressure data from existing wells in order to prudently plan further
development of the two oil pools. Crew also plans to acquire additional
3-D seismic data in 2005 over its lands at Laprise to evaluate the
potential of the Slave Point Formation. Crew's acreage is in an
analogous geologic and structural position to a well three miles away
that has had cumulative production of over 17 BCF and is currently
producing over 21 MMcf/d of gas from the Slave Point Formation.

Viking-Kinsella

Crew drilled four (3.6 net) gas wells in the general Viking-Kinsella
area in the fourth quarter. All of these wells are on production at a
rate of 310 boe/d net to Crew. The Company now has fifteen drilling
locations in this area of which one to two will be drilled in the first
quarter of 2005. The Company is also acquiring 3-D seismic over its
lands at Viking-Kinsella to further define additional drilling locations.

Wimborne-Drumheller

Crew drilled three (1.4 net) wells at Wimborne in the fourth quarter
targeting the Belly River, Edmonton sandstones, and Horseshoe Canyon
coal formations. These wells are in various stages of completion and
tie-in and are expected to be on production through the Company's
gathering system and gas processing facility by the end of the first
quarter of 2005. The Company is also expanding its Wimborne gas
processing facility to 7 MMcf/d with the installation of an 810 bhp
compressor to accommodate low pressure gas production from the area.

Crew's lands in the Wimborne area are surrounded by new natural gas
developments targeting the Horseshoe Canyon coals. Typical Horseshoe
Canyon natural gas developments would incorporate the drilling of four
to eight wells per section with production rates of 70-300 mcf/d per
well. Crew has 42 net sections of Horseshoe Canyon coal rights in the
Wimborne-Drumheller area. With no reserves currently booked in the
Horseshoe Canyon coals this play presents a significant resource to the
Company which remains to be realized. The Company also owns and operates
an extensive pipeline infrastructure and two gas processing facilities
in this area.

Exploration

With over 245,000 net undeveloped acres of land and a larger production
and cash flow base, Crew is at a stage in its development where it has
the ability to dedicate more of its resources to exploration drilling.
The Company (100% W.I.) successfully drilled an exploration well at
Inga, British Columbia in the fourth quarter. Crew has 100% interest in
five sections of land on this play and has plans to construct a 6 MMcf
/d gas processing facility with an anticipated production start by the
end of August 2005. The Company has plans to drill up to three wells in
this area in the second or third quarter of 2005.

At Columbia, Alberta Crew has a 40% interest in a cased gas well that
has two prospective zones awaiting completion. At Edson, Crew has a 75%
interest in a well that is currently drilling to an estimated total
depth of 3,100 meters. Although a number of zones may be prospective at
this drilling location the primary target is gas/condensate in the
Winterburn Group. At Hanlan, Alberta, Crew has a 25% interest in a 4,200
meter Winterburn test that is also currently drilling. This well offsets
a recent discovery that is currently producing over 6 MMcf/d from the
Winterburn Group.

At Brazeau, Alberta Crew has over 18 net sections of land and is
currently completing a well (100% W.I.) for gas production in the area.
The Company also plans to drill one (100% W.I.) exploration well in the
third quarter of 2005 and to drill a Nordegg formation test (100% W.I.)
in the Whitehorse area of Alberta in 2005.

Outlook

Crew's large undeveloped land base continues to fuel the Company's
growth through its drilling program. The Company's exploration and
development budget for 2005 is currently set at $60 million. Plans
include the drilling of 40 to 50 wells during the year of which 30 to 40
will be directed toward development initiatives in its core areas of
Edson, Ferrier, Wimborne and Viking-Kinsella in Alberta and Laprise in
northeast British Columbia. In addition, the Company plans to drill a
minimum of 10 exploratory wells in 2005, generally targeting
gas/condensate reservoirs in the deeper regions of the basin.

For the first quarter of 2005 Crew is projecting to spend approximately
$20 million on its exploration and development program. The program
includes the drilling or completion of 15 to 20 wells, the construction
of three natural gas facilities and the installation of the associated
well-site and pipeline infrastructure.

Crew's current production is estimated at 3,900 boe/d, a 25% increase
over the fourth quarter 2004 average of 3,112 boe/d. The Company also
estimates it currently has an additional 900 boe/d awaiting production
start-up which has placed the Company in a position to achieve its
objective of exiting the quarter at over 4,000 boe/d and the year at
over 5,000 boe/d. The Company looks forward to reporting its first
quarter results and updating its shareholders on the progress of the
2005 capital program in May

Land Holdings

One of the "Crew advantages" has been its large prospective undeveloped
land base. During 2004 the Company continued to strategically acquire
additional lands through Crown land sales, freehold mineral leasing and
farm-in arrangements. A summary of the Company's undeveloped land at
December 31, 2004 is outlined below:



------------------------------------------------------------------------
------------------------------------------------------------------------
Developed Undeveloped
Gross Net Gross Net
------------------------------------------------------------------------

Alberta 126,980 58,125 269,723 227,629
British Columbia 4,195 2,748 26,245 18,025
------------------------------------------------------------------------
131,175 60,873 295,968 245,654
------------------------------------------------------------------------
------------------------------------------------------------------------


Oil and Gas Reserves

Information regarding the Company's December 31, 2004 reserves has been
previously distributed in a press release dated March 2, 2005. The
Company's reserves were evaluated for the year ended December 31, 2004
by Gilbert Laustsen Jung Associates Ltd. ("GLJ") in accordance with the
rules provided by National Instrument 51-101. The following table
provides summary information presented in the GLJ report effective to
December 31, 2004 and based on the GLJ (2005-01) price forecast.
Additional reserve information will be presented in the Statement of
Reserve Data and Other Oil and Gas Information section of the Company's
Annual Information Form scheduled to be filed on SEDAR prior to March
31, 2005.



------------------------------------------------------------------------
------------------------------------------------------------------------
Light/medium Natural gas Barrels of oil
oil liquids Natural gas equivalent
------------------------------------------------------------------------
Gross Net Gross Net Gross Net Gross Net
(Mbbl) (Mbbl) (Mbbl) (Mbbl) (MMcf) (MMcf) (Mbbl) (Mbbl)

Proved
Producing 510 439 623 444 23,046 18,587 4,974 3,981
Non-producing 28 25 98 68 5,636 4,343 1,065 817
Undeveloped 0 0 177 121 3,231 2,572 715 549
------------------------------------------------------------------------
Total proved 537 464 899 633 31,913 25,501 6,755 5,347
Probable 138 120 381 266 11,902 9,647 2,502 1,994
------------------------------------------------------------------------
Total proved
& probable 675 584 1,280 899 43,815 35,149 9,257 7,341
------------------------------------------------------------------------
------------------------------------------------------------------------

Notes:

(1) "Gross" reserves means, Crew's working interest (operating and non-
operating) share before deduction of royalties and without including
any royalty interest of the Company.
(2) "Net" reserves means, Crew's working interest (operated and non-
operated) share after deduction of royalties obligations, plus
Crew's royalty interest in reserves.
(3) Oil equivalent amounts have been calculated using a conversion rate
of six thousand cubic feet of natural gas to one barrel of oil.
(4) May not add due to rounding.


