Duvernay Oil Corp.

Duvernay Oil Corp.

March 17, 2005 18:00 ET

Duvernay Enjoys Record 2004 Annual Production and Financial Results


NEWS RELEASE TRANSMITTED BY CCNMatthews

FOR: DUVERNAY OIL CORP.

TSX SYMBOL: DDV

MARCH 17, 2005 - 18:00 ET

Duvernay Enjoys Record 2004 Annual Production and
Financial Results

CALGARY, ALBERTA--(CCNMatthews - March 17, 2005) - Duvernay Oil Corp.
(TSX:DDV) is pleased to report record fourth quarter and 12 month 2004
results and provide an operational update on activities.

2004 Highlights

- Record cash flow of $59.7 million, an increase of 134% over 2003; the
per share diluted cash flow of $1.41 represents a 76% increase over 2003.

- Record after tax earnings of $20.3 million, a 154% increase over 2003
earnings of $8.0 million, on a per share basis, diluted earnings
increased by 92%.

- Record production volumes of 6,136 boe/d an increase of 91% over 2003.

- Top quartile operating netbacks of $28.30 per boe for full year 2004
and $30.89 per boe for Q4 2004.

- Reserve replacement of 584% in 2004 with very strong RLI of 16.0 years.

- Operating costs in 2004 were $5.37/boe, a 25% decrease from 2003
operating costs of $7.16/boe.

- Strong balance sheet with net debt to trailing cash flow of 0.9 and
net debt to prospective cash flow of 0.5.

- Record drilling success with 77 gross wells drilled with a 94% success
rate.

- Strong proved plus probable FD&A full cycle costs since inception of
$10.04/boe excluding future capital.

2005 Highlights

- Duvernay is increasing full year production guidance for 2005 from
10,500boe/d to between 11,000 and 11,500 boe/d.

- Duvernay has received Good Production Practice approval for the
Wildhay Rock Creek pool.

- Duvernay is increasing the projected 2005 drilling totals from 80 to
105 wells and increasing the 2005 capital program from $140 to $180
million.

- Successful Exploration wells at Pembina and Dawson.

- 25 new gas wells drilled thus far in 2005 with particularly strong
test results from the Alberta Deep Basin area.

2004 Financial Results

Duvernay delivered record 2004 financial results in all categories.
Earnings for the year totaled $20.3 million up 153% from 2003 or $0.48
per diluted equity share. Cash flow showed similar growth to $59.7
million ($1.41/share) an increase of 134%. The majority of this increase
can be attributed to growth in production volumes averaging 6,136 boe/d,
a 91% increase year over year. Coupled with the strong production
volumes, unit economics improved substantially as operating netback
averaged $28.30 per boe in 2004 up 19% from 2003. The drivers providing
this performance uplift were; reduced lease operating expenses averaging
$5.37/boe, full year effective royalty rates of 19% ($8.02/boe), and
stronger product prices averaging $41.69/boe.

Duvernay finished 2004 with an exceptionally strong balance sheet with
net debt $54.2 million or debt to prospective cash flow of 0.5 times.
The Company invested $179.7 million in its capital program, $132 million
of which was dedicated to exploration and development drilling (yielding
15.2 mmboe of new reserves), $19.2 million to expand the undeveloped
land base by 60,000 net acres, and $26.8 million to facilities and
infrastructure in the gas prone Deep Basin of Alberta and the Sunset
Groundbirch area of NEBC. The large upfront investments in both land and
facilities will position Duvernay for strong production growth in 2005
and beyond. Duvernay accelerated drilling and completion programs in the
fourth quarter of 2004 leading to an increase in capital expenditures.
The strong results from this accelerated program are contributing to the
increased guidance for 2005.

Production Results and 2005 Outlook

The 2004 average production level of 6,136 boe/d was a record and a 91%
increase over 2003 production of 3,225 boe/d. On a per share basis,
production increased by 43 %. The 2004 production average was also 636
boe/d above the original 2004 average projection of 5,500 boe/d.

2005 drilling and production test results have been ahead of expectation
in the first quarter. Significant production growth will be realized
during the next four weeks as the major facilities projects at Cecilia
and Sunset are completed. The Company expects production levels to reach
between 11,000 and 11,500 boe/d by the second half of April, assuming
these facility projects are completed on schedule. Completion and
start-up of the 100% Duvernay Cecilia plant will eliminate further
shut-ins of Duvernay gas at facilities in the Deep Basin area in which
Duvernay has no working interest. Such shut-ins have reduced first
quarter production volumes thus far by approximately 900 boe/d. The
Spirit River facilities project, originally planned for an early April
start-up, will be completed late in the second quarter as wet conditions
are currently limiting access. This project is expected to add
approximately 1,000 boe/d when completed.

Duvernay has very large inventories of lower risk development wells in
its two main gas project areas at Sunset-Groundbirch and Wild River-Fir.
Now that the Company has control of its gas infrastructure in both
areas, the pace of activity can be increased with the assurance that
Duvernay gas volumes have continuous access to sales systems. The
Company has decided to more aggressively pursue these inventories after
break-up in 2005, and plans to drill between 60 and 70 development wells
in these areas during the remainder of 2005.

The better than projected first quarter drilling results and the
accelerated EP program results in an increased forecast average
production for the year from 10,500 boe/d to between 11,000 and 11,500
boe/d. The more aggressive development drilling program is expected to
yield a 2005 exit production volume of between 15,000 and 16,000 boe/d.
The production volume outlook does not include potential volumes from
future exploration successes during the year. The corresponding 2005
cash flow per share with the increased production levels is $2.59/share.

Drilling Overview

Duvernay operated and participated in a total of 77 wells in 2004, with
a 94% success rate. The Company has drilled a further 25 wells thus far
in 2005. Duvernay plans to continue to operate between eight and nine
triple rigs for the balance of the year, after the spring break-up
period. A minimum total of 105 wells are now planned for 2005, the
Company has the inventory and financial capability to increase this new
location total.

Reserve Overview

Duvernay had strong reserve growth in all categories again in 2004.
Proved producing reserves were increased by 43%, total proved reserves
grew by 30% in 2004 and proved plus probable reserves increased by 44%
during the year. A further 2.8 mmboe of reserves have been converted to
proved producing reserves thus far in the first quarter of 2005. Proven
plus probable reserve replacement was 584% in 2004. Proved reserve life
index is now 10.9 years at end 2004 and the proved plus probable reserve
life index is 16 years at year end 2004. Finding and development costs
were $11.91/boe for proved and probable reserves in 2004 and $17.83/boe
for proved reserves, before future capital and revisions. The proved and
probable costs were $13.70/boe including revisions. The three year
average finding and development costs are $10.04/boe for proved and
probable reserves excluding future capital.

Finding and development costs were higher in 2004 primarily due to lower
than anticipated initial independent reserve recognition for the
Company's highly successful Alberta Deep Basin drilling program. Average
initial reserve bookings for Duvernay's new wells in 2004 in the Deep
Basin are 1.25 bcf proved and 1.56 bcf proved plus probable, primarily
for single zone Cretaceous Cadomin Formation Wells. Analogous wells with
two productive zones and longer production histories in adjacent Deep
Basin areas will typically produce between 3.0 and 4.0 bcf. The vast
majority of the Duvernay wells in the Deep Basin are less than 2.0 years
old. These wells with limited production histories are not recognized
with full reserves, and in particular proven reserves, under the new
guidelines until longer term production performance is established. The
majority of Duvernay's Deep Basin gas wells also have at least two
productive horizons, however most have only been completed in one zone
thus far; zones not completed by year end are generally not recognized
with year-end reserves under the NI51-101 guidelines. Duvernay expects
per well reserve increases in future years for existing booked Cadomin
wells assuming the observed initial strong production performance
continues and as the uphole zones above the Cadomin are systematically
completed, recognized, and brought on stream. Duvernay also had 11 wells
out of a total of 77 wells drilled and cased in 2004 as productive but
not production tested prior to year-end. These wells were not recognized
with reserves in the 2004 report increasing overall 2004 Finding and
Development costs. Eight of these wells have now been successfully
completed during the first quarter of 2005, with the remaining three yet
to be tested. Approximately 67% of the total 2004 capital expenditures
were directed into the Wild River-Fir/Deep Basin operating area.

The projected mid to late April total corporate production rate of
11,500 boe/d is already essentially at the forecast total proved plus
probable production rate of 11,608 boe/d in the 2004 GLJ report.

2005 Operating Complex Update

Sunset-Groundbirch

Exploration and development of the Triassic Doig gas trend continued in
the first quarter of 2005 with 5 additional gas wells drilled. The total
number of the wells in the pool is 29 with 23 on production. The first
phase of the Sunset plant upgrade will be completed in early April,
adding an additional 4.0 mmcf/d of Doig gas processing capacity. The
second phase of this expansion will be completed by July 1, bringing
total Doig production in the central portion of the pool to between 20
and 25 mmcf/d. At Sundown, Duvernay now has interests in six Doig gas
wells and has the critical mass to embark upon a gas processing facility
in that area. This facility is scheduled for a third quarter 2005
start-up and will process an additional 10 mmcf/d of Doig gas volumes.
The Company acquired a large 3D seismic survey in the
Groundbirch-Saturn-Worth portion of the 50 mile long gas pool. This data
will be utilized to optimize initial production rate from new wells
drilled during the balance of 2005. It is anticipated that successful
drilling on the northern end of the trend will lead to construction of a
fourth gas plant in the North Saturn-Worth area early in 2006. Duvernay
was particularly encouraged with strong test results from several
step-out and exploration wells along the trend. The Saturn-Worth
16-4-80-19W6 exploration test, drilled in March 2004, production tested
natural gas at rates of 2.6 mmcf/d from the Doig in February. This 2004
well was not assigned reserves in the 2004 GLJ report as it was not
production tested until February. The South Groundbirch 14-22-78-19W6
step-out tested at rates of up to 5.0 mmcf/d during February 2005 and
will be brought on-stream through the Sunset 5-3 plant expansion.

