Duvernay Oil Corp.
TSX : DDV

Duvernay Oil Corp.

March 22, 2007 15:11 ET

Duvernay Enjoys Record 2006

CALGARY, ALBERTA--(CCNMatthews - March 22, 2007) - Duvernay Oil Corp. (TSX:DDV) is pleased to announce very strong 2006 financial and operating results.

Highlights

2006 proved plus probable reserve additions of 39.8 mmboe yielding a 2006 year end total of 101 mmboe added at a cost of $13.44/boe.

Proved producing reserves were increased by 68%, total proved reserves increased by 59%, proved plus probable reserves were increased by 51% in 2006, net of production.

Production replacement of 690% on a proved plus probable basis and 510% on a proved basis.

Production was increased by 51% in 2006 over 2005, comparable to the greater than 50% growth in all reserve categories during 2006.

Record fourth quarter production of 18,230 boe/d, an increase of 14% over third quarter 2006.

Record cash flow in the fourth quarter of $55.8 million ($1.03 per diluted share).

Top decile operating costs in 2006 of $5.51/boe and G and A cash costs of ($0.62/boe) yielding a strong unit operating net-back of $33.42/boe.

The Company drilled 126 wells in 2006 with a 98% success rate.

Completion of major gas facility infrastructure construction projects in both core complexes with a year end development drilling inventory in excess of 1400 locations.

Financial Results and Outlook

Duvernay delivered record financial results in 2006. Cash flow of $184.2 million ($3.45 per diluted share) compared to 2005 of $137.5 million ($2.81 per diluted share) increased by 34% (23% on a per share basis) in a climate where Canadian natural gas prices deteriorated by 26%. Similarly earnings of $58.4 million ($1.09 per diluted share) reached record levels when compared to $50.1 million ($1.02 per diluted share) achieved in 2005.

Unit netbacks for 2006 of $33.42 /boe are amongst the strongest in the industry. Continued cost control discipline has resulted in operating costs of $5.51/boe down from $5.60/boe for 2005 in a climate of intense competition for field services. The Company is expecting operating costs of less than $5.00/boe in 2007. The Company's effective royalty rate of 15% is due to the benefits derived from various royalty relief programs in Alberta and B.C. Finally cash general and administrative costs averaged $0.62/boe in 2006 down by 33% from the 2005 level of $0.92/boe. Continued improvements in the overall cash cost structure positions the Company for strong profitability in 2007 even if lower natural gas prices persist.

Production Outlook

Fourth quarter 2006 production of 18,230 boe/d was 14% higher than third quarter 2006 and 34% higher than fourth quarter 2005. Full year 2006 average production of 15,806 boe/d was 51% higher than 2005 production of 10,469 boe/d. The Company disposed of a net 950 boe/d in 2006, primarily in the fourth quarter. Duvernay expects first and second quarter 2007 production growth to be at the higher end of the Company's 5-20% quarterly growth range target.

By operating 9-10 drilling rigs during the first quarter, the resulting inventory of new gas wells early in the year will allow the Company to maintain its strong production growth momentum. The Company expects to tie-in 52 new wells in the January-April time frame, with the majority of these tie-ins occurring in March.

Current production is 23,000 boe/d, the Company expects to average 26,000 boe/d for full year 2007.

2006 Reserves

During 2006 proved producing reserves were increased by 68% to 32.0 mmboe, total proved reserves were increased 59% to 63.6 mmboe net of production and proved plus probable reserves were increased 51% to 100.8 mmboe net of production. Net positive total proved technical revisions of 4.74 mmboe were realized in 2006, driven primarily by stronger performance from wellbores identified in the 2005 GLJ report in the Alberta Deep Basin.

Duvernay replaced 2006 production by 6.9 times on a proved plus probable basis and 5.1 times on a proved basis. Proved reserve life index is 11.0 years using average 2006 production. Proved plus probable reserve life index is 17.5 years using average 2006 production.

Total proved reserves were added at a cost of $ 18.19/boe prior to future capital and $24.89/boe including future capital. Proved plus probable costs reserve addition were $13.44/boe prior to future capital and $20.70/boe including future capital.

Future capital for Alberta Deep Basin wells was increased by 25% in the 2006 report reflecting the new drilling and multi-zone completion techniques employed. However, average per well proved undeveloped reserves are virtually unchanged from the 2005 report. The Company expects these per well proved reserves to increase in future years driven by the continually improving well performance observed in 2006.

During the first quarter of 2007, Duvernay has converted approximately 7.1 mmboe of year end proved non-producing and probable reserves to proved producing reserves.