The following reconciliation of the Company's gross reserves compares
changes in the Company's reserves as at December 31, 2003 to the
reserves as at December 31, 2004, each evaluated following National
Instrument 51-101(NI51-101) definitions.



------------------------------------------------------------------------
------------------------------------------------------------------------
Proved Total Total Proved
Producing Proved plus Probable
------------------------------------------------------------------------
(MMboe) (MMboe) (MMboe)

Balance December 31, 2003 2.3 2.9 3.7
Technical revisions 0.6 0.5 0.4
Exploration discoveries 0.6 0.6 0.7
Drilling extensions 2.1 3.3 4.9
Improved recoveries 0.3 0.3 0.4
Economic factors - 0.1 0.1
Production (0.9) (0.9) (0.9)
------------------------------------------------------------------------
Balance December 31, 2004 5.0 6.8 9.3
------------------------------------------------------------------------
------------------------------------------------------------------------

Capital Program Efficiency

The efficiency of the Company's capital program for the year ended
December 31, 2004 is summarized below:

------------------------------------------------------------------------
------------------------------------------------------------------------
Proved plus
Proved Probable
------------------------------------------------------------------------

Capital expenditures ($ thousands) 55,181 55,181
Change in future development capital ($ thousands) 5,649 5,559
------------------------------------------------------------------------
Total costs ($ thousands) 60,830 60,740

Reserve additions including revisions (Mboe) 4,772 6,500
------------------------------------------------------------------------
Finding and development costs without change in
future capital ($/boe) $11.56 $ 8.49
Finding and development costs with change in
future capital ($/boe) $12.75 $ 9.34
------------------------------------------------------------------------
------------------------------------------------------------------------


Operating net back ($/boe) 27.57 27.57
Finding and development costs ($/boe) 12.75 9.34
------------------------------------------------------------------------
Recycle ratio 2.2x 3.0x
------------------------------------------------------------------------
------------------------------------------------------------------------


Reserve additions including revisions (Mboe) 4,772 6,500
Total production 2004 (mboe) 894 894
------------------------------------------------------------------------
Reserve replacement 534% 727%
------------------------------------------------------------------------
------------------------------------------------------------------------


Total gross reserves (Mboe) 6,755 9,257
Fourth quarter 2004 production (boe/d) 3,112 3,112
Annual 2004 production (boe/d) 2,444 2,444
------------------------------------------------------------------------
RLI based on fourth quarter annualized
production (years) 6.0 8.2
RLI based on 2004 annual production (years) 7.6 10.4
------------------------------------------------------------------------
------------------------------------------------------------------------


Reserve Values

The before tax estimated future net revenues associated with Crew's
reserves effective December 31, 2004 and based on the GLJ (2005 - 01)
future price forecast and constant dollar pricing are summarized in the
following table:



------------------------------------------------------------------------
------------------------------------------------------------------------
Forecast Price Constant Price
5% 10% 5% 10%
------------------------------------------------------------------------

Proved
Producing 107,815 94,044 118,054 102,172
Non-producing 17,210 14,557 19,811 16,675
Undeveloped 9,395 7,074 11,023 8,352
------------------------------------------------------------------------
Total proved 134,420 115,676 148,887 127,199
Probable 38,931 27,843 43,788 31,568
------------------------------------------------------------------------
Total proved and probable 173,351 143,519 192,675 158,767
------------------------------------------------------------------------
------------------------------------------------------------------------

Notes:

(1) The estimated future net revenues are stated before deducting future
estimated site restoration costs, but include the Alberta Royalty
Tax Credit, and are reduced for estimated future abandonment costs
and estimated capital for future development associated with the
reserves.
(2) Constant pricing assumptions include a base Canadian Light/medium
oil price of $46.54 per bbl, natural gas of $6.54 per mcf,
condensate of $48.91 per bbl, butane of $34.44 per bbl and propane
of $29.81 per bbl.
(3) May not add due to rounding.


Management's Discussion and Analysis

Management's discussion and analysis ("MD&A") is the Company's
explanation of its financial performance for the period covered by the
financial statements along with an analysis of the Company's financial
position. Comments relate to and should be read in conjunction with the
consolidated financial statements of the Company for the three month
periods ended December 31, 2004 and the audited consolidated financial
statements for the year ended December 31, 2004 and the audited and
consolidated financial statements and Management Discussion and Analysis
for the period from September 2, 2003 to December 31, 2003.

As the Company commenced operations effective September 2, 2003,
comparative information for the period ended December 31, 2003 is for
only 121 days. The limitations of such comparative information should be
recognized.

Certain of the statements set forth under "Management's Discussion and
Analysis" and elsewhere in this press release, including statements
which may contain words such as "could", "expect", "believe", "will",
"budgeted", "forecasted" and similar expressions and statements relating
to matters that are not historical facts, are forward-looking and are
based upon the Company's current belief as to the outcome and timing of
such future events. There are numerous risks and uncertainties that can
affect the outcome and timing of such events, including many factors
beyond the control of the Company. These factors include, but are not
limited to, the matters described under the heading "Risk and Risk
Management" in the Company's December 31, 2003 management, discussion
and analysis on Page 21 of the Company's 2003 Annual Report. Should one
or more of these events occur, or should any of the underlying
assumptions prove incorrect, the Company's actual results and plans for
2004 and beyond could differ materially from those expressed in the
forward-looking statements. The Company does not undertake to update,
revise or correct any of the forward-looking information. Such
forward-looking statements should be read in conjunction with the
Company's disclosures under the heading: "CAUTIONARY STATEMENT"
contained in this release.

The consolidated financial statements have been prepared in accordance
with generally accepted accounting principles ("GAAP") in Canada. Barrel
of oil equivalent ("boe") amounts have been calculated using a
conversion rate of six thousand cubic feet of natural gas to one barrel
of oil.