Wild River - Fir/Deep Basin

Duvernay had an outstanding year in 2004 in the Company's Alberta Deep
Basin operating area. The Company drilled a total of 42 new gas wells
during the year and has drilled an additional 13 new gas wells thus far
in 2005. Production has recently been increased to 5,500 boe/d (800 bpd,
28 mmcf/d gas), and the Company expects to reach the 50 mmcf/d net gas
production milestone from the area during the third quarter of this
year. Of the 55 new 2004/2005 wells, 45 are productive in the Cadomin
and the majority have two or more uphole productive Cretaceous horizons.
A total of 16 wells remain to be tied in, approximately 12 are expected
on stream by early April. Of particular note is the rapid delineation of
the Wroe-Berland western Cadomin pool extension where Duvernay now has
interests in 16 new gas wells. With further drilling and plant
expansion, production could reach 25 mmcf/d from Wroe Creek alone by
year-end. Average initial production rates in 2004 for the Cadomin
Formation were above 2003 rates and statistical averages for the general
area of 1.5 mmcf/d. The 8-12-57-25W5 well tested at 3.9 mmcf/d, the
14-2-57-25W5 well tested at 7.0 mmcf/d, the 14-7-57-25W5 well tested at
2.1 mmcf/d, the 9-36-58-27W5 well tested at 4.4 mmcf/d, the 2-31-57-24W5
well tested at 4.9 mmcf/d and the 10-2-58-24W5 well tested at 2.2
mmcf/d. Continued strong performance from these wells will likely lead
to per well-bore reserve increases above initial recognition at year end
2004. Duvernay expects to drill a total of 60 to 70 wells in the Deep
Basin during 2005, from an inventory of over 250 locations. Included in
this 2005 program will be five deep Devonian new pool Exploration
wildcats. These deep Devonian tests have per prospect reserve targets
between 10 and 150 bcf.

Duvernay has experienced occasional production shut-ins at various
plants in the greater Deep Basin area as, apart from the Duvernay
Wildhay facility, the Company is not currently a working interest owner
in the existing plants and facilities at Wild River, Cecilia and
Bigstone. These plants are all operating at or near capacity and
Duvernay wells are shut-in for periods of time when plant owners bring
new wells on-stream. After lengthy negotiations the Company received
approval for its sought after Cecilia gas plant in early February and
has now almost completed construction of the plant and associated
gathering systems. This 100% owned and operated plant will have
capability for processing 25 mmcf/d initially and will be expanded prior
to year end 2005. The plant will eliminate further shut-ins of Duvernay
working interest gas in the Deep Basin project area.

Duvernay is also pleased to report that it has recently received Good
Production Practice (GPP) for its Wildhay/Wild River Jurassic Rock Creek
pool and intends to systematically increase production during the second
and third quarters of this year.

Spirit River

Duvernay drilled two additional successful wells during the first
quarter of 2005 at Spirit River in its Peace River High operated
complex. The Company now has 11 wells containing 18 productive zones at
Spirit River, with a considerable remaining development drilling
inventory. Currently only four Company interest sweet gas wells are on
stream, netting Duvernay approximately 600 boe/d. Duvernay has eight
sour Charlie Lake wells to bring on stream via a sour gathering system
with compression and dehydration connecting to an existing area sour gas
plant. This tie-in project, when completed, is expected to add
approximately 1,000 boe/d net to Duvernay. Surface access issues delayed
receipt of a final permit for this project until March 2005. Subsequent
wet conditions will not allow for facilities completion until late
second quarter or early third quarter. Further development drilling will
be timed to the start-up of these sour service facilities.

Exploration Program

Duvernay had very strong results with the 2004 exploration new pool
wildcat program highlighted by the major, successful exploration
step-outs on the NEBC Doig play, the significant western extension of
the regional Cadomin gas pool into Wroe-Berland and the high
deliverability Kiskatinaw discovery at Spirit River. The Company is
planning an even more expansive and aggressive new pool wildcat program
in 2005, with a minimum of fifteen wildcats currently planned. Thus far
in 2005 Duvernay has drilled successful exploration tests at Pembina in
the Nisku Formation and at Dawson in the Cretaceous Bluesky formation.
The Company is planning to production test both wells prior to Spring
break-up. Both discoveries are anticipated to make significant
contributions to Duvernay's liquid production volumes in the second half
of the year. Also included in the 2005 Exploration program are five deep
new pool wildcats beneath the greater Wild River-Fir Cretaceous Deep
Basin gas development project area. One of these new pool wildcats is
currently drilling.

MANAGEMENT DISCUSSION AND ANALYSIS

This management's discussion and analysis should be read in conjunction
with Duvernay's comparative audited annual financial statements for the
year ended December 31, 2004 and comparative information included
therein. This management discussion and analysis is dated March 17, 2005.

Certain information set forth in this management's discussion and
analysis contains forward-looking statements. By their nature,
forward-looking statements are subject to numerous risks and
uncertainties, many of which are beyond Duvernay's control, including
the impact of general economic conditions, industry conditions,
volatility of commodity prices, currency fluctuations, imprecision of
reserve estimates, environmental risks, competition from other industry
participants, the competition for qualified personnel and management,
stock market volatility and ability to access sufficient capital from
internal and external sources. Readers are cautioned that the
assumptions used in the preparation of such information, although
considered reasonable at the time of preparation, may prove to be
incorrect and, as such, undue reliance should not be placed on
forward-looking statements. Duvernay's actual results, performance or
achievement could differ materially from those expressed in or implied
by these forward-looking statements, and accordingly, no assurance 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 Duvernay will derive therefrom. Duvernay disclaims any
intention or obligation to update or revise any forward-looking
statements, whether as a result of new information, future events or
otherwise.

Funds flow from operations and operating netback are not recognized
measures under GAAP. Management believes that in addition to net income,
funds flow from operations and operating netback are useful supplemental
measures as they demonstrate Duvernay's ability to generate the cash
necessary to repay debt or fund future growth through capital
investment. Investors are cautioned, however, that these measures should
not be construed as an alternative to net income determined in
accordance with GAAP as an indication of Duvernay's performance.
Duvernay's method of calculating these measures may differ from other
companies and accordingly, they may not be comparable to measures used
by other companies. For these purposes, Duvernay defines funds flow from
operations as cash provided by operations before changes in non-cash
operating working capital and defines operating netback as revenue less
royalties and operating expenses.

Per barrel of oil equivalent amounts have been calculated using a
conversion rate of six thousand cubic feet of natural gas to one barrel
of oil equivalent (6:1). (Barrel of oil equivalents (boe) may be
misleading, particularly if used in isolation. A boe conversion ratio of
6mcf:1bbl is based on an energy equivalency conversion method primarily
applicable at the burner tip and does not represent a value equivalency
at the wellhead.)

12 months ending December 31, 2004 compared to the 12 months ending
December 31, 2003

Production

Production volumes for the twelve months ended December 31, 2004
averaged 6,136 boe/d compared to 3,225 boe/d for the same period in
2003. Fourth quarter 2004 production volumes averaged 7,275 boe/d an
increase of 76% over the 4,129 boe/d reported for the same quarter in
2003. On a year over year basis, 2004 production increased by 91% over
2003. The following table summarizes production volumes by product:



------------------------------------------------------------------------
Three Months Ended Twelve Months Ended
Dec - 31 Dec - 31
% %
2004 2003 change 2004 2003 change
----------------------------------------------------
Crude Oil and
Liquids (bbl/d) 1,307 1,554 (16)% 1,379 1,481 (7)%
Natural Gas (mcf/d) 35,803 15,446 132% 28,541 10,464 173%

Oil Equivalent
- boe's 669,265 379,836 76% 2,245,871 1,177,145 91%
Oil Equivalent
- boe/d 7,275 4,129 76% 6,136 3,225 91%
------------------------------------------------------------------------


Duvernay's production profile continued to shift towards natural gas
during 2004 with 81% natural gas and 19% oil and liquids for the fourth
quarter of 2004, changing from 62% natural gas and 38% oil and liquids
for the same period in 2003. This commodity mix is now quite consistent
with the Company's proven reserves which are 82% natural gas and 18% oil
and liquids at the end of 2004. Production by property in Q4 2004
compared to Q4 2003 is as follows:



------------------------------------------------------------------------
Average boe/d

Three Months Three Months
ending ending %
Dec - 31- 2004 Dec - 31- 2003 change
----------------------------------------------------

Sunset/Groundbirch B.C. 3,421 2,111 62%

Wildhay/Fir/Bigstone 3,057 1,545 98%

Peace River 797 473 68%

Total 7,275 4,129 76%
------------------------------------------------------------------------


