Duvernay Oil Corp.
TSX : DDV

Duvernay Oil Corp.

March 23, 2006 09:00 ET

Duvernay Enjoys Record 2005, Doubles Reserves and Earnings

CALGARY, ALBERTA--(CCNMatthews - March 23, 2006) - Duvernay Oil Corp. (TSX:DDV) is pleased to report record fourth quarter and 12 month 2005 results and provide an operational update on activities.

2005 Highlights

- Record cash flow in the fourth quarter of $53.8 million ($1.02 per diluted share), an increase of 182% from the same quarter in 2004.

- Full year cash flow of $137.5 million ($2.81 per diluted share) was double 2004 cash flow on a per share basis ($59.7 million/$1.41 per diluted share).

- Record quarterly production of 13,601 boe/d, an increase of 33% from the third quarter and an increase of 87% from the same quarter in 2004.

- Duvernay achieved the 2005 Production Exit rate target of 15,500 boe/d, compared to a 2004 exit of 7,400 boe/d.

- Record earnings in the fourth quarter of $18.3 million ($ 0.35 per diluted share), an increase of 194 % from the same quarter in 2004.

- Full year 2005 earnings of $50.1 million ($1.02 per diluted share) more than double 2004 earnings of $20.3 million ($0.48 per diluted share).

- Total proved plus probable reserves were approximately doubled in 2005, entirely with the drill bit.

- Record reserve growth including top decile reserve replacement of 812%, and a reserve life index of 17.5 years.

- Strong reserves per share growth of 74% year over year.

- 2005 Drill Bit Finding and Development costs of $9.66/boe (proved plus probable) and Finding Development and Acquisition costs of $13.32/boe (proved plus probable).

- Strong unit netbacks averaging $37.57 for 2005 an increase of 32% from 2004.

- Top decile operating costs of $ 5.60 boe in 2005 and G&A costs of $ 0.92/boe. Operating costs were $ 4.95/boe in December of 2005, already close to the initial 2006 full year operating cost target ($4.75/boe).

- Record drilling totals of 126 gross (85.6 net) wells with a 97% success rate.

- Completed major plant and gathering system infrastructure investments in 2005 of $103 million, positioning Duvernay to be a dominant, long term competitor in the Alberta Deep Basin and Northeast B.C.

- Application of new technology in both major gas development project areas is yielding gas wells with initial deliverabilities more than double Duvernay's historical average.

- Multiple New Pool Wildcat discoveries in first quarter of 2006.

Production

Duvernay enjoyed a record year for production in 2005, achieving both the 10,000 boe/d and 15,000 boe/d milestones. 2005 average production of 10,469 boe/d was 71% higher than 2004 average production of 6,136 boe/d. Fourth quarter 2005 average production was approximately 33% higher than third quarter 2005 average production. Duvernay reached and exceeded its production exit target of 15,500 boe/d in late December 2005.

Effective January 1, 2006, Duvernay sold select, small non-core assets and returned its Pembina 6-11 production back to MRL rates, reducing overall corporate production volumes by approximately 1,250 boe/d from the December 2005 average of 15,000 boe/d. These volumes were replaced by tie-ins in the Alberta Deep Basin during late January and February. The company expects to tie-in a total of 50 new gas wells between January and April 2006, as well as start up new gas plants at Brassey and Sundown, B.C. Sundown is currently expected to start up in late March and Brassey is expected to start up in mid-April. Both plants have been delivered to their field sites. Current production volumes are 16,500 boe/d, and assuming that facility and significant well start ups happen on schedule, a production level of between19,000 and 20,000 boe/d is anticipated in late April or early May 2006.

As was the case in 2005, Duvernay expects quarter over quarter production volume growth to have a significant range of between 2.5 and 25 percent during 2006 with the actual growth rate primarily a function of when new company operated facilities commence production within the quarter. Duvernay remains on track to meet or exceed the previously disclosed full year 2006 average production target of 19,600 boe/d. Initial per well gas deliverabilities have been significantly higher than the historical Duvernay average in both large gas development project areas during the past eight months. Continuation of these above average per well rates could lead to an increase in both 2006 and 2007 production volume outlooks.

Reserves

Duvernay added 34.8 mmboe of total proved plus probable reserves with the 2005 EP program, essentially doubling the year end 2004 proved plus probable reserves of 35.8 mmboe. Year over year proved plus probable reserves were increased 86% after production. Finding and development costs were $13.32/boe for 2005, including revisions and excluding future capital ($18.66/boe including future capital. Proved plus probable reserves replacement was 812%, and the proved plus probable reserve life index has expanded to 17.5 years.

Year over year total proved reserves were increased 64% in 2005 with total proved reserve replacement of 410%. Finding and development costs for total proved additions in 2005 were $23.76/boe including revisions and excluding future capital ($28.36/boe including future capital). The majority of Duvernay's wells are less than two years old yielding smaller initial proved reserve recognition under the NI 51-101 (P90) guidelines. Duvernay believes that the majority of the current probable reserves will be converted to proved reserves over the next 12 to 24 months. The estimated late April/early May 2006 production estimate of between 19,000 and 20,000 boe/d is already in excess of the forecast GLJ total proved plus probable 2006 production estimate.

2005 was a record year for facility investment by Duvernay as it built the necessary gas infrastructure in both major project areas to ensure long term gas processing access and production volume certainty. The 2005 total facility investment of $103 million will drop dramatically in 2006 and again in 2007. Excluding these facility expenditures, 2005 finding and development costs were $9.66/boe for 'drill-bit' proved plus probable reserves. The majority of future unbooked development wells in both the Alberta Deep Basin and Sunset-Groundbirch will access these facilities; future finding and development costs should migrate towards the 2005 'drill-bit' cost levels.

In the Deep Basin of Alberta, Duvernay has over 300 uncompleted zones with wireline log pay in existing Duvernay well bores that are not recognized with reserves in the 2005 GLJ report. The increasing application of multi-zone, commingled completion technology will allow for earlier recognition of these by-passed zones in future wells. The company plans to employ two service rigs in 2006 to systematically complete and access these unbooked uphole zones in existing wells.

Finding and Development costs are calculated using NI51-101 methodology. 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, 2006.