Crew evaluates performance based on net income and cash flow from
operations. Cash flow from operations is a measure not based on GAAP
that is commonly used in the oil and gas industry. It represents cash
generated from operating activities before changes in non-cash working
capital. The Company considers it a key measure as it demonstrates the
ability of the business to generate the cash flow necessary to fund
future growth through capital investment and to repay debt.

Production

Production for the quarter ended December 31, 2004 averaged 3,112 boe/d,
an increase of 63% over the fourth quarter of 2003. Natural gas volumes
grew to 14.0 MMcf/d a 64% increase over the fourth quarter of 2003.
Light oil and natural gas liquids ("ngl") production increased 59% to
772 bbls/d in the fourth quarter compared to 486 bbls/d in the fourth
quarter of 2003.

Production for 2004 averaged 2,444 boe/d, an increase of 34% over the
1,820 boe/d produced in the 121 day period ended December 31, 2003.
Production increased throughout 2004 as a result of the Company's
successful drilling program. Natural gas volumes increased 37% to 11.2
MMcf/d as a result of added production from new wells at Edson, Ferrier
and Viking Kinsella in Alberta. Liquid production increased 25% to 569
bbl/d in 2004 as a result of increased light oil production from Laprise
in northeastern British Columbia and increased ngl production at Edson
and Ferrier.

Revenue

Revenue for the fourth quarter totalled $12.7 million including natural
gas revenue of $8.9 million and light oil and ngl revenue of $3.8
million. These amounts compared to fourth quarter 2003 revenue of $6.1
million including natural gas revenue of $4.6 million and light oil and
natural gas liquids of $1.5 million. The 2004 fourth quarter revenue
increased over the fourth quarter 2003 due to increased production and
higher commodity pricing.

Revenue in 2004 totalled $37.7 million comprised of $27.8 million in
natural gas sales and $9.9 million in oil and ngl sales. Revenue for the
121 day period ended December 31, 2003 totalled $7.6 million. Crew's
revenue grew quarter over quarter throughout 2004 bolstered by
increasing production and strong commodity prices. The Company's oil and
ngl price averaged $47.47 per bbl in 2004 representing an increase of
36% over the $34.92 realized in the 121 day period ended December 31,
2003. Average natural gas prices increased 18% to $6.75 in 2004 compared
to the $5.72 realized during the Company's 2003 period.

Prior to 2004 the Company had presented petroleum and natural gas sales
net of transportation costs. The Company now records petroleum and
natural gas sales separate from transportation costs on the statement of
operations. Previously reported amounts have been reclassified for
comparative purposes.

Royalties

Royalties for the fourth quarter of 2004 totalled $2.7 million or 21.5%
of revenue compared to $1.1 million or 18.5% of revenue for the fourth
quarter of 2003.

Royalties for 2004 totalled $8.5 million in 2004 or 22.5% of revenues.
During the 121 day period ended December 31, 2003 the Company paid
royalties totaling $1.5 million or 19.5% of revenue. Royalty rates as a
percentage of revenue have increased in 2004 due to the addition of
production from new wells which attract higher royalty rates than the
production from the Company's older wells transferred from Baytex.

Operating Costs

Operating costs for the three months ended December 31, 2004 totalled
$1.1 million or $3.98 per boe compared to $0.8 million or $4.54 for the
same period in 2003.

Operating costs totalled $3.5 million in 2004 or $3.96 per boe. During
the 121 day period ended December 31, 2003 the Company incurred total
operating costs of $1.0 million or $4.68 per boe. Operating costs per
unit have decreased in 2004 as a result of higher production offsetting
a larger portion of the Company's fixed operating costs and an increase
in processing fees charged to third parties to recover the Company's
facility operating costs.

Transportation

Transportation costs for the fourth quarter of 2004 were $0.4 million or
$1.35 per boe compared to $0.2 million or $1.06 per boe in the fourth
quarter of 2003.

Transportation costs totalled $1.0 million or $1.17 per boe in 2004.
During the 121 day period in 2003 the Company incurred transportation
costs totaling $0.2 million or $1.06 per boe. Transportation costs per
unit have increased in 2004 due to increased production from Laprise,
which attract higher per unit transportation costs.



Operating Netbacks

------------------------------------------------------------------------
------------------------------------------------------------------------
Three months ended Three months ended
December 31, 2004 December 31, 2003
------------------------------------------------------------------------
Oil and Natural Oil and Natural
Liquids Gas Total Liquids Gas Total
($/bbl) ($/mcf) ($/boe) ($/bbl) ($/mcf) ($/boe)

Revenue $ 53.31 $ 6.91 $ 44.42 $ 34.46 $ 5.77 $ 34.61
Royalties (9.89) (1.83) (10.71) (7.29) (1.02) (6.39)
Alberta royalty
tax credit - - 1.15 - - -
Operating costs (4.06) (0.66) (3.98) (3.04) (0.84) (4.54)
Transportation
costs (2.99) (0.13) (1.33) (1.68) (0.14) (1.06)
------------------------------------------------------------------------
Operating
Net backs $ 36.37 $ 4.29 $ 29.55 $ 22.45 $ 3.77 $ 22.62
------------------------------------------------------------------------
------------------------------------------------------------------------


------------------------------------------------------------------------
------------------------------------------------------------------------
Year ended Period from Sept. 2, 2003
December 31, 2004 to Dec. 31, 2003
------------------------------------------------------------------------
Oil and Natural Oil and Natural
Liquids Gas Total Liquids Gas Total
($/bbl) ($/mcf) ($/boe) ($/bbl) ($/mcf) ($/boe)

Revenue $ 47.47 $ 6.75 $ 42.15 $ 34.92 $ 5.72 $ 34.47
Royalties (8.77) (1.73) (9.99) (7.23) (1.09) (6.73)
Alberta royalty
tax credit - - 0.54 - - -
Operating costs (3.84) (0.67) (3.96) (3.39) (0.85) (4.68)
Transportation
costs (2.31) (0.14) (1.17) (2.51) (0.10) (1.06)
------------------------------------------------------------------------
Operating
Net backs $ 32.55 $ 4.21 $ 27.57 $ 21.79 $ 3.68 $ 21.98
------------------------------------------------------------------------
------------------------------------------------------------------------


General and Administrative

General and administrative expenses for the fourth quarter of 2004
totalled $0.2 million or $0.53 per boe compared to $0.2 million or $1.06
per boe for the fourth quarter of 2003.