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Finding, Development and Acquisition Costs
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(excluding future capital) (with future capital)
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2006
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Proved + Probable $ 13.44 $ 20.70
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Proved $ 18.19 $ 24.89
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Inception
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Proved + Probable $ 12.22 $ 17.24
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Proved $ 18.24 $ 22.86
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Reserves Summary January 2007

Company Interest (includes working interests and royalty interests)

2006

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

Proved
Producing 1,679 169,161 2,140 32,013

Proved non
producing 109 35,146 578 6,544
Proved
Undeveloped 1,520 130,009 1,897 25,086

TOTAL
PROVED 3,308 334,316 4,615 63,642

Probable 1,662 197,842 2,547 37,182

PROVED +
PROBABLE 4,969 532,158 7,162 100,825

2005

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

Proved
Producing 1,610 97,073 1,288 19,076 1,679

Proved non
producing 212 39,865 578 7,434 109
Proved
Undeveloped 556 71,559 1,019 13,503 1,520

TOTAL
PROVED 2,377 208,496 2,886 40,012 3,308

Probable 1,111 142,677 1,908 26,798 1,662

PROVED +
PROBABLE 3,488 351,173 4,793 66,810 4,969

Before Tax Net Present Value Summary January 2007
Company Interest (includes working interests and royalty interests)

Discount Rate
-------------

0% 5% 10%
---------------------------------------------

Proved Producing 1,096,321 817,330 662,016
Proved non producing 202,861 156,037 126,400

Proved Undeveloped 588,987 371,693 244,996
---------------------------------------------
TOTAL PROVED 1,888,169 1,345,060 1,033,412
Probable 1,255,473 678,862 426,798
---------------------------------------------
PROVED plus PROBABLE 3,143,642 2,023,922 1,460,210


Capital Program

2006 was the second year of a major capital program in the two core gas complexes involving a significant expansion of the existing development drilling inventories and construction of major gas infrastructure in both areas. With the inventories built and infrastructure complete, the 2007 EP capital program is focused almost entirely on drilling, completions and tie-ins. The 2007 capital budget is between $350 and $365 million compared to $534 million in 2006. This will allow Duvernay to continue with an eight to nine drilling rig program continuously through the balance of the year. The Company has spent $312 million on facilities, land and seismic in 2005-2006, the planned facilities and land expenditures in 2007 are $40 million. With the majority of the facility infrastructure already constructed in the two large project areas, the Company can focus 2007 capital on converting the enormous undrilled inventories into production and reserves. First half 2007 capital is estimated at $150.0 million with approximately $20.0 million expended on land and facilities. Expected first half cash flow is approximately $140.0 million. The 2007 capital spending program and profile allows the Company to operate within the existing $400.0 million line of credit with its banking syndicate. The 2006 reserve report however will allow Duvernay to pursue a significant borrowing base increase should incremental capital be required.

2007 EP Program Update

In 2006 Duvernay operated or participated in a total of 126 wells with an overall success rate of 98%. The Company participated in 124 wells in 2005 with a 97% success rate.

Duvernay operated between nine and 10 drilling rigs in the first quarter of 2007 and plans to operate between eight and nine rigs for the balance of the year. All of the drilling rigs are currently shut down for Spring break-up. The Company operated between 10 and 12 service rigs during the first quarter. Three are currently still active. Pipeline operations will continue in both large project areas until surface conditions prevent further access.

Sunset - Groundbirch, B.C.

Duvernay operated 33 wells in the Sunset-Groundbirch complex in 2006 with a 100% success rate.

Duvernay operated three drilling rigs in Sunset-Groundbirch during the first quarter yielding 12 new gas wells and one new oil well. The Sunset 15-21-80-18W6 Cecil horizontal well drilled into the Sunset unit tested oil at initial rates of 625 boe/d with no water. This is the first of several unit optimization opportunities that the Company can pursue since it consolidated unit interests in the fourth quarter of 2006.

The Company now has 75 wells drilled into the original Groundbirch Doig discovery and has an additional six new Doig pools to delineate and develop. Duvernay also has four successful new pool completions in both the Montney and Phosphate formations that will be the focus of further delineation in 2007.

The large 3D seismic at Sunset is now acquired, this survey will be utilized for the new pool Doig delineation drilling as well as finalizing the locations for the deep Paleozoic exploration tests beneath Sunset-Groundbirch.

Duvernay has negotiated several farm-ins in the Sunset-Groundbirch area thus far in 2007. These drilling based deals will net the company up to 107 sections of new lands in and around the existing core EP complex over the next two to three years. This will represent a 50% increase over existing Sunset-Groundbirch land holdings.

Production from the complex has reached 7,500 boe/d and will grow further with the start-up of the Brassey plant expansion, currently scheduled for late April.