Financial Results and Outlook

Duvernay delivered record financial results in 2005. Cash flow of $137.5 million ($2.81 per diluted share) more than doubled when compared to 2004 of $59.7 million ($1.41 per diluted share). Similarly earnings of $50.1 million ($1.02 per diluted share) reached record levels when compared to $20.3 million ($0.48 per diluted share) achieved in 2004. Earnings efficiency was also boosted in 2005 reaching 36% as a percentage of cash flow compared to 34% in 2004.

Strong unit operating netbacks, for 2005 of $37.57 per boe are the combination of high product prices and Duvernay's continued emphasis on cost control. Duvernay operating expenses for 2006 are expected to be below $5.00 per boe ($5.60 per boe in 2005) as more natural gas is processed through company owned facilities. In a similar manner, cash general and administrative costs of $0.92 per barrel of oil equivalent for 2005 improved by more than 70% compared to 2004. Finally, royalty rates in 2005 are amongst the best in the industry, averaging 20% as the company continued to benefit from various royalty relief programs in Alberta and B.C. Continued improvement in the overall unit cost structure positions Duvernay for strong profitability in 2006, even if lower natural gas prices persist.

EP Program Update

Duvernay continues to operate 12 drilling rigs and 15 service rigs throughout its EP core areas. Thus far in the first quarter, Duvernay has drilled 42 wells (31 net) with a 100% success rate. All wells required to achieve both first and second quarter 2006 production growth objectives have been drilled and completed. Multiple tie-in and Duvernay owned and operated facility projects are underway throughout Alberta and B.C. The Sundown B.C. plant is expected to commence production at the end of March, the Brassey B.C. plant is expected to start-up during the third week of April and the Cecilia Alberta 15-4 plant expansion is expected to be operational during the first week of May.

In the Alberta Deep Basin, a combination of optimum well location and co-mingled multi-zone completion technology is yielding spectacular test results. In addition to the Fir-Oldman area well announced on February 9th, (14.5 mmcf/d initial test rate) the company has recently completed a five zone 100% working interest gas well in the Wild River - Wroe area with a combined initial test rate in excess of 15.0 mmcf/d. Both of these wells are expected to decline when production commences, but both should ultimately be amongst the best wells in the Deep Basin over life.

During the first quarter Duvernay entered into a major farm-in in the Alberta Deep Basin operated area, securing an additional 30 sections of land. These new lands are expected to add an additional 100 locations to the existing Deep Basin development well inventory of approximately 450 locations. This highly attractive new acreage is within the Duvernay Cecilia plant gathering area.

In the Sunset-Groundbirch complex of NEBC, Duvernay has also enjoyed recent stellar well results. The Corporation tested a new pool Triassic Doig gas discovery at stabilized rates of 96 e3m3/d in the greater Sundown area. Four additional new pool Triassic gas discoveries, separate from the existing Groundbirch pool, were cased in the complex during the first quarter. Overall complex production is anticipated to reach the 50 mmcf/d milestone in April with the start-up of the Sundown and Brassey plants. All the Doig wells required to fill and maintain the four Duvernay operated B.C. plants are already drilled and completed.

At Puskwa, Alberta, Duvernay has continued its long evolving exploration program. The company has two oil wells producing from the two different deep Devonian sand oil objectives in the area. Duvernay plans step-outs to both of these wells as well as a large 3D program immediately after spring break-up. Duvernay has 47.75 (41.80 net) sections of land in the immediate vicinity of the company's two existing oil wells and recently announced high oil rate competitor wells.

Additional new pool wildcat successes were cased in March at Dawson and Elmworth Alberta. Production testing of the Dawson discovery is expected to commence within the next two weeks. A deep Devonian exploration new pool wildcat at Spirit River Alberta is expected to spud within the next week.

Expected 2006 production volumes from the exploration discoveries and subsequent 2006 delineation wells at Sunset, Puskwa, Dawson and Elmworth are not included in the current 2006 full year production forecast.

MANAGEMENT'S 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, 2005 and comparative information included therein. This management's discussion and analysis is dated March 22, 2006.

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, except as expressly required by applicable securities laws.

Funds from operations and operating netback are not recognized measures under GAAP. Management believes that in addition to net income, funds 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 from operations as cash provided by operations before changes in non-cash operating working capital and abandonment costs incurred. Operating netback is defined 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.)

Year ending December 31, 2005 compared to the Year ending December 31, 2004

Production

Production volumes for the year ended December 31, 2005 averaged 10,469 boe/d compared to 6,136 boe/d for the same period in 2004. Fourth quarter 2005 production volumes averaged 13,601 boe/d, an increase of 87% over the 7,275 boe/d reported for the same quarter in 2004. On a year over year basis, 2005 production increased by 71% over 2004. The following table summarizes production volumes by product:



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

Three Months Ended Year Ended
Dec - 31 Dec - 31
--------------------------- ---------------------------
% %
2005 2004 change 2005 2004 change
---------- -------- ------- --------- --------- -------
Crude Oil and
Liquids (bbl/d) 2,856 1,307 119% 2,229 1,379 62%
Natural Gas
(mcf/d) 64,471 35,803 80% 49,442 28,541 73%

Oil Equivalent
- boe's 1,251,314 669,265 87% 3,821,202 2,245,871 71%
Oil Equivalent
-boe/d 13,601 7,275 87% 10,469 6,136 71%

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


Duvernay's production profile continued to be natural gas weighted during 2005 with 79% natural gas and 21% oil and liquids, consistent with full year 2004 with 78% natural gas and 22% oil and natural gas liquids. Production by property in Q4 2005 compared to Q4 2004 is as follows:



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

Average boe/d
Three Months Three Months
ending ending %
Dec - 31- 2005 Dec - 31- 2004 change
--------------- --------------- --------

North East B.C. 4,052 3,421 18%

Deep Basin 6,845 3,057 124%

Peace River/Pembina/Other 2,704 797 239%

Total 13,601 7,275 87%

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


Revenue & Royalties

Revenue from petroleum and natural gas sales for the year ended December 31, 2005 was $213.0 million representing a 120% increase over revenue of $96.7 million for the same period in 2004. The revenue increase attributed to volume growth was $65.6 million while the revenue increase attributed to product price improvement was $50.7 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. Realized oil and liquids prices for 2005 averaged $55.73 per barrel (including realized hedging losses of $1.93 per barrel) compared to $43.59 per barrel in 2004 (including realized hedging losses of $4.75 per barrel). Natural gas prices also improved on a year over year basis averaging $8.93/mcf for 2005 compared to $6.86 for 2004. During 2005, Duvernay estimates that natural gas marketing operational performance combined with natural gas hedges have yielded the company $2.2 million ($0.12/mcf) in additional gross revenue over the comparable monthly indices. Prices are summarized as follows:



Duvernay Realized Prices

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

Three Months Ended Year Ended
Dec - 31 Dec - 31
--------------------------- ---------------------------
% %
2005 2004 change 2005 2004 change
---------- -------- ------- --------- --------- -------

Crude Oil and
Liquids $ 59.86 $ 42.81 40 $ 55.73 $ 43.59 28

Natural Gas $ 10.72 $ 7.12 51 $ 8.93 $ 6.86 30

Price/boe $ 63.40 $ 42.74 48 $ 54.02 $ 41.69 30

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


Benchmark Oil and Gas Prices

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

Three Months Ended Year Ended
Dec - 31 Dec - 31
--------------------------- ---------------------------
% %
2005 2004 change 2005 2004 change
---------- -------- ------- --------- --------- -------
Oil
NYMEX U.S. $ 60.05 $ 48.27 24 $ 56.70 $ 41.47 37
Edmonton Par Cdn. $ 72.22 $ 58.03 25 $ 69.85 $ 53.27 31
Natural Gas
NYMEX U.S. $ 12.88 $ 7.26 77 9.00 6.18 46
A.E.C.O. Cdn $ 11.61 $ 6.73 73 8.81 6.59 34
Currency $ .8521 $ .8198 4 $ .8256 $ .7688 7

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


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

Three Months Ended Year Ended
Dec - 31 Dec - 31
---------------------- ----------------------
2005 2004 2005 2004
---------- ---------- ---------- ----------

Revenue(1): ($ thousands)

Oil and NGL's $ 16,458 $ 6,081 $ 47,866 $ 24,407
Hedge (730) (932) (2,533) (2,398)
---------------------- ----------------------
$ 15,728 $ 5,149 $ 45,333 $ 22,009

Natural Gas 63,609 23,454 161,078 71,621

Processing & Rental Income 796 490 2,227 1,346
---------------------- ----------------------

Gross Revenue(1) $ 80,133 $ 29,093 $208,638 $ 94,976

Interest Income - (56) - -
---------------------- ----------------------

Total Revenue(1) $ 80,133 $ 29,037 $208,638 $ 94,976

(1) Revenue is reduced by transportation costs

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


Duvernay's royalties are summarized as follows:

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

Three Months Ended Year Ended
Dec - 31 Dec - 31
---------------------- ----------------------
2005 2004 2005 2004
---------- ---------- ---------- ----------

Royalties: ($ thousands)

Oil and Liquids $ 4,114 $ 1,164 $ 10,787 $ 4,993
Natural Gas 11,973 2,969 31,185 13,517
ARTC (125) (525) (500)
---------------------- ----------------------

$ 15,962 $ 4,133 $ 41,447 $ 18,010

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


For the year ended December 31, 2005 the average effective royalty rate was 20% compared to 19% for the same period in 2004. The rate has held constant as the Corporation continues to benefit from deep gas royalty holidays on new wells in Alberta and the benefits realized through the British Columbia low productivity natural gas well program. Duvernay 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 Corporation had an effective royalty rate of 20% compared to 14% for the same quarter in 2004. Duvernay has applied for royalty holidays on 26 wells which have approximately a $2 million royalty refund due to Duvernay when these applications are approved.

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 on a barrel of oil equivalent basis went from $5.37/boe in 2004 to $5.60/boe in 2005. Total operating expenses for 2005 were $21.4 million compared to $12.1 million for 2004. This absolute increase is entirely attributable to increases in production volumes. For the fourth quarter of 2005, operating expenses were relatively unchanged compared to the same quarter in 2004 ($5.74/boe compared to $5.67/boe). For 2005, The Corporation managed to keep unit operating costs in check in spite of having to deal with inflationary pressures arising from competition for many field services. On a barrel of oil equivalent basis, third party processing, treating and compression costs rose to $1.55 up from $1.40 in 2004, representing 28% of total operating expenses. Early in 2006, 15 mmcf/d of gas flowing through third party facilities has been rerouted into the Duvernay owned Cecilia gas plant. This initiative, combined with new incremental volumes going into Duvernay owned and operated facilities is expected to bring unit operating expenses down in 2006.



General & Administrative Expenses

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

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

Three Months Ended Year Ended
Dec - 31 Dec - 31
---------------------- ----------------------
($ thousands) 2005 2004 2005 2004
---------- ---------- ---------- ----------

General & Administrative
Expenses $ 3,799 $ 2,828 $ 11,234 $ 7,718
Administrative and
Operating Recovery (285) (98) (1,288) (457)
Capital Recovery (1,615) (687) (4,718) (1,962)
Capitalized G&A (600) (607) (1,707) (1,747)
Stock Based Compensation 1,477 413 3,881 1,165
---------------------- ----------------------
$ 2,776 $ 1,849 $ 7,402 $ 4,717

$/boe $ 2.22 $ 2.76 $ 1.94 $ 2.10

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


General and administrative expenses for the twelve months ending December 31, 2005 increased to $7.4 million from $4.7 million for the same period in 2004. On a per unit of production basis, the rate decreased from $2.10/boe in 2004 to $1.94 in 2005. On a cash basis, G&A for 2005 dropped to $0.92/boe from $1.58/boe in 2004 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 2004. Fourth quarter 2005 G&A cash costs of $1.04 per boe are significantly lower than the same quarter for 2004 of $2.15 per boe. The Corporation's strong performance in the equity markets combined with the issuance of 1.3 million stock options in 2005, drove stock based compensation costs for 2005 up by 233% to $3.9 million. On a barrel of oil equivalent basis, this non cash cost increased to $1.02/boe from $0.52/boe in 2004.

Depletion, Depreciation and Accretion

Depletion, depreciation and site restoration expense increased to $60.1 million during 2005 from $27.2 million during 2004. On a dollars per boe basis, full year unit of production DD&A increased in 2005 to $15.73 from $12.12 in 2004, an increase of 30%. The rate increase is primarily attributable to large 2005 investments in facilities (22% of total capital compared to 15% in 2004). The 2006 capital program contemplates dedicating 78% of total capital to drilling and completions. For the fourth quarter of 2005 the DD&A rate of $19.82/boe is compared to $15.47 for the fourth quarter of 2004. The increase in rate is primarily attributable to the high level of facilities spending in the fourth quarter combined with higher than anticipated future development costs associated with proved reserves.