General and administrative expenses for the year ended December 31, 2004
totalled $0.8 million or $0.89 per boe and for the period from September
2 to December 31, 2003 totalled $0.3 million or $1.14 per boe. The
Company's general and administrative costs per boe have decreased in
2004 as a result of the Company's increasing production volumes. Crew
follows the full cost method of accounting for its petroleum and natural
gas operations under which, $ 0.8 million (2003 - $0.3 million) of
corporate expenses were capitalized during the year.

Stock-Based Compensation

The Company accounts for its stock-based compensation programs,
including the performance shares and stock options, using the fair value
method. Under this method, compensation expense related to these
programs is recorded in the consolidated statement of operations over
the vesting period. For the three months ended December 31, 2004 the
Company has recorded a stock-based compensation expense totalling
$86,000 or $0.30 per boe compared to $55,500 or $0.31 per boe for the
fourth quarter of 2003.

During 2004 stock-based compensation expense of $0.3 million (2003 -
$0.1 million) was recorded and $0.3 million (2003 - $0.1 million) was
capitalized to the company's full cost pool.

Depletion, depreciation and accretion

The provision for depletion, depreciation and accretion was $3.0 million
or $10.49 per boe for the three months ended December 31, 2004. This
compares to a fourth quarter 2003 provision of $1.5 million or $8.46 per
boe.

The provision for depletion, depreciation and accretion for the year
ended December 31, 2004 was $9.6 million or $10.78 per boe. During the
period from September 2 to December 31, 2003 depletion, depreciation and
accretion was $1.8 million or $7.96/boe. Per unit depletion has
increased in 2004 due to an increase in the average cost of the Company
adding reserves.

Effective January 1, 2004 the Company adopted new Accounting Guideline
16 "Oil and Gas Accounting - Full Cost." Under the new standard the
Company assesses if the carrying amount of petroleum and natural gas
properties is recoverable when compared to undiscounted cash flows
expected from the production of proved reserves, using forecast prices
and costs. When the carrying amount is not assessed as recoverable, an
impairment loss is recognized based on the discounted cash flows
expected from the production of proved plus probable reserves. Adopting
Accounting Guideline 16 had no effect on the Company's financial results.

Cash flow and Net income

Cash flow from operations in the fourth quarter of 2004 grew to $8.3
million, a 118% increase over the fourth quarter of 2003. On a per share
basis, cash flow was $0.33 per basic share and $0.28 per diluted share
compared to $0.17 per basic share and $0.15 per diluted share in the
fourth quarter of 2003. Net income increased to $3.4 million in the
fourth quarter representing a 167% increase over the fourth quarter of
2003. On a per share basis net income was $0.13 per basic share and
$0.11 per diluted share.

Cash flow from operations for the year totalled $24.1 million or $0.97
per basic share and $0.84 per diluted share, while net income totalled
$8.9 million for the year or $0.36 per basic share and $0.31 per diluted
share. These amounts compare to $4.6 million, $0.20 per basic share and
$0.18 per diluted share of cash flow and $1.6 million, $0.07 per basic
share and $0.06 per diluted share of net income earned in the 121 day
period ended December 31, 2003. The Company's increase in cash flow from
operations and net income was the result of increased production from
new wells and higher commodity prices.

Liquidity and Capital Resources

At December 31, 2004 Crew had a net working capital deficiency of $3.9
million including cash and short-term investments of $7.1 million.

The Company currently has a $27 million credit facility with a Canadian
chartered bank. At year-end there were no borrowings against this
facility. The demand operating facility bears interest at the bank's
prime lending rate, bankers' acceptance rates plus scheduled margins and
is allowed to revolve at the Company's discretion.

During 2004 the Company completed two private placements issuing
3,800,000 Common Shares and raising gross proceeds of $24.85 million.
The second of these issues, completed in December 2004, was issued on a
flow-through basis under which the Company has committed to renounce
$8.8 million of certain Canadian tax deductions to the purchasers. The
capital expenditures related to these tax deductions will be incurred
throughout 2005.

Looking forward Crew will continue to focus on maintaining a strong
financial position. The Company is currently planning to fund its 2005
capital expenditure program through a combination of existing bank
lines, proceeds from the expected exercise of existing warrants in
September 2005 and the Company's cash flow from on-going operations.
Emphasis will continue to be placed on the Company's strong financial
position and management will endeavor not to exceed a total debt to
forward cash flow ratio of more than one time.

As at March 10, 2005, 26,780,684 Common Shares and 1,864,000 Class C
Performance shares of the Company were outstanding along with 400,500
options and 3,635,000 warrants to acquire Common Shares of the Company.

Operations and Capital Expenditures

During the fourth quarter the Company drilled a total of 16 (12.7 net)
wells resulting in 13 (10.2 net) natural gas wells, 2 (1. 5 net) oil
wells, and 1 (1.0 net) D&A well. In 2004 Crew drilled a total of 39
(32.2 net) wells resulting in 31 (25.7 net) gas wells, 5 (3.5 net) oil
wells, and 3 (3.0 net) D&A wells representing a success rate of 92% (91%
net). In addition, the Company also continued to follow its strategy of,
where possible, owning and controlling it's processing and gathering
facilities. As a result, in 2004 the Company spent 25% of its total
capital expenditures on the construction of gas processing and
compression equipment at Edson, Ferrier and Laprise as well as adding
extensive gas gathering systems at Edson, Laprise and Viking-Kinsella.

Total exploration and development expenditures for 2004 were $55.2
million compared to $6.7 million for the period from September 2 to
December 31, 2003. The expenditures are detailed below:



------------------------------------------------------------------------
------------------------------------------------------------------------
Three months Year
ended ended
December 31, December 31,
(thousands) 2004 2004
------------------------------------------------------------------------

Land $ 1,661 $ 6,298
Seismic 507 1,812
Drilling and completions 14,222 32,903
Facilities, equipment and pipelines 4,328 13,933
Other 57 235
------------------------------------------------------------------------
Total $20,775 $55,181
------------------------------------------------------------------------
------------------------------------------------------------------------


Dated as of March 10, 2004

Cautionary Statement

This press release contains forward-looking statements relating to
Management's approach to operations, expectations relating to the number
of wells, amount and timing of capital projects, company production,
commodity prices, foreign exchange rates, royalties, operating costs and
cash flow. The reader is cautioned that assumptions used in the
preparation of such information, although considered reasonable by Crew
at the time of preparation, may prove to be incorrect. Actual results
achieved during the forecast period will vary from the information
provided herein as a result of numerous known and unknown risks and
uncertainties and other factors. Such factors include, but are not
limited to: general economic, market and business conditions; industry
capacity; competitive action by other companies; fluctuations in oil and
gas prices; the ability to produce and transport crude oil and natural
gas to markets; the result of exploration and development drilling and
related activities; fluctuation in foreign currency exchange rates; the
imprecision of reserve estimates; the ability of suppliers to meet
commitments; actions by governmental authorities including increases in
taxes; decisions or approvals of administrative tribunals; change in
environmental and other regulations; risks associated with oil and gas
operations; the weather in the Company's areas of operations; and other
factors, many of which are beyond the control of the Company. There is
no representation by Crew that actual results achieved during the
forecast period will be the same in whole or in part as that forecast.