Alberta Deep Basin

Duvernay operated or participated in 75 wells in the Alberta Deep Basin with a 100% success rate.

In the Alberta Deep Basin, Duvernay operated six drilling rigs and seven service rigs during the first quarter, yielding 24 new gas wells. Individual gas well performance continues to improve through the application of multi-zone completion/commingled production techniques. Significant production additions have been realized at Oldman, Wroe Creek and Fir during the past four weeks as these high rate wells are brought on-stream. Early break-up may delay the start-up of the Marsh-Pedley pipeline system through the expanded Obed compressor site until June. The 100% owned and operated Cecilia gas plant is capable of 120.0 mmcf/d and is expected to be full in the second quarter.

The 2007 deep Devonian Exploration program in the Deep Basin consists of three new pool tests including large volume gas prospects at Edson and greater Wild River.

Dawson - Puskwa, Alberta

At Dawson, Alberta, Duvernay has now drilled and successfully completed five wells into the Slave Point pool discovered in 2006 proving up a substantial new light oil pool. The 2-13 discovery well has produced steadily at rates of 250-300 boe/d since last April.

At Puskwa Alberta, the Company expects to drill several wells on its 45 section land base.

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, 2006 and comparative information included therein. This management's discussion and analysis is dated March 20, 2007.

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, 2006 compared to the Year ending December 31, 2005

Production

Production volumes for the year ended December 31, 2006 averaged 15,806 boe/d compared to 10,469 boe/d for the same period in 2005. Fourth quarter 2006 production volumes averaged 18,230 boe/d, an increase of 34% over the 13,601 boe/d reported for the same quarter in 2005. On a year over year basis, 2006 production increased by 51% over 2005. The following table summarizes production volumes by product:



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Three Months Ended Year Ended
Dec - 31 Dec - 31
% %
2006 2005 change 2006 2005 change
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Crude Oil and Liquids
(bbl/d) 2,133 2,856 (25)% 1,703 2,229 (24)%
Natural Gas (mcf/d) 96,583 64,471 50% 84,618 49,442 71%
Oil Equivalent
- boe's 1,677,162 1,251,314 34% 5,769,326 3,821,202 51%
Oil Equivalent
- boe/d 18,230 13,601 34% 15,806 10,469 51%
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Duvernay's production profile continued to be natural gas weighted during 2006 with 89% natural gas and 11% oil and liquids, compared to full year 2005 with 79% natural gas and 21% oil and natural gas liquids, the decrease in the production of oil and liquids is due to the dispositions of oil-weighted minor properties that occurred during the year. Production by property is as follows:



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Three Months Ended Year Ended
Dec - 31 Dec - 31
% %
2006 2005 change 2006 2005 change
-----------------------------------------------
Northeast B.C. 6,078 4,052 50% 5,135 2,704 90%
Deep Basin 11,581 6,845 69% 9,566 5,167 85%
Other Minor Properties 571 2,704 (79)% 1,105 2,598 (57)%
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18,230 13,601 34% 15,806 10,469 51%
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Production increases in 2006 over 2005 occurred as a result of growth from both Northeast BC where 30 new wells were tied in and the Alberta Deep Basin where 98 new wells were tied in during the year. Full year Deep Basin production for the year averaged 9,566 boe/d for an increase of 85 % compared to 2005. In a like manner, Groundbirch/Sunset production improved to 5,135 boe/d or an increase of 90 % from 2005 and a decrease in production from other areas is due to the impact of the property sales.

Revenue & Royalties

Revenue from petroleum and natural gas sales for the year ended December 31, 2006 was $265.9 million representing a 28.8% increase over revenue of $206.4 million for the same period in 2005. The revenue increase attributed to volume growth was $104.0 million which is offset partially with the revenue decrease attributed to product price movement of $44.5 million. Revenue includes all petroleum and natural gas sales and income from third party natural gas processing, reduced for transportation and adjusted for the effects of commodity hedging activities. Realized oil and liquids prices for 2006 averaged $65.05 per barrel (including realized hedging losses of $0.44 per barrel) compared to $55.73 per barrel in 2005 (including realized hedging losses of $3.11 per barrel). Natural gas prices decreased on a year over year basis averaging $7.30/mcf for 2006 compared to $8.93 for 2005. During 2006, Duvernay estimates that natural gas marketing operational performance combined with natural gas hedges have yielded the Company $23.8 million ($0.77/mcf) in additional gross revenue over the comparable monthly indices.