Income Taxes

Duvernay did not incur any cash tax expense in 2005 other than Large Corporation Tax, which totaled $1,228,000. Other than Large Corporation Tax Duvernay does not expect to pay any cash taxes in 2006 based on existing tax pools, planned capital expenditures and the most recent forecast of 2006 taxable income. Although current tax horizons depend on product prices, production levels, and the nature, magnitude and timing of capital spending, the Corporation currently believes that no cash income tax will be payable for 1-2 years. Duvernay's tax pools at December 31, 2005 and December 31, 2004 are as follows:



Maximum 2005 2004
Deduction % ($ millions) ($ millions)


COPGE 10 $ 71 $ 52
CDE 30 $249 $ 99
CEE 100 $ 83 $ 81
UCC 25 $165 $ 59
Other $ 10 $ 7
$578 $298
----------- -----------
----------- -----------


The future income tax provision for the fourth quarter of 2005 was 31% of pre tax income compared to 24% for the same period in 2004. The fourth quarter 2004 effective rate was low for two reasons. The first factor is that Duvernay enjoyed a lower crown royalty rate than originally forecast resulting in lower crown royalty rates compared to the resource allowance. The Corporation 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 130% to $137.5 million ($2.81 per diluted Equity Share) for the twelve months ending December 31, 2005 from $59.7 million ($1.41 per diluted Equity Share) for the comparable period in 2004 due to the combination of growth in production volumes and stronger operating netbacks which improved by 33% averaging $37.57/boe compared to $28.30 for 2004. Full year funds from operations guidance announced in November of 2005 was $148 million ($2.98/diluted share) which was 7% higher than actual results, primarily due to full year production of 10,469 boe/d being slightly lower than November 2005 guidance of 10,700 boe/d. After tax earnings improved by 147% for 2005 to $50.1 million when compared to 2004 of $20.3 million. On a per share basis, diluted earnings improved by 113% to $1.02 per share for 2005 compared to $0.48 for 2004.



Three Months Ended Year Ended
Dec - 31 Dec - 31
--------------------------- ---------------------------
% %
2005 2004 change 2005 2004 change
---------- -------- ------- --------- --------- -------

Funds from
Operations per
Equity Share (1) $ 1.04 $ 0.42 148% $ 2.81 $ 1.41 99%
Earnings per
Equity Share (1) $ 0.35 $ 0.14 150% $ 1.02 $ 0.48 113%
Operating
Netback per boe $44.90 $30.89 45% $37.57 $28.30 32%

note:
(1) diluted

Liquidity and Capital Resources

Duvernay invested $463.3 million in 2005 compared to $179.7 million in
2004, as set out in the following table.

Year Ended
Dec - 31
-----------
2005 2004
------------- --------------
($ thousands) ($ thousands)

Land and seismic 46,587 19,186
Drilling and completions 289,928 131,817
Facilities 103,224 26,824
Property Acquisitions 52,908 (88)
Property Dispositions (31,262)
Other 1,867 1,952
----------------------------
Total $463,252 $179,691


Duvernay participated in the following equity financings during 2005, the proceeds from which were dedicated to an expanded capital spending program:



April flow through-private placement 1,150,000 $35.50 $40,825,000
June common-short term prospectus 1,800,000 $27.75 $49,950,000
October flow through-private placement 800,000 $52.00 $41,600,000


The Corporation estimates that it has completed its commitment to invest $40.8 million in exploration spending from the April 2005 flow through and that $32.5 million of the October 2005 flow through has been spent by December 31, 2005.

During the year, the Corporation also issued 710,000 common shares as consideration for the purchase of 2 producing properties.

At December 31, 2005, Duvernay had a working capital deficiency of $40.2 million and the bank line was drawn to $175.5 million for net debt of $215.7 million or 1.56 times annual trailing funds from operations. In January 2006, the Corporation finalized the expansion of its credit facility from $200 million to $250 million. The credit facility is an arrangement with a Canadian chartered bank bearing interest on a variable grid currently 95 basis points over the prevailing bankers' acceptance rate. Security for the facility includes a general security and a $500 million demand loan debenture secured by a first floating charge over all assets.

Duvernay also completed a short form prospectus equity financing for $55.6 million by issuing 1,250,000 common shares at $44.50 per share. This equity financing completed in January 2006 improved Duvernay's balance sheet resulting in pro forma net debt of approximately $160 million or 1.15 times trailing funds from operations.

The Corporation's average interest rate on borrowed funds increased slightly in 2005 to 4.55% from 4.34% in 2004.

During 2005, Duvernay drilled 126 gross (85.7 net) wells, with a success rate of 97% resulting in 4 oil wells, 120 gas wells, and 2 suspended or abandoned wells. In addition a new gas plant in the Cecilia area of the Alberta Deep Basin was commissioned with capability to process 50 mmcf/d of sales natural gas, 100% owned by Duvernay. In the second quarter of 2006, Duvernay is scheduled to complete construction of a 50 mmcf/d gas plant expansion at Cecilia along with two new plants in North East BC to process 25 mmcf/d of Doig and Cadomin gas.

The Corporation invested $103 million in 2005 in facilities and infrastructure $78 million of which is dedicated to the Alberta Deep Basin in order to serve the reserves assigned in this region as well to support future growth. Duvernay also continued to grow its undeveloped land base aggressively by spending $39.2 million at Crown land sales resulting in 67,000 gross acres (56,000 net) primarily in the Alberta Deep Basin and the Cadomin and Doig resource play of North East BC.

Duvernay's base capital budget for 2006 is $400 million with approximately $90 million allocated to exploration activities and approximately $310 million allocated to development drilling and facilities. The 2006 budget contemplates drilling 168 wells for $316 million, or 78% of the 2006 capital program. This is in contrast to 2005 when $290 million was invested in drilling or 63% of total capital spending. This capital program will be funded through a combination of cash flow and bank debt.

The Corporation currently forecasts 2006 Funds from Operations to be $250 - $300 million depending on product prices, with the balance being funded from bank debt.

As at December 31, 2005, the Corporation had issued and outstanding common shares of 49,345,308 and outstanding stock options of 4,653,284. As at March 22, 2006 the Corporation had issued and outstanding common shares of 51,204,808 and outstanding stock options of 4,173,784.