Crew is a junior oil and gas exploration and production company whose
shares are traded on The Toronto Stock Exchange under the trading symbol
"CR".

Financial statements for the three month period and year ended December
31, 2004 are attached.



CREW ENERGY INC.
Consolidated Balance Sheet
(thousands)
------------------------------------------------------------------------
------------------------------------------------------------------------
December 31, 2004 December 31, 2003
------------------------------------------------------------------------

Assets

Current Assets:
Cash and cash equivalent $ 7,069 $ 7,721
Accounts receivable 11,346 5,848
------------------------------------------------------------------------
18,415 13,569

Future income tax asset (note 7) - 2,041
Property, plant and equipment (note 3) 77,123 30,150

------------------------------------------------------------------------
$ 95,538 $ 45,760
------------------------------------------------------------------------
------------------------------------------------------------------------

Liabilities and Shareholders' Equity

Current Liabilities:
Accounts payable and accrued liabilities $ 22,297 $ 9,629

Asset retirement obligations (note 4) 4,984 3,896

Future income tax liability 2,675 -

Shareholders' Equity
Share capital (note 6) 54,382 30,524
Contributed surplus (note 6) 687 146
Retained Earnings 10,513 1,565
------------------------------------------------------------------------
65,582 32,235
------------------------------------------------------------------------
$ 95,538 $ 45,760
------------------------------------------------------------------------
------------------------------------------------------------------------

See accompanying notes to the consolidated financial statements.


CREW ENERGY INC.
Consolidated Statement of Operations and Retained Earnings
(thousands, except per share amounts)
------------------------------------------------------------------------
------------------------------------------------------------------------
Three Three
months months Year Period
ended ended ended Sept. 2 to
December December December December
31, 2004 31, 2003 31, 2004 30, 2004
------------------------------------------------------------------------
(unaudited) (unaudited)

Revenue

Petroleum and natural
gas sales $ 12,721 $ 6,086 $ 37,702 $ 7,586
Royalties (net of Alberta
Royalty Tax Credit) (2,737) (1,124) (8,455) (1,482)
Other revenue 41 39 243 38
------------------------------------------------------------------------
10,025 5,001 29,490 6,142

Expenses

Operating 1,140 798 3,538 1,030
Transportation 385 187 1,042 232
General and administrative 152 188 801 250
Stock-based compensation 86 55 274 73
Depletion, depreciation
and accretion 3,003 1,487 9,641 1,752
------------------------------------------------------------------------
4,766 2,715 15,296 3,337

------------------------------------------------------------------------
Income before taxes 5,259 2,286 14,194 2,805

Taxes (note 7)
Capital 18 14 33 18
Future 1,883 1,014 5,213 1,222
------------------------------------------------------------------------
1,901 1,028 5,246 1,240

------------------------------------------------------------------------
Net income 3,358 1,258 8,948 1,565

Retained earnings,
beginning of period 7,155 307 1,565 -

------------------------------------------------------------------------
Retained earnings,
end of period $ 10,513 $ 1,565 $ 10,513 $ 1,565
------------------------------------------------------------------------
------------------------------------------------------------------------

Per share amounts (note 6(g))
Basic $ 0.13 $ 0.05 0.36 $ 0.07
Diluted $ 0.11 $ 0.05 0.31 $ 0.06
------------------------------------------------------------------------
------------------------------------------------------------------------

See accompanying notes to the consolidated financial statements.


CREW ENERGY INC.
Consolidated Statement of Cash Flows
(unaudited, thousands)

------------------------------------------------------------------------
------------------------------------------------------------------------
Three Three
months months Year Period
ended ended ended Sept. 2 to
December December December December
31, 2004 31, 2003 31, 2004 30, 2004
------------------------------------------------------------------------
(unaudited) (unaudited)

Cash provided by (used in):

Operating activities:
Net income $ 3,358 $ 1,258 $ 8,948 $ 1,565
Items not involving cash:
Depletion, depreciation
& accretion 3,003 1,487 9,641 1,752
Stock-based compensation 86 55 274 73
Future income taxes 1,883 1,014 5,213 1,222
------------------------------------------------------------------------
Funds flow from
operations 8,330 3,814 24,076 4,612

Change in non-cash
working capital (1,180) (2,145) 1,561 (2,807)
Asset retirement
expenditures 1 - (72) -
------------------------------------------------------------------------
7,151 1,669 25,565 1,805

Financing activities:
Issue of common shares 8,800 - 24,850 6,017
Re-purchase of common
shares (74) - (74) -
Share issue costs (537) - (1,421) -
------------------------------------------------------------------------
8,189 - 23,355 6,017

Investing activities:
Exploration and
development (20,775) (4,860) (55,181) (6,689)
Change in non-cash
working capital 5,895 4,795 5,609 6,588
------------------------------------------------------------------------
(14,880) (65) (49,572) (101)

------------------------------------------------------------------------
Change in cash and cash
equivalents 460 1,604 (652) 7,721

Cash and cash equivalents,
beginning of period 6,609 6,117 7,721 -

------------------------------------------------------------------------
Cash and cash equivalents,
end of period $ 7,069 $ 7,721 $ 7,069 $ 7,721
------------------------------------------------------------------------
------------------------------------------------------------------------

See accompanying notes to the consolidated financial statements.


CREW ENERGY INC.
Notes to Consolidated Financial Statements
For the three months and year ended December 31, 2004,
The three months ended December 31, 2003 and
The period from September 2, 2003 to December 31, 2003
(Tabular amounts in thousands)


1. Significant accounting policies:

Crew Energy Inc. ("Crew" or the "Company") was incorporated on May 12,
2003 and commenced operations on September 2, 2003 when certain assets
of Baytex Energy Ltd. ("Baytex") were transferred into Crew under a Plan
of Arrangement. The Plan of Arrangement resulted in the shareholders of
Baytex becoming unit holders of Baytex Energy Trust and shareholders of
Crew.