Fourth quarter 2006 revenue decreased 5% over the fourth quarter in 2005 ($75.5 million in the fourth quarter 2006 compared to $79.3 million in 2005) mainly due to weakening prices, offset by the growth in production volumes. Realized natural gas prices decreased 32% from $10.72/mcf in the fourth quarter of 2005 to $7.25/mcf in the fourth quarter of 2006. Realized oil and liquids prices also decreased in the fourth quarter of 2006 ($56.17/bbl) when compared to the fourth quarter 2005 ($59.86/bbl). The decrease in Duvernay's realized prices is consistent with the decreases in benchmark prices, offset by strength in marketing operations and hedging activities.



Prices are summarized as follows:

Duvernay Realized Prices

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Three Months Ended Year Ended
Dec - 31 Dec - 31
% %
2006 2005 change 2006 2005 change
------------------------------------------------
Crude Oil and Liquids $ 56.17 $ 59.86 (6) $ 65.05 $ 55.73 17
Natural Gas $ 7.25 $ 10.72 (32) $ 7.30 $ 8.93 (18)
Price/boe $ 45.00 $ 63.40 (29) $ 46.09 $ 54.02 (15)
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Benchmark Oil and Gas Prices

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Three Months Ended Year Ended
Dec - 31 Dec - 31
% %
2006 2005 change 2006 2005 change
------------------------------------------------
Oil
NYMEX U.S. $ 60.16 $ 60.05 - $ 66.25 $ 56.70 17
Edmonton Par $ 65.14 $ 72.22 (10) $ 73.72 $ 69.85 6
Cdn.
Natural Gas
NYMEX U.S. $ 7.25 $ 12.88 (44) $ 6.98 $ 9.00 (22)
AECO Cdn $ 6.91 $ 11.61 (40) $ 6.53 $ 8.81 (26)
Currency $ .8778 $ .8521 3 $ .8817 $ .8256 7
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Three Months Year Ended
Ended Dec - 31 Dec - 31
2006 2005 2006 2005
------------------------------------------------
Revenue(1): ($ thousands)
Oil and NGL's $ 10,904 $ 16,458 $ 40,723 $ 47,866
Hedge 118 (730) (276) (2,533)
------------------------------------------------
$ 11,022 $ 15,728 $ 40,447 $ 45,333

Natural Gas 64,443 63,609 225,450 161,079

Processing & Rental Income 2,543 796 7,368 2,226
Total Revenue(1) $ 78,008 $ 80,133 $ 273,265 $ 208,638

(1) Revenue is reduced by transportation costs
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Transportation costs for 2006 were 2% of gross revenue or $1.15/boe, which is consistent with 2005. For the fourth quarter of 2006 transportation costs were 2% of gross revenue, consistent with 2% of gross revenue in the same period in 2005. Third party processing income of $7.4 million increased primarily due to the completion of the Cecilia 15-4 expansion during 2006 to 120 mmcf/d, attracting approximately 15 mmcf/d of third party natural gas in 2006.



Duvernay's royalties are summarized as follows:

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Three Months Year Ended
Ended Dec - 31 Dec - 31
2006 2005 2006 2005
------------------------------------------------
Royalties: ($ thousands)

Oil and Liquids $ 809 $ 4,114 $ 6,750 $ 10,787
Natural Gas 6,580 11,973 35,099 31,185
ARTC - (125) (500) (525)
------------------------------------------------

$ 7,389 $ 15,962 $ 41,349 $ 41,447
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For the year ended December 31, 2006 the average effective royalty rate was 15% compared to 20% for the same period in 2005. The rate fell as the Company's operational focus in the Deep Basin and Northeast BC helped to increase the benefits from various gas royalty holiday programs. On new wells in British Columbia, royalty benefits were received for low productivity natural gas wells and for wells drilled in the summer. Duvernay records the benefits provided by the various provincial incentives only in the period in which the benefit has been approved by the provincial regulatory agency. In the fourth quarter, the Company had an effective royalty rate of 9% compared to 20% for the same quarter in 2005. Effective January 2007 the Province of Alberta has eliminated the Alberta Royalty Tax Credit (ARTC) program.

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 decreased from $5.60/boe in 2005 to $5.51/boe in 2006. Total operating expenses for 2006 were $31.8 million compared to $21.4 million for 2005. This increase is attributable to increases in production volumes as well as inflationary pressures. For the fourth quarter of 2006, operating expenses were down slightly compared to the same quarter in 2005 ($5.67/boe compared to $5.74/boe). For 2006, the Company 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 dropped to $1.36 down from $1.55 in 2005, representing 25% of total operating expenses. For the fourth quarter 2006 third party processing fees per barrel of oil equivalent were down $.32 to $1.20 (21% of fourth quarter operating expenses) from $1.77 in the same period in 2005. In 2006, 15 mmcf/d of gas previously 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 helped to bring unit operating expenses down in 2006.