Revenue & Royalties

Revenue from petroleum and natural gas sales for the 12 months ended
December 31, 2004 was $96.7 million representing a 108% increase over
revenue of $46.6 million for the same period in 2003. The revenue
increase attributed to volume growth was $44.5 million while the revenue
increase attributed to product price improvement was $5.6 million.
Revenue includes all petroleum and natural gas sales and income from
third party natural gas processing, and includes the realized portion of
commodity hedging activities. The Corporation has reported
transportation cost separately in the statement of earnings and retained
earnings as a deduction from gross revenue. Wellhead oil and liquids
prices for 2004 averaged $43.59 per barrel (including realized hedging
losses of $4.75 per barrel) compared to $39.11 per barrel in 2003
(including realized hedging losses of $0.97 per barrel). Natural gas
prices also improved on a year over year basis averaging $6.86/mcf for
2004 compared to $6.54 for 2003. Duvernay estimates that natural gas
marketing operational performance combined with natural gas hedges have
yielded the Company $2.3 million ($0.22/mcf) in additional gross revenue
over the comparable monthly indices. Prices are summarized as follows:



------------------------------------------------------------------------
Three Months Ended Twelve Months Ended
Dec - 31 Dec - 31
% %
2004 2003 change 2004 2003 change
----------------------------------------------------
Crude Oil and
Liquids $42.81 $35.80 20 $43.59 $39.11 11

Natural Gas $ 7.12 $ 6.20 15 $ 6.86 $ 6.54 5

Price/boe $42.74 $37.47 14 $41.69 $39.59 5
------------------------------------------------------------------------


Benchmark Oil and Gas Prices

------------------------------------------------------------------------
Three Months Ended Twelve Months Ended
Dec - 31 Dec - 31
% %
2004 2003 change 2004 2003 change
----------------------------------------------------
Oil
----------------
NYMEX U.S. $48.27 $31.16 55 $41.47 $30.99 34
Edmonton Par Cdn. $58.03 $40.05 45 $53.27 $43.82 22

Natural Gas
----------------
NYMEX U.S. $ 7.26 $ 5.43 34 $ 6.18 $ 5.49 13
A.E.C.O. Cdn $ 6.73 $ 5.84 15 $ 6.59 $ 6.67 (1)
Currency $.8198 $.7599 8 $.7688 $.7147 8
------------------------------------------------------------------------

Revenue is summarized as follows:
------------------------------------------------------------------------
Three Months Twelve Months
Ended Dec - 31 Ended Dec - 31
--------------------------------------------

2004 2003 2004 2003
--------------------------------------------
Revenue: ($ thousands)

Oil and NGL's $ 6,081 $ 5,191 $24,407 $21,673
Hedge (932) (71) (2,398) (525)
--------------------------------------------
$ 5,149 $ 5,120 $22,009 $21,148

Natural Gas 23,454 8,813 71,620 24,959

Processing & Rental Income 490 300 1,346 495
--------------------------------------------

Gross Revenue $29,093 $14,233 $94,975 $46,602

Interest Income (56) 88 0 223
--------------------------------------------

Total Revenue $29,037 $14,321 $94,975 $46,825

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

Duvernay's royalties are summarized as follows:

------------------------------------------------------------------------
Three Months Twelve Months
Ended Dec - 31 Ended Dec - 31
--------------------------------------------

2004 2003 2004 2003
--------------------------------------------
Royalties: ($ thousands)

Oil and Liquids $1,164 $ 929 $ 4,993 $ 5,126
Natural Gas 2,969 1,780 13,517 5,463
ARTC 0 -500 -500
--------------------------------------------
$4,133 $2,709 $18,010 $10,089

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


For the 12 months ended December 31, 2004 the average effective royalty
rate was 19% compared to 22% for the same period in 2003. The reduction
in rate is primarily driven by deep gas royalty holidays on new wells in
Alberta and the benefits realized through the British Columbia low
productivity natural gas well program. The Company records the benefits
provided by the various provincial incentive programs only in the period
in which the benefit has been approved by the provincial regulatory
agency. Consequently, in the fourth quarter, the Company had an
effective royalty rate of only 14% compared to 19% for the same quarter
in 2003.

Operating Expenses

Operating expenses include all periodic lease and field level expenses
and include no income recoveries for processing third party volumes.
Duvernay's lease operating expenses continued to trend downward for 2004
on a barrel of oil equivalent basis from $7.16/boe in 2003 to $5.37/boe
in 2004, an improvement of 25%. Total operating expenses for 2004 were
$12.1 million compared to $8.4 million for 2003. This absolute increase
is entirely attributable to increases in production volumes. For the
fourth quarter of 2004, operating expenses were down compared to the
same quarter in 2003 ($5.67/boe compared to $7.70/boe). Lease operating
expenses in 2004 improved dramatically on a per unit basis for the
following reasons; the 11-22 Wildhay facility was commissioned in
February 2004 mitigating processing costs on approximately 10 mmcf/d of
natural gas, new high pressure, high deliverability gas wells were
brought onstream with low unit operating costs, and the Company
benefited from economies of scale by having existing staff and
contractors manage a larger producing asset base. Approximately 25% of
Duvernay lease operating expenses are related to fees paid to third
parties to process and treat equity natural gas and liquids.

General & Administrative Expenses

General and Administrative Expenses are summarized on the table below as
follows:



------------------------------------------------------------------------
Three Months Twelve Months
Ended Dec - 31 Ended Dec - 31
--------------------------------------------

($ thousands) 2004 2003 2004 2003
--------------------------------------------

General & Administrative
Expenses $2,828 $1,838 $7,718 $4,723
Administrative and
Operating Recovery (98) (106) (457) (331)
Capital Recovery (687) (416) (1,962) (914)
Capitalized G&A (607) (459) (1,747) (1,209)
Stock Based Compensation 413 261 1,165 261
--------------------------------------------
$1,849 $1,118 $4,717 $2,530

$/boe $ 2.76 $ 2.94 $ 2.10 $ 2.15
------------------------------------------------------------------------


General and administrative expenses for the twelve months ending
December 31, 2004 increased to $4.7million from $2.5 million for the
same period in 2003. On a per unit of production basis, the rate
decreased slightly from $2.15/boe in 2003 to $2.10 in 2004. On a cash
basis, G&A for 2004 dropped to $1.58/boe from $1.93/boe in 2003 as fixed
costs are spread over a larger production volume. The percentage of head
office expenses attributed to exploration activities and capitalized was
35% consistent with 2003. Fourth quarter 2004 G&A cash costs are
slightly lower than the same quarter for 2003 on a per unit basis ($2.15
vs. $2.25) due to sub lease costs that the Duvernay was unable to
remediate until the end of 2003 related to the Segue acquisition
partially offset by increases in various professional services costs.

Depletion, Depreciation and Accretion

Depletion, depreciation and site restoration expense increased to $27.2
million during 2004 from $11.9 million during 2003. On a dollars per boe
basis, full year unit of production DD&A increased in 2004 to $12.12
from $10.08 in 2003, an increase of 20% due primarily to prior years
technical revisions in the Company's reserve report (2,219 mboe or
$1.00/boe), lower than anticipated per well proved reserve assignments
in the greater Wildhay tight gas area and a reduction in the percentage
of the property, plant and equipment investment excluded from Duvernay's
depletable base (13% in 2004, 16% in 2003). For the fourth quarter of
2004 the DD&A rate of $15.47/boe is compared to $10.33 for the fourth
quarter of 2003, reflecting higher finding and development costs in 2004.

Income Taxes

Duvernay did not incur any cash tax expense in 2004 other than Large
Corporation Tax, which totaled $743,000 for 2004. Other than Large
Corporation Tax Duvernay does not expect to pay any cash taxes in 2005
based on existing tax pools, planned capital expenditures and the most
recent forecast of 2005 taxable income. Although current tax horizons
depend on product prices, production levels, and the nature, magnitude
and timing of capital spending, the Company currently believes that no
cash income tax will be payable for 2 years. Duvernay's tax pools at
December 31, 2004 and December 31, 2003 are as follows:



-------------------------------------------------------
Maximum 2004 2003
Deduction % ($ thousands) ($ thousands)


COPGE 10 $ 52,346 $ 42,961
CDE 30 98,771 44,345
CEE 100 80,560 47,229
UCC 25 59,427 29,158
Other 6,883 5,883
--------------------------
$297,987 $169,576
-------------------------------------------------------
-------------------------------------------------------


The future income tax provision for the fourth quarter of 2004 was 24%
of pre tax income compared to 45% for the same period in 2003. There are
two reasons for this change in effective rate in the fourth quarter. The
first factor is that the Company enjoyed a lower crown royalty rate than
originally forecast resulting in lower crown royalty rates compared to
the resource allowance. The Company also amended its' 2003 federal
income tax return giving rise to a positive adjustment to the 2003
resource allowance calculation which is incorporated in the results for
the fourth quarter of 2004.

Funds From Operations and Earnings

Funds From Operations increased by 134% to $59.7 million ($1.38 per
diluted Equity Share) for the twelve months ending December 31, 2004
from $25.5 million ($0.80 per diluted Equity Share) for the comparable
period in 2003 due to the combination of growth in production volumes
and stronger operating netbacks which improved by 26% averaging
$28.30/boe compared to $23.86 for 2003. Full year funds from operations
guidance announced in August of 2004 was $55.2 million ($1.22/diluted
share) which was exceeded by 8% due to stronger than forecast product
prices and lower lease operating expenses. After tax earnings improved
by 154% for 2004 to $20.3 million when compared to 2003 of $8.0 million.
On a per share basis, diluted earnings improved by 88% to $0.47 per
share for 2004 compared to $0.25 for 2003.



------------------------------------------------------------------------
Three Months Ended Twelve Months Ended
Dec - 31 Dec - 31
----------------------------------------------------

2004 2003 2004 2003
----------------------------------------------------
Cash flow per
Equity Share(1) $ 0.42 $ 0.20 110% $ 1.41 $ 0.80 76%
Earnings per
Equity Share (1) $ 0.14 $ 0.04 250% $ 0.47 $ 0.25 88%
Operating Netback
per boe $30.89 $22.64 36% $28.30 $23.86 19%

note:
(1) diluted
------------------------------------------------------------------------


Liquidity and Capital Resources

Duvernay invested $179.7 million in 2004 compared to $152.8 million in
2003, as set out in the following table.