These consolidated financial statements have been prepared in accordance
with Canadian generally accepted accounting principles within the
framework of the accounting policies summarized below:

(a) Principles of consolidation:

The consolidated financial statements include the accounts of the
Company and its wholly owned subsidiary, Crew Resources Inc. and a
partnership, Crew Energy Partnership.

(b) Cash and cash equivalents:

Cash and cash equivalents include monies on deposit and highly liquid
short-term investments accounted for at cost and having a maturity date
of not more than 90 days.

(c) Petroleum and natural gas properties:

The Company follows the full cost method of accounting for petroleum and
natural gas properties, whereby all costs of exploring for and
developing petroleum and natural gas properties and related reserves are
capitalized. Capitalized costs include land acquisition costs,
geological and geophysical expenses, cost of drilling both productive
and non-productive wells, production facilities, the fair value of asset
retirement obligations and related overhead expenses.

Capitalized costs, excluding costs relating to unproven properties, are
depleted using the unit-of-production method based on estimated proved
reserves of petroleum and natural gas before royalties as determined by
independent petroleum engineers. For purposes of the depletion
calculation, natural gas reserves and production are converted to
equivalent volumes of crude oil based on relative energy content of six
thousand cubic feet of gas to one barrel of oil. Proceeds from the sale
of petroleum and natural gas properties are applied against capitalized
costs, with no gain or loss recognized unless such a sale would alter
depletion by more than 20%.

The cost of acquiring and evaluating unproved properties are initially
excluded from depletion calculations. These unevaluated properties are
assessed periodically for impairment. When proved reserves are assigned
or the property is considered impaired the costs of the property or the
amount of impairment is added to the costs subject to depletion.

Petroleum 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 if 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 forecast
product prices and costs and are discounted using a risk-free interest
rate.

Effective January 1, 2004, the Corporation adopted the new accounting
standard relating to full cost accounting including a new ceiling test.
The adoption of this new policy on January 1, 2004 resulted in no
write-down to the carrying value of petroleum and natural gas assets.
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 cash flows were
estimated using period end prices and costs.

(d) Interest in joint ventures:

A portion of the Company's petroleum and natural gas exploration and
development activity is conducted jointly with others and, accordingly,
the financial statements reflect only the Company's proportionate
interest in such activities.

(e) Asset retirement obligations:

The fair value of the liability for the Company's asset retirement
obligation ("ARO") is recorded in the period in which it is incurred,
discounted to its present value using Crew's credit adjusted risk-free
interest rate and the corresponding amount is recognized by increasing
the carrying amount of the related long-lived asset. The liability is
accreted each period, and the capitalized cost is depreciated over the
useful life of the related asset. Revisions to the estimated timing of
cash flows or to the original estimated undiscounted cost would result
in an increase or decrease to the ARO. Actual costs incurred upon
settlement of the ARO are charged against the ARO.

(f) Revenue recognition:

Revenue from the sale of petroleum and natural gas are recorded when
title passes to a third party.

(g) Financial instruments:

From time to time, Crew may use swap agreements or other financial
instruments to hedge its exposure to fluctuations in petroleum and
natural gas prices. Financial instruments are not used for speculative
purposes. When Crew enters into a hedge it formally assesses, both at
the hedge's inception and on an ongoing basis, whether the derivatives
that are used in the hedging transactions are highly effective in
offsetting changes in fair value or cash flows of the hedged item. These
derivative contracts, accounted for as hedges, are not recognized on the
balance sheet. Realized gains and losses on these contracts are
recognized in petroleum and natural gas sales and cash flows in the same
period in which the revenues associated with the hedged transactions are
recognized. Premiums paid or received are deferred and amortized to
earnings over the term of the contract. Financial instruments that do
not qualify as a hedge are recorded on a mark-to-market basis with the
resulting gains or losses taken into income.

(h) Flow-through shares:

Flow-through shares are issued at a fixed price and the proceeds are
used to fund qualifying exploration expenditures within a defined
period. The expenditures funded by flow-through arrangements are
renounced to investors in accordance with tax legislation. Share capital
is reduced and future tax liability is increased by the total estimated
future income tax costs of the renounced tax deductions in the period of
renouncement.

(i) Per share amounts:

Basic per share amounts are calculated using the weighted average number
of shares outstanding during the period. Diluted per share amounts are
calculated based on the treasury-stock method, which assumes that any
proceeds obtained on exercise of options, warrants and performance
shares would be used to purchase common shares at the average market
price during the period. The weighted average number of shares
outstanding is then adjusted by the net change.

(j) Stock-based compensation plans:

The Company accounts for its stock-based compensation programs including
stock options, warrants and performance shares, using the fair value
method. Under this method, compensation expense related to these
programs is recorded in the consolidated statement of operations over
the vesting period.

(k) Income taxes:

The Company uses the asset and liability method of accounting for future
income taxes. The future tax asset or liability is calculated assuming
the financial assets and liabilities will be settled at their carrying
amount. This amount is compared to the tax assets and the difference is
multiplied by the substantively enacted tax rate when the temporary
differences are expected to reverse.

(l) Use of estimates:

The amounts recorded for depletion of petroleum and natural gas
properties and equipment and the asset retirement obligations are based
on estimates. The ceiling test is based on estimates of proved reserves,
production rates, petroleum 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.

(m) Comparative Information:

Certain comparative amounts have been reclassified to conform to current
period presentation.

2. Plan of Arrangement:

Effective September 2, 2003 and pursuant to a Plan of Arrangement,
Baytex transferred certain property, plant and equipment to Crew. In
exchange, the former Baytex shareholders received 1/3 of a Crew Common
Share for every common share of Baytex held prior to the arrangement.
The number of shares of Crew, which were issued to former Baytex
shareholders as a result of the transaction was 19,345,696. At the time
of the transaction, Crew and Baytex were related companies resulting in
the transfer of the assets and related liabilities to Crew from Baytex
at their carrying value.



Details of the amounts transferred are as follows:

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

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

Allocated:
Petroleum and natural gas properties and equipment $ 24,848
Office furniture and equipment 137
Future income tax asset 3,263
Asset retirement obligation (3,741)

------------------------------------------------------------------------
Net assets transferred and share capital issued $ 24,507
------------------------------------------------------------------------
------------------------------------------------------------------------


In conjunction with the Plan of Arrangement the Company adopted a new
accounting standard, Asset Retirement Obligations. As a result of
adopting this standard, an entry was recorded to increase the asset
retirement obligations by $3,182,000, increase petroleum and natural gas
properties and equipment by $3,741,000, decrease the future income tax
asset by $195,000 and increase share capital by $364,000.