General & Administrative Expenses

General and Administrative Expenses are summarized as follows:

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Three Months Year Ended
Ended Dec - 31 Dec - 31
($ thousands) 2006 2005 2006 2005
------------------------------------------------

General & administrative
expenses $ 4,224 $ 3,799 $ 14,141 $ 11,234
Administrative and
operating recovery (630) (285) (1,787) (1,288)
Capital recovery (2,064) (1,615) (6,982) (4,718)
Capitalized G&A (526) (600) (1,786) (1,707)
Stock based compensation 3,137 1,477 10,139 3,881
Capitalized stock based
Compensation (including
income tax effect) (1,361) - (4,398) -
------------------------------------------------
$ 2,780 $ 2,776 $ 9,327 $ 7,402
Oil equivalent ($/boe) $ 1.66 $ 2.22 $ 1.62 $ 1.94
Oil equivalent cash costs
($/boe) $ 0.60 $ 1.04 $ 0.62 $ 0.92
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General and administrative expenses for the twelve months ending December 31, 2006 increased to $9.3 million from $7.4 million for the same period in 2005. On a per unit of production basis, the rate decreased from $1.94/boe in 2005 to $1.62 in 2006. On a cash basis, G&A for 2006 dropped to $0.62/boe from $0.92/boe in 2005 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 2005. Fourth quarter 2006 G&A cash costs of $0.60 per boe are significantly lower than the same quarter for 2005 of $1.04 per boe. The issuance of 1.7 million stock options in 2006 drove stock based compensation costs for 2006 up by 161% to $10 million. Additionally, most of the impact of a large option issuance in the fourth quarter of 2005 is being recognized in 2006. On a barrel of oil equivalent basis, this non cash cost decreased to $1.00/boe from $1.02/boe in 2005.

Depletion, Depreciation and Accretion

Depletion, depreciation and site restoration expense increased to $112.1 million during 2006 from $60.1 million during 2005. On a dollars per boe basis, full year unit of production DD&A increased in 2006 to $19.43 from $15.73 in 2005, an increase of 24%. The rate increase is primarily attributable to continued large investments in facilities (18% of total capital compared to 22% in 2005) and rate inflation primarily from providers of drilling, fracture stimulation and trucking services. The 2007 capital program contemplates dedicating 79% of total capital to drilling and completions. For the fourth quarter of 2006 the DD&A rate of $22.53/boe is compared to $19.82/boe for the fourth quarter of 2005. 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. Capital for future wells in the Alberta Deep Basin external reserve engineers report is up significantly reflecting the completion and stimulation of 5 zones as opposed to 2 zones previously. Associated future proved undeveloped reserves have not increased thus increasing the implied depletion rate.

Income Taxes

Duvernay did not incur any cash tax expense in 2006. Duvernay does not expect to pay any cash taxes in 2007 based on existing tax pools, planned capital expenditures and the most recent forecast of 2007 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 1-2 years. Federal tax rate reductions introduced during the second quarter have lowered the effective rate of the Company's future income tax. The impact of this reduction was recognized as a decrease in the Future Income Tax liability in the second quarter, resulting in full year future income tax expense falling to 12% of pre-tax income when compared to 31% in 2005. The rate reductions announced in the first half of 2006 helped to decrease future income tax provision for the fourth quarter of 2006 to 24% of pre tax income from 31% in 2005.



Duvernay's tax pools at December 31, 2006 and December 31, 2005 are as
follows:

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Maximum Deduction % 2006 ($ millions) 2005 ($ millions)

COPGE 10 37 71
CDE 30 389 249
CEE 100 144 83
UCC 25 274 165
Other 13 10
----- -----
857 578
----- -----
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Subsequent to December 31, 2006 Duvernay renounced exploration expenditures related to 2006 flow through share obligations resulting in reductions of the tax pool balances of $104.1 million.

Funds From Operations and Earnings

Funds from operations increased by 34% to $184.2 million ($3.45 per diluted Equity Share) for the twelve months ending December 31, 2006 from $137.5 million ($2.81 per diluted Equity Share) for the comparable period in 2005. This is due to the growth in production volumes offset by operating netbacks primarily related to the erosion of natural gas prices, which decreased by 11% averaging $33.42/boe compared to $37.57 for 2005. Full year funds from operations guidance announced in November of 2006 was $192.1 million ($3.52/diluted share) which was 4% higher than actual results, primarily due to full year production of 15,806 boe/d being slightly lower than November 2006 guidance of 16,500-17,000 boe/d. After tax earnings improved by 16.6% for 2006 to $58.4 million when compared to 2005 of $50.1 million. On a per share basis, diluted earnings improved by 7% to $1.09 per share for 2006 compared to $1.02 for 2005.