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 2005 and 2006 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 most significant risk with the commodity hedges is that the prevailing product prices are higher than those committed to in the hedging contract. The Corporation partially mitigates this risk by including collars in its hedging portfolio. A less significant risk relates to the Corporation's ability to supply the production at future dates. This risk is managed by keeping the percentage of total budgeted production below 25% and by entering into the hedging contracts at multiple delivery points.

During 2005, the Corporation's Petroleum and Natural gas sales of $213.0 million included realized hedging losses of $333,000. At the end of 2005, Duvernay assessed the prevailing market value of similar contracts to those that were unsettled at year end and has estimated a net cost to settle these instruments to be approximately $1.2 million. Completing a similar assessment at February 28, 2006 results in a receipt to the Corporation of $11.7 million due to gas price erosion in the first two months of 2006.



Type of Quantity
Time Period Contract Control Contract Price
------------------------------------------------------------------------
2006 January-June Put (floor) 100 bbls/day $50.00 U.S. W.T.I.
2006 January-March Put (floor) 100 bbls/day $50.00 U.S. W.T.I.
2006 April-June Put (floor) 100 bbls/day $50.00 U.S. W.T.I.
2006 July-September Put (floor) 100 bbls/day $50.00 U.S. W.T.I.


2006 January-March Physical (Swap) 15,000 gj's/day $ 9.05 Cdn/gj
average
2006 April-October Physical (Swap) 5,000 gj's/day $ 9.32 Cdn/gj
2006 January-March Put (floor) 5,000 gj's/day $ 9.00 Cdn/gj
2006 January-March Put (floor) 2,000 gj's/day $12.00 Cdn/gj
2006 April-October Call (Ceiling) 5,000 gj's/day $9.65 Cdn/gj
2006 April-October Call (Ceiling) 2,000 gj's/day $12.45 Cdn/gj
2006 April-October Collar 2,000 gj's/day $6.86 Cdn/gj Floor
$9.66 Cdn/gj Ceiling
2006 April-October Collar 3,000 gj's/day $10.00 Cdn/gj Floor
$11.00 Cdn/gj Ceiling



Subsequent to the end of the year, the Corporation has not entered into
any other commodity hedging instruments.



DUVERNAY OIL CORP.
SELECTED QUARTERLY INFORMATION
2005 2005 2005 2005
Q4 Q3 Q2 Q1
-------------------------------------------

PRODUCTION
Crude oil and liquids (bbls) 262,755 197,497 205,527 147,723
Gas (mcf) 5,931,351 4,452,299 4,218,977 3,443,570
Oil equivalent (boe) 1,251,314 939,547 908,690 721,651

Crude oil and liquids
(bbls/d) 2,856 2,147 2,259 1,641
Gas (mcf/d) 64,471 48,395 46,362 38,262
Oil equivalent (boe/d) 13,601 10,212 9,986 8,018

FINANCIAL
($ thousands, except as noted)
Revenue, net of royalties
and transportation 64,170 42,898 33,217 26,906

Funds from operations 53,828 35,758 26,495 21,372
Per share basic 1.10 0.75 0.58 0.48


Net earnings 18,287 15,532 8,537 7,719
Per share basic 0.37 0.32 0.19 0.17
Per share diluted 0.35 0.31 0.18 0.16

Total Assets 827,263 672,868 548,268 474,245

Bank Debt 175,481 141,792 79,190 68,859

Cash and Working capital
(deficiency) (40,180) (28,005) (8,602) (52,366)

Basic Outstanding Shares 49,345 47,856 45,844 44,436

PER UNIT
Gas, net of transportation
($/mcf) 10.72 8.84 7.58 7.59

Crude oil and liquids,
net of transportation
($/bbl) 59.86 59.85 51.48 48.76

Revenue,
net of transportation
($/boe) 63.40 54.47 47.16 46.22




2004 2004 2004 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

Funds from operations 19,064 15,570 14,951 10,091
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



Duvernay's quarterly and annual 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
2005 2004 2003 2002
Year Year Year Year
-------------------------------------------
(restated)
PRODUCTION
Crude oil and liquids (bbls) 1,313,626 504,860 540,590 420,668
Gas (mcf) 16,600,461 10,446,068 3,819,328 626,968
Oil equivalent (boe) 3,821,202 2,245,871 1,177,145 525,163

Crude oil and liquids
(bbls/d) 2,229 1,379 1,481 1,153
Gas (mcf/d) 49,442 28,541 10,464 1,718
Oil equivalent (boe/d) 10,469 6,136 3,225 1,439

FINANCIAL
($ thousands, except as
noted)
Revenue, net of royalties 167,191 76,966 36,736 15,130

Funds from operations 137,454 59,675 25,472 9,963
Per share basic 2.94 1.47 0.84 0.37


Net earnings 50,075 20,254 8,032 2,136
Per share basic 1.07 0.50 0.26 0.08
Per share diluted 1.02 0.48 0.25 0.08

Total Assets 827,263 393,440 220,546 101,438

Total Long Term Financial
Liabilities 175,481 67,126 48,564 2,378

Cash and Working capital
(deficiency) (40,180) (13,439) (15,942) 23,651

Basic Outstanding Shares 49,345 40,645 30,396 26,700

PER UNIT
Gas ($/mcf) 8.93 6.86 6.54 5.25

Crude oil and liquids
($/bbl) 55.73 43.59 39.11 36.42

Revenue ($/boe) 54.02 41.69 39.59 35.45

Operating netback ($/boe) 37.57 28.30 23.86 19.17


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.


Less than 1-3 4-5
Payments due by period Total 1 year years years Thereafter
($ millions)
Long-term debt $ 175.5 $ - $ 175.5 $ - $ -
Operating leases 1.9 0.5 1.1 0.3 -
Firm transportation
agreements 6.4 2.5 3.6 0.3 -
$ 183.8 $ 3.0 $ 180.2 $ 0.6 $ -



Drilling Results

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



2005 2004
--------------------------------------
Gross Net Gross Net
--------------------------------------


Crude Oil 4 3.2 7 2.0
Natural gas 120 80.7 65 44.6
Suspended 1 0.9 1 0.5
Dry and abandoned 1 1 4 2.4
------------------------------------------------------------------------
Total wells 126 85.8 77 49.5



Landholdings

Duvernay's developed and undeveloped landholdings as at December 31,
2004 and 2005 are set forth below:


Undeveloped Developed Total
----------------------------------------------------
(Acres) Gross Net Gross Net Gross Net
----------------------------------------------------

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


2005
-----------------
Alberta 242,092 155,083 108,883 57,944 350,975 213,027
British Columbia 149,824 105,165 58,439 34,974 208,263 140,139
------------------------------------------------------------------------
Total 391,916 260,248 167,322 92,918 559,238 353,166


CRITICAL ACCOUNTING ESTIMATES

The financial statements have been prepared in accordance with Canadian GAAP. A summary of significant accounting policies is 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 proved 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 obligation 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. Abandonment costs per well are estimated to be $50,000 and are assumed to be incurred over a 6 year period commencing in 2010. Site by site estimates are added for significant facilities. Costs are inflated by 3% per year and a discount rate of 7% is assumed.