------------------------------------------------------------------------
Twelve Months Ended
Dec - 31
-----------------------------

2004 2003
-----------------------------
($ thousands) ($ thousands)

Land and seismic 19,186 13,846
Drilling and completions 131,817 72,299
Facilities 26,824 17,901
Property acquisitions (88) 6,566
Corporate acquisitions - 40,831
Other 1,952 1,337

-----------------------------
Total $179,691 $152,780

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


In February of 2004, Duvernay became a public Company by converting the
Class A common shares previously issued by private placement into common
shares tradable on the Toronto Stock Exchange. At the same time, the
Corporation issued 5 million common shares at $10.50 per share for gross
proceeds of $52.5 million ($49.5 million net). The net proceeds of the
issue were used to immediately pay off the existing credit line. In June
2004, the Corporation issued by private placement 1.6 million flow
through common shares at $15.75 per share for gross proceeds of $25.2
million ($24.0 million net). This represented a 24% premium to the
trailing 30 day trading price for the common stock and was dedicated to
Canadian Exploration Expense. In October 2004, Duvernay issued an
additional 2.5 million common shares on a bought deal basis with an
underwriting syndicate at $17.00 per share for gross proceeds of $42.5
million ($40.7 million net) and announced the expansion of the 2004
capital program to $140 million based on success in the Wildhay area.

At December 31, 2004, Duvernay had a working capital deficiency of $13.4
million with capital expenditures being funded by a combination of the
equity placements noted above, funds from operations and the
Corporation's bank line, which was drawn to $40.7 million at the end of
2004.

During 2004, the Company drilled 77 gross (49.5 net) wells, with a
success rate of 94% resulting in 7 oil wells, 65 gas wells, and 5
suspended or abandoned wells. In addition a new gas plant in the Wildhay
area of West Central Alberta was commissioned with capability to process
16 mmcf/d of sales natural gas, 100% owned by Duvernay. In the first
quarter of 2005, Duvernay is scheduled to complete construction of a 25
mmcf/d sweet gas plant to serve the Cecilia, Fir and Wroe Creek areas.

Duvernay's base capital budget for 2005 is $140 million with
approximately $25 million allocated to exploration activities and
approximately $115 million allocated to development drilling and
facilities. This capital program will be funded through a combination of
cash flow and bank debt. The Corporation has estimated that its costs of
production on a flowing barrel of oil equivalent basis for 2004 are
$29,800 per flowing boe per day computed as follows:



Productive capability December 2003 4,100 boe/d
December 2003 asset sales 300 boe/d
Decline in 2004 1,330 boe/d
-------------
Base December 2004 2,470 boe/d
Productive capability December 2004 8,500 boe/d
-------------
New production 6,030 boe/d
-------------


Capital spending of $179.7 million to yield 6,030 boe/d results in
$29,800 per flowing boe per day.

As at December 31, 2004, the Corporation had issued and outstanding
common shares of 44,286, 924 and outstanding stock options of 3,924,168.
As at March 17, 2005 the Corporation had issued and outstanding common
shares of 44,500, 491 and outstanding stock options of 3,710,601.

Financial Instruments

The Corporation makes use of specific commodity hedging instruments that
serve two primary business objectives. The first objective is to reduce
the variability in cash flows from fluctuations in product prices to
ensure a source of funding for the 2004 and 2005 capital program. The
second objective is to fix the rate of return on capital invested in the
gas prone resource projects. The Board of Directors has approved a
policy permitting management to hedge up to a fixed percentage of
budgeted corporate production.
Duvernay has entered into all hedging transactions with the same party
that the commodity is physically sold to, avoiding the need to provide
credit in the event that the hedges are at prices below prevailing
prices.

The Corporation has adopted Accounting Guideline 13 "Hedging
Relationships" that deals with the identification, designation,
documentation and measurement of effectiveness of hedging relationships
for the purpose of applying hedge accounting. The Corporation records
the realized portion of each hedge in Petroleum and Natural Gas Sales
and the unrealized portion is at December 31, 2004 is as follows:



------------------------------------------------------------------------
------------------------------------------------------------------------
Type of
Time Period Contract Quantity Control Contract Price
------------------------------------------------------------------------
2005 January
- March Collar 100 bbls/day $30.00 U.S. W.T.I. Floor
$34.35 U.S. W.T.I. Ceiling
2005 April
- June Collar 100 bbls/day $30.00 U.S. W.T.I. Floor
$36.90 U.S. W.T.I. Ceiling
2005 January
- December Collar 200 bbls/day $31.00 U.S. W.T.I. Floor
$37.43 U.S. W.T.I. Ceiling
2005 January Physical
- December (swap) 100 bbls/day $46.60 U.S. W.T.I.
2005 January
- March Collar 2,000 gj's/day $6.00 Cdn/gj Floor
$7.25 Cdn/gj Ceiling
2005 January Physical
- March (swap) 1,000 gj's/day $7.17 Cdn/gj
2005 January
- March Collar 2,000 gj's/day $6.00 Cdn/gj Floor
$11.00 Cdn/gj Ceiling
2005 April
- October Collar 2,000 gj's/day $5.87 Cdn/gj Floor
$7.92 Cdn/gj Ceiling
2005 January
- March Collar 1,000 gj's/day $7.10 Cdn/gj Floor
$9.15 Cdn/gj Ceiling
2005 January Physical
- March (Swap) 2,000 gj's/day $8.28 Cdn/gj
2005 January
- March Collar 3,000 gj's/day $8.00 Cdn/gj Floor
$12.00 Cdn/gj Ceiling
2005 January Physical
- March (Swap) 3,000 gj's/day $7.18 Cdn/gj
2005 April Physical
- October (Swap) 3,000 gj's/day $6.50Cdn/gj
2005 February Physical
- March (Swap) 3,000 gj's/day $7.29 Cdn/gj
------------------------------------------------------------------------
------------------------------------------------------------------------
Subsequent to the end of the year, the Corporation entered into physical
swaps with customers aggregating 8,000 gj's/day for the period from
April 2005 until October 2005 at prices from $6.60 Cdn/gj to $6.89
Cdn/gj.


Financial Presentation

Transportation

The Corporation commenced classifying field level transportation costs
separately as a deduction from petroleum and natural gas sales. The
comparative 2003 figures have been disclosed in a similar manner.
Adopting this presentation has no impact on funds flow from operations
or net earnings.



DUVERNAY OIL CORP.
Selected Quarterly Information

2004
Q4 Q3 Q2 Q1
------------------------------------------------------------------------
------------------------------------------------------------------------
PRODUCTION
Crude oil and
liquids (bbls) 120,282 132,187 129,507 122,884
Gas (mcf) 3,293,899 2,719,770 2,589,721 1,842,678
Oil equivalent (boe) 669,265 585,482 561,127 429,997

Crude oil and
liquids (bbls/d) 1,307 1,437 1,423 1,350
Gas (mcf/d) 35,803 29,563 28,458 20,249
Oil equivalent (boe/d) 7,275 6,364 6,166 4,725

FINANCIAL
($ thousands, except as noted)
Revenue, net of royalties
and transportation 24,904 19,393 18,895 13,774

Cash flow from operations 19,064 15,570 14,951 10,090
Per share basic 0.44 0.37 0.37 0.26

Net earnings 6,213 5,881 4,962 3,198
Per share basic 0.14 0.14 0.12 0.08
Per share diluted 0.14 0.13 0.11 0.08

Total Assets 393,440 327,031 287,471 266,207

Bank Debt 40,724 27,597 23,678 17,728

Cash and Working
capital (deficiency) (13,439) (18,184) 443 (15,678)

Basic Outstanding Shares 42,857 41,671 39,992 38,096

PER UNIT
Gas, net of
transportation ($/mcf) 7.12 6.65 7.11 6.32

Crude oil and liquids,
net of transportation
($/bbl) 42.81 47.95 43.71 39.55

Revenue, net of
transportation ($/boe) 42.74 41.74 42.92 38.38

Operating netback ($/boe) 30.89 27.55 28.62 24.86


DUVERNAY OIL CORP.
Selected Quarterly Information
2003
Q4 Q3 Q2 Q1
------------------------------------------------------------------------
------------------------------------------------------------------------
(restated)
PRODUCTION
Crude oil and
liquids (bbls) 143,005 125,171 134,418 137,996
Gas (mcf) 1,420,988 914,077 794,949 689,314
Oil equivalent (boe) 379,836 277,517 266,910 252,882

Crude oil and
liquids (bbls/d) 1,554 1,360 1,477 1,533
Gas (mcf/d) 15,446 9,936 8,736 7,659
Oil equivalent (boe/d) 4,129 3,016 2,933 2,810

FINANCIAL
($ thousands, except as noted)
Revenue, net of royalties
and transportation 11,612 7,522 8,580 9,022

Cash flow from operations 7,443 5,037 5,876 7,115
Per share basic 0.27 0.15 0.20 0.27

Net earnings 1,727 1,505 2,516 2,284
Per share basic 0.05 0.05 0.09 0.08
Per share diluted 0.04 0.04 0.09 0.08

Total Assets 220,546 198,026 130,066 106,566

Bank Debt 32,666 12,983 0 0

Cash and Working
capital (deficiency) (15,942) (19,481) 399 1,525

Basic Outstanding Shares 34,895 32,452 27,368 26,700

PER UNIT
Gas, net of
transportation ($/mcf) 6.20 5.28 7.37 7.80

Crude oil and liquids,
net of transportation
($/bbl) 35.80 41.70 37.18 44.10

Revenue, net of
transportation ($/boe) 37.47 36.21 40.66 45.34

Operating netback ($/boe) 22.64 20.38 23.76 29.60


Duvernay's quarterly growth in production volumes, gross revenue, per
share cash flow and per share earnings is primarily attributed to an
active exploration and development drilling program.