Fourth quarter after tax earnings decreased 34% to $0.23 per diluted equity share in 2006, down from $0.35 for the same period in 2005, due mainly to the decrease in natural gas prices.



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Three Months Ended Year Ended
Dec. 31 Dec. 31
2006 2005 2006 2005
----------------------------------------------------------------------------

Funds from Operations per
Equity Share (1) $ 1.03 $ 1.04 (1)% $ 3.45 $ 2.81 23%
Earnings per Equity Share (1) $ 0.23 $ 0.35 (34)% $ 1.09 $ 1.02 7%
Operating Netback per boe $34.92 $44.90 (22)% $33.42 $37.57 (11)%

note:
(1) diluted
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2006 2005
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Net Earnings $ 58,362 $ 50,075
Items not involving cash
Depletion, depreciation and accretion 112,077 60,091
Stock based compensation 5,741 3,881
Future income taxes 7,999 23,407
---------- ----------
Funds from Operations $ 184,179 $ 137,454
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Liquidity and Capital Resources

Duvernay invested $534.9 million in 2006 compared to $463.3 million in 2005,
as set out in the following table.

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($ thousands) Year Ended
Dec - 31
2006 2005
----------------------------------------------------------------------------

Land and seismic $ 44,419 $ 46,587
Drilling and completions 440,331 289,928
Facilities 118,142 103,224
Property Acquisitions 37,446 52,908
Property Dispositions (112,277) (31,262)
Other 6,818 1,867

--------------------
Total $534,879 $463,252
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Duvernay participated in the following equity financings during 2006, the
proceeds from which were dedicated to an expanded capital spending program:

February public equity issue 1,250,000 $44.50 $55,625,000

May flow through-private
placement 1,000,000 $56.00 $56,000,000

October flow through-private
placement 1,100,000 $43.75 $48,125,000


In February 2007 Duvernay closed an additional 1,000,000 flow through share financing at $41.50 per share on a private placement basis.

The Company estimates that it has completed its commitment to invest $56 million in exploration spending from the May 2006 flow through share issue and that approximately $25 million of the October 2006 flow through share issue has been spent by December 31, 2006.

At December 31, 2006, Duvernay had a working capital deficiency of $93.5 million and the bank line was drawn to $324.6 million for net debt of $418.1 million or 1.9 times annualized fourth quarter 2006 funds from operations. In May 2006, Duvernay completed a new syndicated bank facility with a group of Canadian banks. The new facility currently has borrowing capacity of $375 million. In addition the Company has established a $25 million operating line. The syndicated credit facility is an arrangement 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 $1,000 million demand loan debenture secured by a first floating charge over all assets.

Under the terms of the syndicated credit facility, the Company has provided the covenant that at all times the outstanding principal amount owing under the credit agreement is equal to or less than the borrowing base limit ($400 million). The Company has also provided that at the end of each quarter that the ratio of EBITDA to Interest Expense determined retrospectively on a rolling four quarter basis equals or exceeds 3.5 to 1.

The Company's average interest rate on borrowed funds decreased slightly in 2006 to 4.44% from 4.55% in 2005. Interest expense increased to $12.4 million in 2006.

During 2006, Duvernay drilled 126 gross (95.7 net) wells, with a success rate of 98% resulting in 7 oil wells, 112 gas wells, and 7 suspended or abandoned wells. The Company also continued with significant facility investments in 2006 increasing control of infrastructure and processing capacity. These facility investments have good economic returns and allow Duvernay to enter into farm-in opportunities on attractive terms. Capacity at the central Cecilia gas plant was more than doubled in 2006 to 120 mmcf/day. In addition in Northeast B.C. the Brassey gas plant commenced operation with capacity of 12.5 mmcf/day of sales gas. Other significant compression and plant facilities were also built or expanded in both the Deep Basin and Northeast B.C.

The following significant property acquisition and disposition activity took place during 2006:

- A non-core oil property disposition (250 bbls/day) closed in the second quarter for proceeds of approximately $12.2 million. Early in the third quarter, net proceeds of approximately $10 million were derived from a non-core Peace River High producing asset (100 boe/d).

- A $37 million asset purchase in the Company's North East B.C. core area added 450 bbls/day of new production, consolidating working interests and providing new optimization and development opportunities.