Income Taxes

The determination of the Corporation'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.

Expected Changes in Accounting Policies

Financial Instruments and Measurements

In April 2005, a series of new accounting standards were released which established guidance for the recognition and measurement of financial instruments. These new standards include Section 1530 "Comprehensive Income", Section 3855 "Financial Instruments - Recognition and Measurement", and Section 3865 "Hedges". The new standards also resulted in a number of significant consequential amendments to other accounting standards to accommodate the new sections. The standards require all applicable financial instruments to be classified into one of several categories including: financial assets and financial liabilities held for trading, held-to-maturity investments, loans and receivables, available-for-sale financial assets, or other financial liabilities. The financial instruments are then included on a 's balance sheet and measured at fair value, cost or amortized value, depending on the classification. Subsequent measurement and recognition of changes in value of the financial instruments also depends on the initial classification. These standards are effective for interim and annual financial statements for fiscal years beginning on or after October 1, 2006 and must be implemented simultaneously. Duvernay has not yet assessed the full impact, if any, of these standards on the consolidated financial statements. However, the Company anticipates adoption of the new standards on January 1, 2007.

DC&P Disclosure

Disclosure Controls and Procedures are controls and procedures designed and implemented by, or under the supervision of the issuer's Chief Executive Officer ("CEO") and Chief Financial Officer ("CFO") to ensure that material information relating to the issuer is communicated to them by others in the organization as it becomes known and is appropriately disclosed as required under the continuous disclosure requirements of securities legislation. In essence, these types of controls are related to the quality and timeliness of financial and non-financial information in securities filings. An evaluation of the effectiveness of the design and operation of our disclosure controls and procedures was conducted as of December 31, 2005, by and under the supervision of Duvernay's management, including the CEO and CFO. Based on this evaluation, the CEO and CFO have concluded that the Corporation's disclosure controls and procedures, as defined in Multilateral Instrument 52-109, Certification of Disclosure in Issuers' Annual and Interim Filings, are effective to ensure that information required to be disclosed in reports that we file or submit under Canadian securities legislation is recorded, processed, summarized and reported within the time periods specified in those rules and forms. It should be noted that while the Corporation's Chief Executive Officer and Chief Financial Officer believe that the Corporation's disclosure controls and procedures provide a reasonable level of assurance that they are effective, they do not expect that the disclosure controls and procedures will prevent all errors and fraud.

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 about Duvernay Oil Corp. may be found in documents filed on SEDAR at www.sedar.com which are also available on Duvernay's website www.duvernayoil.com.


Financial Statements of

DUVERNAY OIL CORP.

Years ended December 31, 2005 and 2004



DUVERNAY OIL CORP.
Balance Sheets

December 31, 2005 and 2004
(Thousands of Dollars)

------------------------------------------------------------------------
------------------------------------------------------------------------
2005 2004
------------------------------------------------------------------------

Assets

Current assets:
Cash and cash equivalents $ - $ 143
Accounts receivable 58,215 30,920
Prepaid expenses and deposits 530 962
------------------------------------------------------------------------
58,745 32,025

Property, plant and equipment
(note 2) 768,518 361,415

------------------------------------------------------------------------
$ 827,263 $ 393,440
------------------------------------------------------------------------
------------------------------------------------------------------------

Liabilities and Shareholders' Equity

Current liabilities:
Accounts payable and accrued
liabilities 98,925 45,464
------------------------------------------------------------------------
98,925 45,464

Long-term debt (note 3) 175,481 40,724

Asset retirement obligation (note 4) 9,491 5,849

Future income tax (note 6) 61,054 20,553

Shareholders' equity:
Share capital (note 5) 396,450 248,651
Contributed surplus (note 5) 4,915 1,327
Retained earnings 80,947 30,872
------------------------------------------------------------------------
482,312 280,850
Subsequent event (note 5)
------------------------------------------------------------------------
$ 827,263 $ 393,440
------------------------------------------------------------------------
------------------------------------------------------------------------

See accompanying notes to financial statements.



DUVERNAY OIL CORP.
Statements of Earnings and Retained Earnings

Years ended December 31, 2005 and 2004
(Thousands of Dollars, Except Per Share Amounts)

------------------------------------------------------------------------
------------------------------------------------------------------------
2005 2004
------------------------------------------------------------------------

Revenue:
Petroleum and natural gas $ 212,967 $ 96,692
Royalties (41,447) (18,010)
Transportation (4,329) (1,716)
------------------------------------------------------------------------
167,191 76,966

Expenses:
Operating 21,396 12,069
General and administration 3,521 3,552
Stock-based compensation 3,881 1,165
Interest 3,592 926
Depletion, depreciation and accretion 60,091 27,237
------------------------------------------------------------------------
92,481 44,949

------------------------------------------------------------------------
Earnings before taxes 74,710 32,017

Taxes (note 6):
Capital 1,228 743
Future 23,407 11,019
------------------------------------------------------------------------
24,635 11,762

------------------------------------------------------------------------
Net earnings 50,075 20,255

Retained earnings, beginning of year 30,872 10,617

------------------------------------------------------------------------
Retained earnings, end of year $ 80,947 $ 30,872
------------------------------------------------------------------------
------------------------------------------------------------------------

Earnings per share:
Basic $ 1.07 $ 0.50
Diluted $ 1.02 $ 0.48
------------------------------------------------------------------------
------------------------------------------------------------------------

See accompanying notes to financial statements.