DUVERNAY OIL CORP.
Selected Annual Information

2004 2003 2002 2001
Year Year Year 4 Months
------------------------------------------------
(restated)
PRODUCTION
Crude oil and
liquids (bbls) 504,860 540,590 420,668 90,403
Gas (mcf) 10,446,068 3,819,328 626,968 0
Oil equivalent (boe) 2,245,871 1,177,145 525,163 90,403

Crude oil and
liquids (bbls/d) 1,379 1,481 1,153 741
Gas (mcf/d) 28,541 10,464 1,718 0
Oil equivalent (boe/d) 6,136 3,225 1,439 741

FINANCIAL
($ thousands, except as noted)
Revenue, net of royalties 76,966 36,736 15,130 2,749

Cash flow from
operations 59,675 25,472 9,963 1,909
Per share basic 1.47 0.84 0.37 0.07


Net earnings 20,254 8,032 2,136 450
Per share basic 0.50 0.26 0.08 0.02
Per share diluted 0.48 0.25 0.08 0.02

Total Assets 393,440 220,546 101,438 84,193

Total Long Term
Financial Liabilities 67,126 48,564 2,378 16

Cash and Working
capital (deficiency) (13,439) (15,942) 23,651 63,026

Basic Outstanding Shares 40,645 30,396 26,700 26,700

PER UNIT
Gas ($/mcf) 6.86 6.54 5.25 0.00

Crude oil and
liquids ($/bbl) 43.59 39.11 36.42 30.09

Revenue ($/boe) 41.69 39.59 35.45 30.09

Operating netback ($/boe) 28.30 23.86 19.17 15.81


Contractual Obligations

In the normal course of business Duvernay is obligated to make future
payments. These obligations represent contracts and other commitments
that are known and non-cancelable.



Payments due by period Less than
($ millions) Total 1 year 1-3 years Thereafter
Long-term debt $ 40.7 $ - $ 40.7 $ -
Operating leases 5.2 1.2 2.4 1.6
Firm transportation agreements 4.2 3.2 1.0
$ 50.1 $ 1.2 $ 46.3 $ 2.6

Drilling Results

The following table shows Duvernay's drilling results for the periods
indicated.

2004 2003
---- ----
Gross Net Gross Net
----- --- ----- ---
Year Ended Dec 31

Crude Oil 7 2.0 12 6.6
Natural gas 65 44.6 27 17.6
Suspended 1 0.5 5 3.5
Dry and abandoned 4 2.4 2 1.4
------------------------------------------------------------------------
Total wells 77 49.5 46 29.1

Landholdings

Duvernay's developed and undeveloped landholdings as at December 31,
2003 and 2004 are set forth below:

Undeveloped Developed Total
----------- --------- -----
(Acres) Gross Net Gross Net Gross Net
----- --- ----- --- ----- ---
2003
-------
Alberta 238,892 111,848 57,683 22,304 296,575 134,152
British Columbia 87,642 70,649 12,102 7,623 99,744 78,272
Saskatchewan 16,126 16,126 8,078 7,333 24,204 23,459
------------------------------------------------------------------------
Total 342,660 198,623 77,863 37,260 420,523 235,883

2004
-------
Alberta 291,554 152,204 69,683 31,177 361,237 183,381
British Columbia 113,630 88,078 24,599 17,952 138,229 106,030
------------------------------------------------------------------------
Total 405,184 240,282 94,282 49,129 499,466 289,411


CRITICAL ACCOUNTING ESTIMATES

The financial statements have been prepared in accordance with Canadian
GAAP. A summary of significant accounting policies are presented in Note
1 to the financial statements. Certain accounting policies are critical
to understanding the financial condition and results of operations of
Duvernay.

Proved Oil and Gas Reserves

Under Canadian Securities Regulations National Instrument 51-101
"Standards of Disclosure for Oil and Gas Activities" (NI 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%
probability that the quantities actually recovered will equal or exceed
the estimated reserves. There was no such consideration of probability
under National Policy 2B (NP 2B). In the case of "probable" reserves,
which are obviously less certain to be recovered than proved reserves,
NI 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% probability that the quantities actually recovered will equal or
exceed the sum of the estimated proved plus probable reserves. The
implementation of NI 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, reservoir and 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 under the heading "Full Cost Accounting for Oil and Gas
Activities".

Depletion and Depreciation Expense

Duvernay uses the full cost method of accounting for exploration and
development activities whereby all costs associated with these
activities are capitalized, whether successful or not. The aggregate of
capitalized costs, net of certain costs related to unproved properties,
and estimated future development costs is amortized using the
unit-of-production method based on estimated proved reserves. Changes in
estimated proven reserves or future development costs have a direct
impact on depletion and depreciation expense.
Certain costs related to unproved properties and major development
projects may be excluded from costs subject to depletion until proved
reserves have been determined or their value is impaired. These
properties are reviewed quarterly to determine if proved reserves should
be assigned, at which point they would be included in the depletion
calculation, or for impairment, for which any write-down would be
charged to depletion and depreciation expense.

Full Cost Accounting Ceiling Test

The carrying value of property, plant and equipment is reviewed at least
annually for impairment. Impairment occurs when the carrying value of
the assets is not recoverable by the future undiscounted cash flows. The
cost recovery 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 impact on the financial statements
could be material. Any impairment would be charged as additional
depletion and depreciation expense.

Asset Retirement Obligations

The asset retirement obligations is estimated based on existing laws,
contracts or other policies. The fair value of the obligation is based
on estimated future costs for abandonments and reclamations discounted
at a credit adjusted risk free rate. The liability is adjusted each
reporting period to reflect the passage of time, with the accretion
charged to earnings and for revisions to the estimated future cash
flows. By their nature, these estimates are subject to measurement
uncertainty and the impact on the financial statements could be material.

Income Taxes

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.

CHANGE IN ACCOUNTING POLICIES

Full Cost Accounting Guideline

Effective January 1, 2004, Duvernay adopted the new Canadian accounting
guideline for oil and gas accounting using the full cost method. In
accordance with the new guideline, Duvernay evaluates its oil and gas
assets to determine that the costs are recoverable and do not exceed the
fair value of the properties. The costs are assessed to be recoverable
if the sum of the undiscounted cash flows expected from the production
of proved reserves and the lower of cost and market of unproved
properties exceed the carrying value of the oil and gas assets. If the
carrying value of the oil and gas assets is not assessed to be
recoverable, an impairment loss is recognized to the extent that the
carrying value exceeds the sum of the discounted cash flows expected
from the production of proved and probable reserves and the lower of
cost and market of unproved properties. The cash flows are estimated
using the future product prices and costs and are discounted using the
risk-free rate.

Asset Retirement Obligations

Effective January 1, 2004, Duvernay adopted the new Canadian accounting
standard for asset retirement obligations. The year ended December 31,
2003 financial statements have been restated to reflect this change.

Transportation Expenses

Effective January 1, 2004, and consistent with the adoption of the new
Canadian accounting standard for generally accepted accounting
principles, transportation expenses have been reclassified as an expense
in the statements of earnings and accumulated earnings for year ended
December 31, 2004 and 2003. Previously, as was industry practice,
transportation expenses were netted off revenue.

Hedging Relationships

Effective January 1, 2004, Duvernay adopted the new Canadian guidelines
for hedging relationships. The adoption of these guidelines had no
impact on the results of operations or financial position of the Company.

Business Risks and Uncertainties

Duvernay is exposed to numerous risks and uncertainties associated with
the exploration for and the development, acquisition and production of
crude oil and natural gas. Primary risks include the uncertainty
associated with exploration drilling, changes in production practices,
product pricing, industry competition and government regulation.

Drilling activities are subject to numerous technical risks and
uncertainties of discovering commercially productive reservoirs.
Duvernay attempts to offset exploration risk by utilizing trained
professional staff and conducting extensive geological and geophysical
analysis prior to drilling wells.

Duvernay utilizes sound marketing practices in an attempt to partially
offset the cyclical nature of commodity pricing which is subject to
external influences beyond Duvernay's control. Fluctuations in commodity
pricing and foreign exchange rates may significantly impact Duvernay's
revenue. The oil and natural gas industry is extremely competitive and
success in competing with larger well-established competitors is not
assured.

Duvernay monitors and complies with current government regulations that
affect its activities, although operations may be adversely affected by
changes in government policy, regulations or taxation. In addition,
Duvernay maintains a level of liability, property and business
interruption insurance which is believed to be adequate for Duvernay's
size and activities, but is unable to obtain insurance to cover all
risks within the business or in amounts to cover all possible claims.

ADDITIONAL INFORMATION

Additional information regarding the Duvernay and its business and
operations, including the annual information form ("AIF") is available
on the company profiles at www.sedar.com. Copies of the AIF can also be
obtained by contacting Scott Kirker, Manager Corporate Affairs at
info@duvernayoil.com or directly at 403 571-3600.