3. Property, plant and equipment:

------------------------------------------------------------------------
Accumulated
depletion & Net
December 31, 2004 Cost depreciation book value
------------------------------------------------------------------------

Petroleum and natural gas
properties and equipment $ 88,054 $ 10,931 $ 77,123
------------------------------------------------------------------------
------------------------------------------------------------------------

------------------------------------------------------------------------
Accumulated
depletion & Net
December 31, 2003 Cost depreciation book value
------------------------------------------------------------------------

Petroleum and natural gas
properties and equipment $ 31,830 $ 1,680 $ 30,150
------------------------------------------------------------------------
------------------------------------------------------------------------


The cost of unproven lands at December 31, 2004 of $10,067,000 (2003 -
$5,530,000) has been excluded from the depletion calculation.

During the year ended December 31, 2004, $1,074,000 (2003 - $323,000) of
corporate expenses related to exploration and development activities
were capitalized.

Crew performed a ceiling test under the rules provided by AcG - 16 as at
December 31, 2004. Based on the calculation, the carrying values are
recoverable as compared to the sum of the undiscounted cash flows of the
proved reserves based on the following benchmark prices.



------------------------------------------------------------------------
------------------------------------------------------------------------
WTI F/X Edmonton Company AECO Company
Oil Rate Oil Liquids Gas Gas
($US/Bbl) ($Cdn/$US) ($/bbl) ($/bbl) ($/mmbtu) ($/mcf)
------------------------------------------------------------------------

2005 $42.00 0.82 $50.25 $41.76 $6.60 $6.47
2006 $40.00 0.82 $47.75 $39.30 $6.35 $6.18
2007 $38.00 0.82 $45.50 $37.11 $6.15 $5.99
2008 $36.00 0.82 $43.25 $34.96 $6.00 $5.84
2009 $34.00 0.82 $40.75 $32.74 $6.00 $5.85
2010 $33.00 0.82 $39.50 $31.61 $6.00 $5.86
2011 $33.00 0.82 $39.50 $31.62 $6.00 $5.86
2012 $33.00 0.82 $39.50 $31.58 $6.00 $5.88
2013 $33.50 0.82 $40.00 $31.95 $6.10 $5.99
2014 $34.00 0.82 $40.75 $32.75 $6.20 $6.12
2015 $34.50 0.82 $41.25 $33.28 $6.30 $6.24
Annual escalation thereafter +2.0%/yr.
------------------------------------------------------------------------
------------------------------------------------------------------------


4. Asset retirement obligations:

The total future asset retirement obligation was determined by
management and was based on Crew's net ownership interest, the estimated
future cost to reclaim and abandon the Company's wells and facilities
and the estimated timing of when the costs will be incurred. Crew has
estimated the net present value of its total asset retirement obligation
as at December 31, 2004 to be $4,984,000 (2003 - $3,896,000) based on a
total future liability of $9,810,000 (2003 - $6,847,000). These payments
are expected to be made over the next 41 years. An 8% (2003 - 10%)
interest rate and 2% (2003 - 2%) inflation rate were used to calculate
the present value of the asset retirement obligation.



The following table reconciles Crew's asset retirement obligations:

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

Carrying amount, beginning of year $ 3,896 $ 3,741
Increase in liabilities during the year 770 83
Accretion expense 390 72
Liabilities settled (72) -

------------------------------------------------------------------------
Carrying amount, end of year $ 4,984 $ 3,896
------------------------------------------------------------------------
------------------------------------------------------------------------


5. Bank facility:

Crew has a $27 million demand operating facility with a Canadian
chartered bank, which is available by way of prime rate based loans or
bankers acceptances. Advances under the facility bear interest at the
bank's prime lending rate, bankers' acceptance rates plus scheduled
margins. The facility revolves at the Company's discretion, is repayable
on demand of the bank and is secured by a first floating charge
debenture over all of Crew's real property and a first priority security
interest in all of Crew's personal property.

Cash interest income received during the year ended December 31, 2004
totalled $178,000 (2003 - $30,000).



6. Share capital:

(a) Authorized:

Unlimited number of Common Shares

1,881,000 Class C non-voting performance shares ("performance shares")

(b) Common Shares:

------------------------------------------------------------------------
------------------------------------------------------------------------
Number of shares Amount
------------------------------------------------------------------------

Issued for cash as private placement 3,635 $ 5,998
Issued on transfer of assets (note 2) 19,346 24,507
------------------------------------------------------------------------
Common shares, December 31, 2003 22,981 30,505
Private placement issued for cash 3,000 16,050
Flow-through shares issued for cash 800 8,800
Exercise of Class C, performance shares 9 6
Buy-back of common shares (9) (74)
Share issue costs, net of tax of $ 497 (924)
------------------------------------------------------------------------
Common shares, December 31, 2004 26,781 $ 54,363
------------------------------------------------------------------------
------------------------------------------------------------------------

(c) Contributed Surplus:

------------------------------------------------------------------------
------------------------------------------------------------------------
Amount
------------------------------------------------------------------------

Stock-based compensation $ 146
------------------------------------------------------------------------
Contributed surplus, December 31, 2003 146
Exercise of Class C, performance shares (6)
Stock-based compensation 547
------------------------------------------------------------------------
Contributed surplus, December 31, 2004 $ 687
------------------------------------------------------------------------
------------------------------------------------------------------------


(d) Private placement:

On September 1, 2003 the Company issued 3,635,000 units for proceeds of
$5,998,000. Each unit consisted of one Class B non-voting share and one
warrant. Each Class B non-voting share was subsequently exchanged for
one Common Share. Total proceeds included the value of the shares and
the warrants.

On May 13, 2004, the Company completed a bought-deal private placement
of 3,000,000 Common Shares at a price of $5.50 per share for gross
proceeds of $16,050,000.

On December 2, 2004, the Company completed a bought-deal private
placement of 800,000 flow-through Common Shares at $11.00 per shares for
gross proceeds of $8,800,000. Under the terms of the sale of the
flow-through shares the Company has committed to renounce to the
purchasers of the flow-through shares certain Canadian tax deductions
totaling $8,800,000.

(e) Warrants:

As at December 31, 2004 and 2003 the Company had 3,635,000 outstanding
warrants entitling the holder to acquire one Common Share of the Company
at a price of $1.65 per share at any time subsequent to September 1,
2005 and prior to September 30, 2005.