DUVERNAY OIL CORP.
Statements of Cash Flows

Years ended December 31, 2005 and 2004
(Thousands of Dollars)

------------------------------------------------------------------------
------------------------------------------------------------------------
2005 2004
------------------------------------------------------------------------

Cash provided by (used in):

Operations:
Net earnings $ 50,075 $ 20,255
Items not involving cash:
Depletion, depreciation,
and accretion 60,091 27,237
Stock-based compensation 3,881 1,165
Future income taxes 23,407 11,019
Abandonment expenditures (300) -
Change in non-cash operating
working capital (note 8) (15,301) (1,959)
------------------------------------------------------------------------
121,853 57,717

Financing:
Issue of common shares,
net of share issue costs 127,656 114,462
Increase in long-term debt 134,757 8,058
------------------------------------------------------------------------
262,413 122,520

Investments:
Additions to property, plant,
and equipment (441,822) (179,779)
Property acquisitions (15,748) -
Property dispositions 31,262 87
Change in non-cash working capital
(note 8) 41,899 217
------------------------------------------------------------------------
(384,409) (179,475)

------------------------------------------------------------------------
Increase (decrease) in cash (143) 762

Cash (bank indebtedness), beginning
of year 143 (619)

------------------------------------------------------------------------
Cash, end of year $ - $ 143
------------------------------------------------------------------------
------------------------------------------------------------------------

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, 2005 and 2004

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, asset retirement costs 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 estimated 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.

(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 asset and 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 Corporation 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. The 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) 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 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.

(j) 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.

(k) Revenue recognition:

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

(l) Comparative information:

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



2. Capital assets:

------------------------------------------------------------------------
------------------------------------------------------------------------
Accumulated Net book
2005 Cost depreciation value
------------------------------------------------------------------------
Petroleum and natural
gas properties $ 804,587,499 98,787,733 705,799,766
Gas processing facilities 67,292,986 4,868,206 62,424,780
Furniture, fixtures and
leasehold improvements 676,394 383,012 293,382
------------------------------------------------------------------------
$ 872,556,879 104,038,951 768,517,928
------------------------------------------------------------------------
------------------------------------------------------------------------

2004
------------------------------------------------------------------------
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
------------------------------------------------------------------------
------------------------------------------------------------------------


The cost of unproven lands at December 31, 2005 of $114,239,000 (2004 - $51,005,000) has been excluded from the depletion calculation. Future development costs of proven reserves in 2005 of $156,997,000 (2004 - $67,408,000) have been included in the depletion calculation.

General and administrative expenditures of $1,707,000 (2004 - $1,750,000) have been capitalized and included as costs of petroleum and natural gas properties.

At December 31, 2005, the Corporation applied a ceiling test to its petroleum and natural gas assets using expected future market prices of:



Benchmark reference
price forecast 2006 2007 2008 2009 2010 2011-2016
WTI ($US/bbl) 57.00 55.00 51.00 48.00 46.50 46.54
AECO ($Cdn/mcf) 10.60 9.25 8.00 7.50 7.20 7.17


After 2016 the price forecast for WTI and AECO escalate at 2% per year to the end of the reserve life.

3. Long-term debt:

The Corporation has a financing arrangement with a Canadian chartered bank for an extendible revolving term loan in the amount of $250 million. As at December 31, 2005, $175,481,417 (2004 - $40,724,440) of this term loan was drawn. The facility bears interest on a variable grid currently 95 basis points over the prevailing bankers' acceptance rate. Security for the facility includes a general security agreement and a $500 million demand loan debenture secured by a first floating charge over all assets. In May 2006, at the Corporation'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 Corporation and subject to approval by the bank. The Corporation is required to meet certain financial based covenants to maintain the facility.

4. 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 $17,775,135 (2004 - $10,592,000) which will be incurred between 2010 and 2017. A credit-adjusted risk-free rate of 7% and an inflation rate of 3% was used to calculate the fair value of the asset retirement obligations.



A reconciliation of the asset retirement obligations is provided below:

------------------------------------------------------------------------
------------------------------------------------------------------------
2005 2004
------------------------------------------------------------------------
Balance, beginning of period $ 5,848,599 $ 3,916,015
Accretion expense 640,530 382,619
Liabilities incurred 3,301,848 1,549,965
Liabilities settled (300,000) -
------------------------------------------------------------------------
Balance, end of period $ 9,490,977 $ 5,848,599


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, 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
For cash on private placement of flow
through shares 1,950,000 82,425,000
For cash on public share issue 1,800,000 49,950,000
For cash on exercise of stock options 598,384 2,427,451
For acquisition of properties 710,000 26,015,000
Contributed surplus on exercise of stock
options - 293,358
Share issue costs - (7,146,011)
Tax effect on share issue costs - 2,415,000
Tax effect on flow through renunciation - (8,581,000)
------------------------------------------------------------------------
Balance, December 31, 2005 49,345,308 $396,449,690
------------------------------------------------------------------------
------------------------------------------------------------------------


(b) Common shares issued (continued):

In 2005 the Corporation issued 110,000 common shares to a company controlled by a director of Duvernay to purchase producing properties and 600,000 shares to an unrelated private oil and gas company to acquire their working interest in an area operated by the Corporation. The assets have been recorded at a value of $36,943,000, including $10,928,000 of future income tax liability.

On February 9, 2006, the Corporation completed a bought-deal private placement of 1,250,000 common shares at $44.50 per share for gross proceeds of $55,625,000.

(c) Flow Through Shares:

On April 5, 2005 Duvernay issued 1,150,000 common shares on a flow through basis at an issue price of $35.50 per share for gross proceeds of $40.825 million. On October 18, 2005 the Corporation issued 800,000 common shares on a flow through basis at an issue price of $52.00 for gross proceeds of $41.6 million. Effective December 31, 2005 the Corporation renounced $82.425 million to be incurred on qualifying expenditures on or before December 31, 2006. During the year ending December 31, 2005 Duvernay fulfilled its remaining obligation of $12.7 million of capital expenditures related to its 2004 flow through offering of $25.2 million and has a commitment to renounce $82.425 million relating to its 2005 flow through offering by December 31, 2006.