DUVERNAY OIL CORP.
Balance Sheets

December 31, 2004 and 2003

(Thousands of Dollars)

------------------------------------------------------------------------
------------------------------------------------------------------------
2004 2003
------------------------------------------------------------------------
(as restated)
Assets

Current assets:
Cash and cash equivalents $ 143 $ -
Accounts receivable 30,920 11,879
Prepaid expenses and deposits 962 1,639
------------------------------------------------------------------------
32,025 13,518

Capital assets (note 3) 361,415 207,028

------------------------------------------------------------------------
$ 393,440 $ 220,546
------------------------------------------------------------------------
------------------------------------------------------------------------

Liabilities and Shareholders' Equity

Current liabilities:
Bank indebtedness $ - $ 619
Accounts payable and accrued liabilities 45,464 28,842
------------------------------------------------------------------------
45,464 29,461

Long-term debt (note 4) 40,724 32,666

Asset retirement obligation (note 2) 5,849 3,916

Future income tax (note 6) 20,553 11,982

Shareholders' equity:
Share capital (note 5) 248,651 131,643
Contributed surplus 1,327 261
Retained earnings 30,872 10,617
------------------------------------------------------------------------
280,850 142,521

------------------------------------------------------------------------
$ 393,440 $ 220,546
------------------------------------------------------------------------
------------------------------------------------------------------------

See accompanying notes to financial statements.



DUVERNAY OIL CORP.
Statements of Earnings and Retained Earnings

Years ended December 31, 2004 and 2003
(Thousands of Dollars, except per share amounts)

------------------------------------------------------------------------
------------------------------------------------------------------------
2004 2003
------------------------------------------------------------------------
(as restated)
Revenue:
Petroleum and natural gas $ 96,692 $ 47,287
Royalties (18,010) (10,089)
Transportation (1,716) (685)
Interest income - 223
------------------------------------------------------------------------
76,966 36,736

Expenses:
Operating 12,069 8,429
General and administration 3,552 2,269
Stock-based compensation 1,165 261
Interest 926 287
Depletion, depreciation and accretion 27,237 11,835
------------------------------------------------------------------------
44,949 23,081

------------------------------------------------------------------------
Earnings before taxes 32,017 13,655

Taxes (note 6):
Capital 743 280
Future 11,019 5,343
------------------------------------------------------------------------
11,762 5,623

------------------------------------------------------------------------
Net earnings 20,255 8,032

Retained earnings, beginning of year
(restated - note 1(g)) 10,617 2,585

------------------------------------------------------------------------
Retained earnings, end of year $ 30,872 $ 10,617
------------------------------------------------------------------------
------------------------------------------------------------------------

Earnings per share:
Basic $ 0.50 $ 0.26
Diluted $ 0.48 $ 0.25
------------------------------------------------------------------------
------------------------------------------------------------------------

See accompanying notes to financial statements.


DUVERNAY OIL CORP.
Statements of Cash Flows

Years ended December 31, 2004 and 2003
(Thousands of Dollars)

------------------------------------------------------------------------
------------------------------------------------------------------------
2004 2003
------------------------------------------------------------------------
(as restated)
Cash provided by (used in):

Operations:
Net earnings $ 20,254 $ 8,032
Items not involving cash:
Depletion, depreciation, and accretion 27,237 11,835
Stock-based compensation 1,165 261
Future income taxes 11,019 5,344
------------------------------------------------------------------------
59,675 25,472
Change in non-cash operating working capital (1,959) (5,111)
------------------------------------------------------------------------
57,716 20,361

Financing:
Issue of common shares,
net of share issue costs 114,462 19,155
Increase in long-term debt 8,058 32,666
------------------------------------------------------------------------
122,520 51,821

Investments:
Additions to property, plant, and equipment (179,779) (119,315)
Property dispositions 88 7,366
Business acquisition - (267)
Change in non-cash working capital 217 6,900
------------------------------------------------------------------------
(179,474) (105,316)

------------------------------------------------------------------------
Increase (decrease) in cash 762 (33,134)

Cash(bank indebtedness), beginning of year (619) 32,515

------------------------------------------------------------------------
Cash (bank indebtedness), end of year $ 143 $ (619)
------------------------------------------------------------------------
------------------------------------------------------------------------

Cash is defined as cash and cash equivalents.

See accompanying notes to financial statements.


DUVERNAY OIL CORP.

Notes to Financial Statements

Years ended December 31, 2004 and 2003

Nature of operations:

Duvernay Oil Corp. (the "Corporation") was incorporated under the laws
of the Province of Alberta on June 27, 2001.

1. Significant accounting policies:

(a) Capital assets:

The Corporation follows the full-cost method of accounting for oil and
gas operations whereby all costs of exploring for and developing oil and
gas properties and related reserves are capitalized. Such costs include
land acquisition costs; cost of drilling both productive and
non-productive wells, and geological and geophysical expenses and
overhead charges directly related to acquisition, exploration and
development activities.

Capitalized costs, excluding costs relating to unproven properties and
estimated salvage values, are depleted using the unit-of-production
method based on estimated proven reserves of oil and 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.

The costs of acquiring and evaluating unproved properties are initially
excluded from depletion calculations. These properties are assessed
periodically to ascertain whether impairment has occurred. When proven
reserves are assigned or the property is considered to be impaired, the
cost of the property or the amount of impairment is added to costs
subject to depletion.

The Corporation applied a "ceiling test" to capitalized costs to ensure
that the net costs capitalized do not exceed the estimated future net
revenues from the production of its proven reserves, plus the cost of
undeveloped land, less impairment. Future net revenues are calculated
using the undiscounted cash stream assigned by independent reserve
engineers adjusted for undeveloped land. Gains or losses on the
disposition of oil and gas properties are not ordinarily recognized
except under circumstances that result in a change in the depletion rate
of 20% or more.

Gas processing facilities are amortized on a straight-line basis over
their existing life of 12 years.

Depreciation of furniture and office equipment is provided using the
declining balance method based upon estimated useful lives at a rate of
25%. Leasehold improvements are amortized straight-line over the life of
the lease.

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.

(b) Interest in joint ventures:

Substantially all of the Corporation's oil and gas 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 is defined as cash and investments with a maturity of three months
or less.

(d) 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 using the treasury stock method. Diluted calculations reflect
the weighted average incremental Common Shares that would be issued upon
exercise of dilutive options and warrants assuming the proceeds would be
used to repurchase shares at average market prices for the period. The
weighted average number of shares outstanding is then adjusted by the
net change.

(e) Future income taxes:

The Corporation uses the liability method of income taxes. Under this
method, income tax liabilities and assets are recognized for the
estimated tax consequences attributable to differences between the
amounts reported in the financial statements and their respective tax
bases, using income tax rates enacted at the balance sheet date. The
effect of a change in rates on future income tax liabilities and assets
is recognized in the period that the change occurs.

(f) Use of estimates:

The preparation of financial statements in accordance with Canadian
generally accepted accounting principles requires management to make
estimates and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities and the
reported amounts of revenues and expenses during the reporting period.
In particular, 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. Actual results
could differ from these estimates.

(g) Stock-based compensation plans:

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

(h) Financial instruments:

The Corporation sells forward a portion of its future production through
a combination of fixed price sale contracts with customers and commodity
swap agreements with financial counterparties. Financial instruments are
not used for speculative purposes. When the Corporation enters into a
hedge it formally assesses, both at the hedges 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.

(i) Hedging:

Effective January 1, 2004, the Corporation adopted the new standards
with respect to hedging contained in Accounting Guideline 13. All
realized gains and losses from petroleum and natural gas hedging
activities are included in Duvernay's earnings for the period.

(j) Asset retirement obligations:

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 recognized by increasing the
carrying amount of property, plant and equipment. The asset recorded is
depleted on a unit of production basis over the life of the reserves.
The liability amount is increased each reporting period due to the
passage of time and the amount of 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.

Previously, the Corporation recognized a provision for estimated future
removal and site restoration costs calculated on the unit-of-production
method over the remaining proved reserves.

The effect of this change in accounting policy has been recorded
retroactively with restatement of prior periods. The effect of the
adoption is presented below as increases (decreases):



------------------------------------------------------------------------
------------------------------------------------------------------------
December 31, 2003
------------------------------------------------------------------------

Balance Sheets

Asset retirement costs, included in petroleum
and natural gas properties $3,498,651
Asset retirement obligation 3,916,015
Provision for future site restoration (451,183)
Future income tax 12,000
Retained earnings 21,819
------------------------------------------------------------------------
------------------------------------------------------------------------

Year ended December 31, 2003
------------------------------------------------------------------------

Statement of Operations

Accretion expense $ 84,673
Depletion and depreciation on asset retirement costs 215,857
Amortization of estimated future removal and site
restoration liability (334,350)
Net earnings impact 21,819
Basic net earnings per share 0.01
Diluted net earnings per share 0.01
------------------------------------------------------------------------
------------------------------------------------------------------------


(k) 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.

(l) Comparative information:

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

(m) Revenue recognition:

Revenue from the sale of petroleum and natural gas is recognized during
the month when title passes to an external party.