- The Company sold non-core oil and gas producing assets contributing approximately 650 bbls/day to a private company related to Duvernay. Duvernay's chief executive officer is a member of the Board of Directors of the related company and the related company's chief operating officer is a member of the Duvernay board of directors. The Company received $70 million in cash plus $15 million in shares (5 million shares at $3.00 each) of the private company in consideration for oil and gas properties and gas processing facilities. The transaction was accounted for at its fair value.

Duvernay also continued to grow its undeveloped land base aggressively by spending $34 million at Crown land sales resulting in 54,704 gross acres (54,192 net) primarily in the Alberta Deep Basin and the Cadomin and Doig resource play of Northeast BC.

Duvernay's base capital budget for 2007 is $365 million with approximately $155 million allocated to exploration activities and approximately $210 million allocated to development drilling and facilities. The 2007 budget contemplates drilling 90-100 wells. This capital program will be funded through a combination of cash flow, bank debt and the recently completed equity financing. The Company currently forecasts 2007 Funds from Operations to be $310 - $386 million depending on product prices.

As at December 31, 2006, the Company had issued and outstanding common shares of 53,961,607 and outstanding stock options of 5,119,985. As at March 20, 2007 the Company had issued and outstanding common shares of 55,565,773 and outstanding stock options of 4,475,818.

Financial Instruments

The Company 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 2007 and 2008 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 primarily into physical delivery contracts which avoid the need to provide credit in the event that the contracts are at prices below prevailing prices. Significant risks with the commodity hedges is that the prevailing product prices are higher than those committed to in the hedging contract or that production volumes are not sufficient to meet hedging commitments. The Company partially mitigates the price risk by including collars in its hedging portfolio. Production risk is managed by keeping the amount of production hedged below a fixed percentage and by entering into the hedging contracts at multiple delivery points.

At the end of 2006, Duvernay assessed the prevailing market value of similar contracts to those that were unsettled at year end and has estimated net proceeds from monetizing these instruments to be approximately $9.6 million.



Contracts in place at March 20, 2007:
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Type of Quantity Contract
Time Period Contract Control Price
----------------------------------------------------------------------------

2007 January - June Put (floor) 200 bbls/day $72.90 U.S. W.T.I.
2007 January - December Put (floor) 100 bbls/day $79.55 U.S. W.T.I.
2007 July - December Put (floor) 200 bbls/day $72.59 U.S. W.T.I.
2007 January - March Put (floor) 100 bbls/day $66.00 U.S. W.T.I.
2007 January - March Physical 13,000 gj's/day $9.55 Cdn/gj average
(swap)
2007 January - March Physical 7,000 gj's/day $8.14 Cdn/gj average
(swap)
2007 January - December Physical 3,000 gj's/day $7.76 Cdn/gj
(swap)
2007 January - March Put (floor) 10,000 gj's/day $7.00 Cdn/gj
2007 April - October Collar 10,000 gj's/day $7.00 Cdn/gj Floor/
$8.57 Cdn/gj Ceiling
2007 April - October(i) Put (floor) 5,000 gj's/day $7.30 Cdn/gj
2007 April - October(i) Collar 6,000 gj's/day $6.02 Cdn/gj Floor/
$7.05 Cdn'gj Ceiling
2007 April - October(i) Collar 4,000 gj's/day $6.25 Cdn/gj Floor/
$7.37 Cdn/gj Ceiling
2007 April - October(i) Collar 5,000 gj's/day $7.00 Cdn/gj Floor/
$8.91 Cdn/gj Ceiling
2007 April - October(i) Collar 3,000 gj's/day $7.65 Cdn/gj Floor/
$8.17 Cdn/gl Ceiling
2007 April - October(i) Collar 5,000 gj's/day $7.00 Cdn/gj Floor/
$7.80 Cdn/gj Ceiling
2007 April - October(i) Nymex 5,000 MMBTU/d Nymex less $0.83/mmbtu
Differential
Swap

(i) Contract was entered into in 2007


2006 2006 2006 2006
Q4 Q3 Q2 Q1
----------------------------------------------------------------------------
PRODUCTION
Crude oil and liquids (bbls) 196,225 170,051 111,557 143,926
Gas (mcf) 8,885,624 7,836,912 7,823,061 6,339,802
Oil equivalent (boe) 1,677,162 1,476,203 1,415,401 1,200,560

Crude oil and liquids (bbls/d) 2,133 1,848 1,226 1,599
Gas (mcf/d) 96,583 85,184 85,968 70,442

Oil equivalent (boe/d) 18,230 16,046 15,554 13,340

FINANCIAL
($ thousands, except as noted)
Revenue, net of royalties and
transportation 70,620 58,404 50,721 52,171

Funds from operations 55,845 46,081 39,009 43,244
Per share basic 1.05 0.88 0.75 0.86