(d) Contributed surplus:

------------------------------------------------------------------------
------------------------------------------------------------------------
2005 2004
------------------------------------------------------------------------
Contributed surplus, December 31, 2004 $1,327,450 $ 260,881
Stock-based compensation 3,880,700 1,165,066
Exercise of stock options (293,358) (98,497)
------------------------------------------------------------------------
Contributed surplus, December 31, 2005 $4,914,792 $ 1,327,450
------------------------------------------------------------------------
------------------------------------------------------------------------


(e) Stock options:

The Corporation has a rolling stock option plan. Under the employee stock option plan, the Corporation may grant options to its employees for up to 4,934,531 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:

------------------------------------------------------------------------
------------------------------------------------------------------------
2005 2004
---------------------- ----------------------
Weighted Weighted
average average
Number of exercise Number of exercise
options price options price
------------------------------------------------------------------------
Stock options outstanding,
beginning of year 3,924,168 $ 6.55 3,430,000 $ 4.33
Granted 1,327,500 33.07 792,500 15.12
Exercised (598,384) 4.06 (291,666) 3.84
Forfeitures - (6,666) 3.50
------------------------------------------------------------------------
Stock options outstanding,
end of year 4,653,284 $ 14.44 3,924,168 $ 6.55
------------------------------------------------------------------------
------------------------------------------------------------------------
Exercisable, end of year 2,392,451 $ 5.40 2,075,001 $ 3.91
------------------------------------------------------------------------
------------------------------------------------------------------------


------------------------------------------------------------------------
------------------------------------------------------------------------
Options Outstanding Options Exercisable
------------------------------------------------------------------------
Weighted
Average
Range of Weighted Remaining Weighted
Exercise Number Average Contractual Number Average
Prices Outstanding Price Life (years) Exercisable Price
------------------------------------------------------------------------

$ 3.50-6.25 2,557,951 4.54 1.93 2,152,951 4.30
10.90-17.18 767,833 15.18 3.77 239,500 15.31
25.20-38.38 1,327,500 33.07 4.63 -
------------------------------------------------------------------------
4,653,284 3.00 2,392,451 5.40


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:



------------------------------------------------------------------------
Risk-free interest rate (%) 4.5
Expected life (in years) 3.5
Expected volatility (%) 40-50
Expected dividend -
Expected forfeitures (%) 10
------------------------------------------------------------------------


The weighted average fair value of the stock options granted during the year was $11.53 (2004 - $4.76) per option.

(f) 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, 2005 was 46,832,318 (2004 - 40,644,585).

In computing diluted earnings per share for the period ended December 31, 2005, 2,118,880 (2004 - 1,762,697) shares were added to the weighted average number of common shares outstanding for the dilution 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:



------------------------------------------------------------------------
2005 2004
------------------------------------------------------------------------
Earnings before taxes $ 74,710,621 $ 32,016,413
------------------------------------------------------------------------
------------------------------------------------------------------------

Combined federal and provincial tax rate 37.8% 39.75%

Computed "expected" income tax expense $ 28,236,879 $ 12,726,524

Increase (decrease) resulting from:
Non-deductible crown charges 9,080,932 4,689,952
Resource allowance (11,361,538) (5,165,603)
Effect of change in tax rate (4,083,000) (1,102,762)
Stock Based Compensation 1,466,711 463,114
Other 67,116 (592,225)
------------------------------------------------------------------------
Future income taxes 23,407,100 11,019,000

Capital taxes 1,228,000 743,000
------------------------------------------------------------------------
$ 24,635,100 $ 11,762,000
------------------------------------------------------------------------
------------------------------------------------------------------------


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

------------------------------------------------------------------------
2005 2004
------------------------------------------------------------------------
Future tax assets:
Asset retirement obligation $ 3,207,000 $ 2,088,000
Share issue expenses 3,550,000 2,462,000
------------------------------------------------------------------------
6,757,000 4,550,000
Future tax liabilities:
Property, plant and equipment (67,811,000) (25,103,000)
------------------------------------------------------------------------

Net future tax liability $ (61,054,000) $ (20,553,000)
------------------------------------------------------------------------
------------------------------------------------------------------------


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, 2005, the Corporation had fixed the price applicable to future production as follows:



------------------------------------------------------------------------
Type of Quantity
Time Period Contract Control Contract Price
------------------------------------------------------------------------
------------------------------------------------------------------------
2006 January-June Put (floor) 100 bbls/day $50.00 U.S. W.T.I.
2006 January-March Put (floor) 100 bbls/day $50.00 U.S. W.T.I.
2006 April-June Put (floor) 100 bbls/day $50.00 U.S. W.T.I.
2006 July-September Put (floor) 100 bbls/day $50.00 U.S. W.T.I.
2006 January-March Physical (Swap) 15,000 gj's/day $9.05 Cdn/gj average
2006 April-October Physical (Swap) 5,000 gj's/day $9.32 Cdn/gj average
2006 January-March Put (floor) 5,000 gj's/day $9.00 Cdn/gj
2006 January-March Put (floor) 2,000 gj's/day $12.00 Cdn/gj
2006 April-October Call (Ceiling) 5,000 gj's/day $9.65 Cdn/gj
2006 April-October Call (Ceiling) 2,000 gj's/day $12.45 Cdn/gj
2006 April-October Collar 2,000 gj's/day $6.86 Cdn/gj Floor
$9.66 Cdn/gj Ceiling
2006 April-October Collar 3,000 gj's/day $10.00 Cdn/gj Floor
$11.00 Cdn/gj Ceiling

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


If the contracts were terminated at December 31, 2005, the Corporation
would have to pay $1.2 million.

8. Supplemental Cash Flow Information:

2005 2004
------------------------------------------------------------------------
Accounts receivable $ (27,295) $ (19,040)
Prepaid expenses 432 676
Accounts payable and accrued liabilities 53,461 16,622
------------------------------------------------------------------------
Change in non-cash working capital $ 26,598 $ (1,742)
------------------------------------------------------------------------
------------------------------------------------------------------------
Relating to:
Operations $ (15,301) $ (1,959)
Investments 41,899 217
------------------------------------------------------------------------
Change in non-cash working capital $ 26,598 $ (1,742)
------------------------------------------------------------------------
------------------------------------------------------------------------
Interest and Taxes Paid:
------------------------------------------------------------------------
Interest Paid $ (3,402,583) $ (926,636)
Taxes Paid (899,172) (445,945)
------------------------------------------------------------------------
------------------------------------------------------------------------


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 except as required by applicable securities law.

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.)

The aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserves additions for that year.

Additional information on these and other risks is contained in Duvernay's Annual Information Form and other disclosure documents filed on SEDAR at www.SEDAR.com and on Duvernay's website at www.duvernayoil.com.

Contact Information

  • 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