2. 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 $10,592,000 (2003 - $7,441,000)
which will be incurred between 2010 and 2016. A credit-adjusted
risk-free rate of 7% 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 period $3,916,015 $1,209,615
Accretion expense 382,619 84,673
Liabilities incurred 1,549,965 2,621,727
Liabilities settled - -

------------------------------------------------------------------------
Balance, end of period $5,848,599 $3,916,015
------------------------------------------------------------------------
------------------------------------------------------------------------

3. Capital assets:

------------------------------------------------------------------------
------------------------------------------------------------------------
Accumulated Net book
2004 Cost depreciation value
------------------------------------------------------------------------

Petroleum and natural
gas properties $384,687,650 $ 42,653,267 $342,034,383
Gas processing facilities 20,798,152 1,658,877 19,139,275
Furniture, fixtures and
leasehold improvements 517,727 276,662 241,065

------------------------------------------------------------------------
$406,003,529 $ 44,588,806 $361,414,723
------------------------------------------------------------------------
------------------------------------------------------------------------

December 31, 2003 (restated)
------------------------------------------------------------------------

Petroleum and natural gas
properties $211,816,348 $ 16,685,981 $195,130,367
Gas processing facilities 12,275,752 660,953 11,614,799
Furniture and fixtures 334,820 88,047 246,773
Leasehold improvements 85,616 49,943 35,673

------------------------------------------------------------------------
$224,512,536 $ 17,484,924 $207,027,612
------------------------------------------------------------------------
------------------------------------------------------------------------


The cost of unproven lands at December 31, 2004 of $51,005,000 (2003 -
$35,878,000) has been excluded from the depletion calculation. Future
development costs of proven reserves of $67,408,000 have been included
in the depletion calculation.

General and administrative expenditures of $1,750,000 (2003 -
$1,210,000) have been capitalized and included as costs of petroleum and
natural gas properties.

At December 31, 2004, the Company applied a ceiling test to its
petroleum and natural gas assets using expected future market prices of:



Benchmark reference price forecast 2005 2006 2007 2008 2009

WTI ($US/bbl) 42.00 40.00 38.00 36.00 34.00
AECO ($Cdn/mcf) 6.60 6.35 6.15 6.00 6.00

After 2009 the change in future prices are escalated at 2% per year to
the end of the reserve life.


4. Long-term debt:

The Corporation has a financing arrangement with a Canadian chartered
bank for an extendible revolving term loan in the amount of $80 million.
As at December 31, 2004, $40,724,440 of this term loan was drawn. The
facility bears interest on a variable grid currently 125 basis points
over the prevailing bankers' acceptance rate. Security for the facility
includes a general security agreement and a $100 million demand loan
debenture secured by a first floating charge over all assets. In May
2005, at the Company's discretion, the facility is available on a
non-revolving basis for a period of 366 days, at which time the facility
would be due and payable. Alternatively, the facility may be extended
for a further 364-day period at the request of the Company and subject
to approval by the bank. The Corporation is required to meet certain
financial based covenants to maintain the facility.

Cash interest paid during the year was $926,636 (2003 - $287,057).



5. Share capital:

(a) Authorized:

Unlimited number of common shares and Class A common shares

Unlimited number of first preferred shares and second preferred
shares, each issuable in series

(b) Common shares issued:

------------------------------------------------------------------------
Number of
Shares Amount
------------------------------------------------------------------------

Balance December 31, 2002 26,700,000 $ 80,970,554
For cash on private placement 3,200,000 20,000,000
For Segue Energy Corporation 4,995,258 31,220,363
Share issue costs - (845,042)
Tax effect on share issue costs - 296,712
------------------------------------------------------------------------
Balance, December 31, 2003 34,895,258 131,642,587
For cash as initial public offering 5,000,000 52,500,000
For cash on private placement of flow
through shares 1,600,000 25,200,000
For cash on private placement 2,500,000 42,500,000
For cash on exercise of stock options 291,666 1,120,747
Contributed surplus on exercise of
stock options 98,497
Share issue costs - (6,858,939)
Tax effect on share issue costs - 2,448,000

------------------------------------------------------------------------
Balance, December 31, 2004 44,286,924 $248,650,892
------------------------------------------------------------------------

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


On June 29, 2004, the Company completed a bought-deal private placement
of 1,600,000 flow-through Common Shares at $15.75 per share for gross
proceeds of $25,200,000. 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 $25,200,000
before December 31, 2005. At December 31, 2004 the Corporation has
incurred $12,500,000 of eligible expenditures relating to this
commitment.



(c) Contributed surplus:

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

Contributed surplus, December 31, 2003 $ 260,881
Stock based compensation $ 1,165,066
Exercise of stock options $ (98,497)
-----------------------------------------------------------------------
Contributed surplus, December 31, 2004 $ 1,327,450
------------------------------------------------------------------------
------------------------------------------------------------------------


(d) Stock options:

The Corporation has a fixed stock option plan. Under the employee stock
option plan, the Corporation may grant options to its employees for up
to 3,989,526 shares of common stock. The exercise price of each option
equals the market price of the Corporation's stock on the date of grant
and an option's maximum term is five years. Options are granted
throughout the year and vest 1/3 on each of the first, second and third
anniversaries from the date of grant.

Changes in the number of options, with their weighted average exercise
price, are summarized below:



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

Stock options outstanding,
beginning of year 3,430,000 $ 4.33 2,215,000 $ 3.50
Granted 792,500 15.12 1,215,000 5.85
Exercised (291,666) 3.84 - -
Cancelled (6,666) 3.50 - -

------------------------------------------------------------------------
Stock options outstanding,
end of year 3,924,168 $ 6.55 3,430,000 $ 4.33
------------------------------------------------------------------------
------------------------------------------------------------------------

Exercisable, end of year 2,075,001 $ 3.91 1,230,000 $ 3.50
------------------------------------------------------------------------
------------------------------------------------------------------------


------------------------------------------------------------------------
------------------------------------------------------------------------
Options Outstanding Options Exercisable
------------------------------------------------------------------------
Weighted
Average
Remaining
Exercise Number Contractual Number Exercise
Price Outstanding Life (years) exercisable Price
------------------------------------------------------------------------

$ 3.50 2,128,001 2.40 1,764,667 $ 3.50
6.25 1,003,667 3.83 310,334 6.25
10.90 37,500 4.25
12.37 20,000 4.42
13.71 375,000 4.67
17.18 360,000 4.94

------------------------------------------------------------------------
$ 6.55 3,924,168 3.24 2,075,001 $ 3.91
------------------------------------------------------------------------
------------------------------------------------------------------------

Stock-based compensation:

The fair value of each option granted is estimated on the date of grant
using the Black-Scholes option pricing model with weighted average
assumptions for grants as follows:

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

Risk-free interest rate (%) 4.5% 4.5%
Expected life (in years) 3.5 5.0
Expected volatility 40% 40%
Expected dividend Nil Nil
Expected forfeitures 10% 10%
Average fair value of options granted ($) 4.76 2.23
------------------------------------------------------------------------
------------------------------------------------------------------------


(e) 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 40,644,585 (December 31, 2003 -
30,395,715).

In computing diluted earnings per share for the period ended December
31, 2004, 1,762,697 (December 31, 2003 - 1,467,891) shares were added to
the weighted average number of common shares outstanding for the
dilution added from the stock options.

6. Income taxes:

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 Corporation's earnings before
income taxes. This difference results from the following items:



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

Earnings before taxes $ 32,016,413 $ 13,655,204
------------------------------------------------------------------------
------------------------------------------------------------------------

Combined federal and provincial tax rate 39.75% 40.41%

Computed "expected" income tax expense $ 12,726,524 $ 5,518,068

Increase (decrease) resulting from:
Non-deductible crown charges 4,689,952 2,958,201
Resource allowance (5,165,603) (2,440,980)
Effect of change in tax rate (1,102,762) (1,006,793)
Stock Based Compensation 463,114 105,422
Other (592,225) 209,496
------------------------------------------------------------------------
Future income taxes 11,019,000 5,343,414
Capital taxes 743,000 279,769
------------------------------------------------------------------------
$ 11,762,000 $ 5,623,183
------------------------------------------------------------------------
------------------------------------------------------------------------

Cash taxes paid during the year were $445,945 (2003 - $169,938).


The components of the Corporation's future income tax liability are as
follows:

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

Future tax assets:
Asst retirement obligation $ 2,088,000 $ 1,397,822
Share issue expenses 2,462,000 768,683

-----------------------------------------------------------------------
4,550,000 2,166,505

Future tax liabilities:
Property, plant and equipment 25,103,000 14,148,505

------------------------------------------------------------------------
Net future tax liability $20,553,000 $11,982,000
------------------------------------------------------------------------
------------------------------------------------------------------------


7. Financial instruments:

(a) 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.

(b) Credit risk:

A substantial portion of the Corporation's accounts receivable are with
customers and joint venture partners in the oil and 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.

(c) Fair value of financial instruments:

The carrying amounts of financial instruments included in the balance
sheet approximate their fair value due to their short-term maturity, and
long-term debt is carried at fair value because the terms and conditions
are similar to those that the Corporation could negotiate for similar
debt.

(d) Commodity price risk management:

As at December 31, 2004, the Corporation had fixed the price applicable
to future production as follows:



------------------------------------------------------------------------
------------------------------------------------------------------------
Type of
Time Period Contract Quantity Control Contract Price
------------------------------------------------------------------------
2005 January
- March Collar 100 bbls/day $30.00 U.S. W.T.I. Floor
$34.35 U.S. W.T.I. Ceiling
2005 April
- June Collar 100 bbls/day $30.00 U.S. W.T.I. Floor
$36.90 U.S. W.T.I. Ceiling
2005 January
- December Collar 200 bbls/day $31.00 U.S. W.T.I. Floor
$37.43 U.S. W.T.I. Ceiling
2005 January Physical
- December (swap) 100 bbls/day $46.60 U.S. W.T.I.
2005 January
- March Collar 2,000 gj's/day $6.00 Cdn/gj Floor
$7.25 Cdn/gj Ceiling
2005 January Physical
- March (swap) 1,000 gj's/day $7.17 Cdn/gj
2005 January
- March Collar 2,000 gj's/day $6.00 Cdn/gj Floor
$11.00 Cdn/gj Ceiling
2005 April
- October Collar 2,000 gj's/day $5.87 Cdn/gj Floor
$7.92 Cdn/gj Ceiling
2005 January
- March Collar 1,000 gj's/day $7.10 Cdn/gj Floor
$9.15 Cdn/gj Ceiling
2005 January Physical
- March (Swap) 2,000 gj's/day $8.28 Cdn/gj
2005 January
- March Collar 3,000 gj's/day $8.00 Cdn/gj Floor
$12.00 Cdn/gj Ceiling
2005 January Physical
- March (Swap) 3,000 gj's/day $7.18 Cdn/gj
2005 April Physical
- October (Swap) 3,000 gj's/day $6.50Cdn/gj
2005 February Physical
- March (Swap) 3,000 gj's/day $7.29 Cdn/gj
------------------------------------------------------------------------
------------------------------------------------------------------------


The estimated fair value of the fixed price contracts based on the
amounts the Corporation would receive if the contracts were terminated
as at December 31, 2004 is $1.3 million.