(f) Stock-based compensation:

The Company measures compensation costs associated with stock-based
compensation using the fair market value method and the cost is
recognized over the vesting period of the underlying security. The fair
value of each performance share and stock option is determined at each
issue or grant date using the Black-Scholes model with the following
assumptions: risk free interest rate 4.5%, expected life 4 years, and
volatility 45%.

During 2004 the Company recorded $547,000, (2003 - $146,000) of
compensation expense related to the performance shares and stock
options, of which $273,000, (2003 - $73,000) was capitalized in
accordance with the Company's full cost accounting policy.

(i) Performance shares

In conjunction with the private placement of Common Shares, the Company
issued 1,881,000 performance shares to employees, officers and directors
at a price of $0.01 per share. Each performance share is convertible
into a fraction of a Common Share over a three-year period with the
conversion rights expiring on September 1, 2007 after which, if the
shares have not been converted, they are redeemed by the Company at
$0.01 per share. On conversion, each performance share converts at the
rate determined by subtracting $1.65 from the current market price of
the Company's Common Shares and dividing the result by the current
market price of the Company's Common Shares. The fair value of the
performance shares at the date of issue, as calculated by the
Black-Scholes method, was $0.67 per share.



------------------------------------------------------------------------
------------------------------------------------------------------------
Number of shares Amount
------------------------------------------------------------------------

Issued for cash 1,881 $ 19
------------------------------------------------------------------------
Class C, performance shares, December 31, 2003 1,881 19
Converted to Common shares (12) --
------------------------------------------------------------------------
Class C, performance shares, December 31, 2004 1,869 $ 19
------------------------------------------------------------------------
------------------------------------------------------------------------


(ii) Stock options

The Company has a fixed stock option plan in which the Company may grant
options to its employees and directors for up to 417,000 Common Shares.
Under this plan, the exercise price of each option equals the market
price of the Company's Common Shares on the date of grant. All granted
options vest over a three-year period and have a four-year term. Stock
options are granted periodically throughout the year. The fair value of
the stock options granted during the year as calculated by the
Black-Scholes method was $2.79 (2003 - $1.50) per option.



------------------------------------------------------------------------
------------------------------------------------------------------------
Number of Weighted average
Options Price Range exercise price
------------------------------------------------------------------------

Granted 156 $3.50 to $3.75 $ 3.70
------------------------------------------------------------------------
Balance, December 31, 2003 156 $3.50 to $3.75 3.70
Granted 328 $4.70 to $7.90 6.84
Cancelled 120 $3.75 3.75
------------------------------------------------------------------------
Balance December 31, 2004 364 $3.50 to $7.90 $ 6.51
------------------------------------------------------------------------
------------------------------------------------------------------------

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

------------------------------------------------------------------------
------------------------------------------------------------------------
Outstanding Weighted Weighted Exercisable Weighted
at average average at average
December 31, remaining exercise December 31, exercise
2004 life price 2004 price
------------------------------------------------------------------------
(years)

$3.50 to $5.50 43 2.92 $3.79 12 $3.52
$5.50 to $7.50 276 3.75 $6.72 - -
$7.50 to $7.90 45 3.88 $7.90 - -
------------------------------------------------------------------------
364 3.67 $6.51 12 $3.52
------------------------------------------------------------------------
------------------------------------------------------------------------


(g) Per share amounts:

Per share amounts have been calculated on the weighted average number of
shares outstanding. The weighted average shares outstanding for the
period ended December 31, 2004 was 24,946,000 (December 31, 2003 -
22,981,000).

In computing diluted earnings per share for the period ended December
31, 2004, 3,729,000 (December 31, 2003 - 2,753,000) shares were added to
the weighted average number of common shares outstanding for the
dilution added by the warrants, performance shares and stock options.

7. Income taxes:

(a) Income tax provision:

The provision for income taxes in the financial statements differs from
the result which would have been obtained by applying the combined
federal and provincial tax rate to the Company's earnings before income
taxes. This difference results from the following items:



------------------------------------------------------------------------
------------------------------------------------------------------------
2004 2003
------------------------------------------------------------------------
Earnings before income taxes $ 14,194 $ 2,805
------------------------------------------------------------------------

Combined federal and provincial tax rate 38.73% 40.90%

Computed "expected" income tax expense $ 5,497 $ 1,148

Increase (decrease) in income taxes resulting from:
Non-deductible crown charges 2,044 420
Resource allowance (1,794) (400)
Non-taxable provincial royalty credits (ARTC) (139) -
Attributed Canadian royalty income (124) -
Stock-based compensation 213 60
Benefits relating to change in income tax rates (307) (35)
Other (177) 29
------------------------------------------------------------------------
Future income taxes 5,213 1,222

Capital taxes 33 18
------------------------------------------------------------------------
Income taxes $ 5,246 $ 1,240
------------------------------------------------------------------------
------------------------------------------------------------------------

Cash taxes paid during the period were nil.

(b) Future income tax:

The components of the Company's future income tax liability/asset are
as follows:

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

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

Future income tax:
Property, plant and equipment $ 4,868 $ (101)
Asset retirement obligation (1,668) (1,360)
Share issue costs (401) 0
Other (124) -
Non-capital loss - (580)
------------------------------------------------------------------------
Future income tax liability (asset) $ 2,675 $(2,041)
------------------------------------------------------------------------
------------------------------------------------------------------------


8. Financial instruments:

(a) Commodity price risk management:

At December 31, 2004, the Company had no fixed price contracts or
financial instruments associated with future production.

(b) Foreign currency exchange risk:

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

(c) Credit Risk

Crew's accounts receivable are with customers and joint venture partners
in the petroleum and natural gas business and are subject to normal
credit risks. Concentration of credit risk is mitigated by marketing
production to several purchasers under normal industry sale and payment
terms. Crew routinely assesses the financial strength of its customers.
Crew may be exposed to certain losses in the event of non-performance by
counterparties to commodity price contracts. Crew attempts to mitigate
this risk by entering into transactions with highly rated major
financial institutions.

(d) Fair value of financial instruments

The fair values of the financial instruments on the Company's balance
sheet approximate their carrying values due to their short term to
maturity.

-30-

Contact Information

  • FOR FURTHER INFORMATION PLEASE CONTACT:
    Crew Energy Inc.
    Dale Shwed
    President and C.E.O.
    (403) 231-8850
    or
    Crew Energy Inc.
    John Leach
    Vice President, Finance and C.F.O.
    (403) 231-8859
    Website: www.crewenergy.com