RESERVES

The 2004 corporate reserve evaluation was conducted by Gilbert Laustsen
Jung Associates Ltd. ("GLJ") utilizing NI 51-101 evaluation guidelines.
A summary of the Company Interest reserves utilizing forecasted prices
and costs, effective December 31, 2004, is provided below.



Duvernay Oil Corp. Reserves Summary December 31 2004
Company Interest (Includes Working Interests and Royalty Interests)
------------------------------------------------------------------------

2004 2003
---- ------
Oil Gas NGL's Equiv. Equiv.
----- ------ ----- ------ -------
mstb mmcf mbbl mboe mboe
----- ------ ----- ------ -------

Proved Producing 1,234 59,726 918 12,106 8,471

Proved non Producing 99 29,668 477 5,521 6,150
Proved Undeveloped 223 36,566 392 6,710 4,102
---------------------------------- -------
TOTAL PROVED 1,556 125,961 1,787 24,337 18,723

Probable 546 61,216 764 11,512 6,252
---------------------------------- -------
PROVED plus PROBABLE 2,102 187,176 2,551 35,849 24,976


Columns may not add due to rounding

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


From 2003 to 2004, Total Proved reserves have increased 30 % and Total
Proved plus Probable reserves increased by 44 %. This represents a
reserve replacement of 2004 production of 350 % based on Proved reserves
and 584 % based on Proved plus Probable reserves. Approximately 60 % of
the total Company Proved reserves are located in the Deep Basin region
of Alberta (Wildhay, Fir, Wroe, Berland, Bigstone) with 30 % of the
reserves located in the greater Sunset area of northeastern British
Columbia and the remaining 10 % in the Peace River area of Alberta.

Proved producing reserves are 50 % of Total Proved reserves and 34 % of
Proved plus Probable reserves. This is a consistent with previous
evaluations and once again reflects the large inventory of projects to
be developed and brought onstream. The Company estimates that over 3
mmboe of non-producing reserves were converted to proved producing
reserves in the first quarter of 2005.

NI 51-101 finding and development costs including future capital were
$21.46 for Proved reserves and $15.46 on a Proved plus Probable basis.
Based on average 2004 production, Duvernay's Proved plus Probable
reserve life index is 16.0 years. The reserve life index is 13.5 years
utilizing annualized fourth quarter production. Additional reserve
disclosure tables, as required under NI 51-101 may be found in the
Annual Information Form to be filed on SEDAR on or before March 31, 2005.

The present value of the Company reserves using GLJ's January 1, 2005
price forecast is summarized below.



Duvernay Oil Corp. Reserves Summary Dec 31 2004
Company Interest (Includes Working Interests and Royalty Interests)

------------------------------------------------------------------------
$ M Discount Rate
-------------
0% 5% 10% 15% 20%
------- ------- ------- ------- --------
Proved Producing 251,327 209,058 181,004 160,816 145,478

Proved non Producing 113,960 93,196 79,278 69,237 61,630
Proved Undeveloped 93,512 67,576 50,750 39,034 30,469

------------------------------------------------
TOTAL PROVED 458,799 369,829 311,032 269,086 237,577

Probable 221,666 144,084 104,045 79,848 63,723

------------------------------------------------
PROVED plus PROBABLE 680,465 513,914 415,077 348,934 301,301

Columns may not add due to rounding

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


Reserve Reconciliation

A reconciliation of Company reserves by product type is shown below.
Negative revisions resulted from the difficulty in predicting production
performance of newly drilled wells.



Reconciliation of Company Interest Reserves by Product Type Forecast
Prices and Costs

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

Light Natural
Oil Gas NGL's Equivalent
------ ------- ------ -----------
mstb bcf mbbl mmbbl
------ ------- ------ -------

PROVED PRODUCING

Opening Balance (Jan/04) 1515.0 36.666 844.0 8.470
Extensions 21.0 14.456 216.8 2.647
Improved Recovery 30.7 18.077 113.2 3.157
Technical Revisions 34.1 -1.975 -185.2 -0.480
Discoveries 0.0 2.930 15.9 0.504
Acquisitions 18.2 0.122 2.2 0.041
Dispositions 0.0 -0.816 0.0 -0.136
Economic Factors 28.0 0.712 3.0 0.150
Production -413.0 -10.446 -91.9 -2.246
------ ------- ------ -------
Closing Balance (Jan/05) 1234.0 59.726 918.0 12.106

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



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

Light Natural
Oil Gas NGL's Equivalent
------ ------- ------ -----------
mstb bcf mbbl mboe
------ ------- ------ -------
TOTAL PROVED

Opening Balance (Jan/04) 1780.0 92.577 1514.0 18.724
Extensions 21.0 33.727 552.7 6.195
Improved Recovery 53.4 15.997 77.7 2.797
Technical Revisions -24.7 -12.894 -343.0 -2.517
Discoveries 24.1 6.499 72.0 1.179
Acquisitions 18.2 0.122 2.2 0.041
Dispositions 0.0 -1.659 0.0 -0.277
Economic Factors 97.0 2.038 3.0 0.440
Production -413.0 -10.446 -91.9 -2.246
------ ------- ------ -------
Closing Balance (Jan/05) 1556.0 125.961 1786.7 24.337

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


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

Light Natural
Oil Gas NGL's Equivalent
------ ------- ------ -----------
mstb bcf mbbl mboe
------ ------- ------ -------
PROVED PLUS PROBABLE

Opening Balance (Jan/04) 2175.0 124.443 2060.0 24.976
Extensions 27.0 50.628 832.4 9.297
Improved Recovery 97.7 22.026 102.8 3.872
Technical Revisions -35.9 -10.237 -485.0 -2.227
Discoveries 210.0 10.288 125.7 2.050
Acquisitions 23.1 0.140 2.5 0.049
Dispositions 0.0 -1.981 0.0 -0.330
Economic Factors 18.0 2.315 4.0 0.408
Production -413.0 -10.446 -91.9 -2.246
------ ------- ------ -------
Closing Balance (Jan/05) 2101.9 187.176 2550.5 35.849

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


FORWARD LOOKING STATEMENTS

Certain information set forth in this press release contains
forward-looking statements. By their nature, forward-looking statements
are subject to numerous risks and uncertainties, many of which are
beyond Duvernay's control, including the impact of general economic
conditions, industry conditions, volatility of commodity prices,
currency fluctuations, imprecision of reserve estimates, environmental
risks, competition from other industry participants, the competition for
qualified personnel and management, stock market volatility and ability
to access sufficient capital from internal and external sources. Readers
are cautioned that the assumptions used in the preparation of such
information, although considered reasonable at the time of preparation,
may prove to be incorrect and, as such, undue reliance should not be
placed on forward-looking statements. Duvernay's actual results,
performance or achievement could differ materially from those expressed
in or implied by these forward-looking statements, and accordingly, no
assurance 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 Duvernay will derive therefrom. Duvernay disclaims any
intention or obligation to update or revise any forward-looking
statements, whether as a result of new information, future events or
otherwise.

Funds flow from operations and operating netback are not recognized
measures under GAAP. Management believes that in addition to net income,
funds flow from operations and operating netback are useful supplemental
measures as they demonstrate Duvernay's ability to generate the cash
necessary to repay debt or fund future growth through capital
investment. Investors are cautioned, however, that these measures should
not be construed as an alternative to net income determined in
accordance with GAAP as an indication of Duvernay's performance.
Duvernay's method of calculating these measures may differ from other
companies and accordingly, they may not be comparable to measures used
by other companies. For these purposes, Duvernay defines funds flow from
operations as cash provided by operations before changes in non-cash
operating working capital and defines operating netback as revenue less
royalties and operating expenses.

Per barrel of oil equivalent amounts have been calculated using a
conversion rate of six thousand cubic feet of natural gas to one barrel
of oil equivalent (6:1). (Barrel of oil equivalents (boe) may be
misleading, particularly if used in isolation. A boe conversion ratio of
6mcf:1bbl is based on an energy equivalency conversion method primarily
applicable at the burner tip and does not represent a value equivalency
at the wellhead.)

-30-

Contact Information

  • FOR FURTHER INFORMATION PLEASE CONTACT:
    Duvernay Oil Corp.
    Michael Rose
    President and C.E.O.
    (403) 571-3600
    or
    Duvernay Oil Corp.
    Brian Robinson
    Vice President - Finance and C.F.O.
    (403) 571-3609
    or
    Duvernay Oil Corp.
    Scott Kirker
    Manager - Corporate Affairs
    (403) 571-3683
    Website: www.duvernayoil.com