Net earnings 12,242 12,309 21,677 12,133
Per share basic 0.23 0.24 0.42 0.24
Per share diluted 0.23 0.23 0.40 0.23

Total assets 1,272,571 1,173,784 1,022,445 971,616

Bank debt 324,590 296,703 271,692 221,760

Cash and working capital
(deficiency) (93,537) (87,959) (6,154) (53,148)

Basic outstanding Shares 53,962 52,605 52,307 51,205

PER UNIT
Gas, net of transportation ($/mcf) 7.25 6.62 6.55 9.12

Crude oil and liquids, net of
transportation ($/bbl) 56.17 73.07 75.49 59.61

Revenue, net of transportation
($/boe) 45.00 43.58 42.18 55.31

Operating netback ($/boe) 34.92 32.42 29.28 37.42


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

Operating netback ($/boe) 44.90 39.24 31.19 31.02


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
2006 2005 2004 2003
Year Year Year Year
-----------------------------------------------
(restated)
PRODUCTION
Crude oil and liquids (bbls) 621,759 813,502 504,860 540,590
Gas (mcf) 30,885,399 18,046,197 10,446,068 3,819,328
Oil equivalent (boe) 5,769,326 3,821,202 2,245,871 1,177,145

Crude oil and liquids
(bbls/d) 1,703 2,229 1,379 1,481
Gas (mcf/d) 84,618 49,442 28,541 10,464
Oil equivalent (boe/d) 15,806 10,469 6,136 3,225

FINANCIAL
($ thousands, except as noted)
Revenue, net of royalties and
transportation 231,916 167,191 76,966 36,736

Funds from operations 184,179 137,454 59,675 25,472
Per share basic 3.54 2.94 1.47 0.84

Net earnings 58,362 50,075 20,254 8,032
Per share basic 1.12 1.07 0.50 0.26
Per share diluted 1.09 1.02 0.48 0.25

Total assets 1,272,571 827,263 393,440 220,546

Total long term financial
liabilities 324,590 175,481 67,126 48,564

Cash and working capital
(deficiency) (93,537) (40,180) (13,439) (15,942)

Basic outstanding shares 53,962 49,345 40,645 30,396

PER UNIT
Gas ($/mcf) 7.30 8.93 6.86 6.54

Crude oil and liquids ($/bbl) 65.05 55.73 43.59 39.11

Revenue ($/boe) 46.09 54.02 41.69 39.59

Operating netback ($/boe) 33.42 37.57 28.30 23.86


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 Total Less than 1-3 years 4-5 years Thereafter
period ($ millions) 1 year

Long-term debt $ 324.6 $ - $ 324.6 $ - $ -
Flow-through
obligation 23.0 23.0
Operating leases 1.3 0.6 0.7 - -
Firm transportation
agreements 13.0 5.1 7.5 0.3 0.1
$ 361.9 $ 28.7 $ 332.8 $ 0.3 $ 0.1

Drilling Results

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

2006 2005
---- ----
Gross Net Gross Net
---------------------------------
Crude oil 7 5.6 4 3.2
Natural gas 112 84.4 120 80.7
Suspended 5 4.2 1 0.9
Dry and abandoned 2 1.5 1 1.0
----------------------------------------------------------------------------
Total wells 126 95.7 126 85.8


Landholdings

Duvernay's developed and undeveloped landholdings as at December 31, 2005
and 2006 are set forth below:

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


2006
Alberta 224,746 150,885 114,880 71,098 339,626 221,983
British Columbia 90,618 72,873 113,635 109,424 204,253 182,297
----------------------------------------------------------------------------
Total 315,364 223,758 228,515 180,522 543,879 404,280


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 "Depletion and Depreciations Expense".

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 in the ceiling test for impairment, for which any write-down would be charged to depletion and depreciation expense.

Full Cost Accounting Ceiling Test

Oil and gas assets are evaluated at least annually 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 future cash flows from the production of proved and probable reserves and the lower of cost and market of the unproved properties. The cash flows are estimated using the future product prices and costs and are discounted using the risk-free rate. By their nature, these estimates are subject to measurement uncertainty and the impact on the financial statements could be material. Any impairment would be charges as additional depletion and depreciation expense.

Asset Retirement Obligations

The Asset retirement obligations are estimated based on existing laws, contracts or other policies. The fair value of an 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 $60,000 and are assumed to be incurred over a six-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 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.

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 company'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.

The Company adopted the new standards on January 1, 2007; as a result the Company has elected to discontinue the use of hedge accounting, which allowed gains and losses on hedging contracts to be recorded in oil and natural gas sales when they were realized. The new standard will result in outstanding hedging contracts being recorded on the balance sheet at their estimated fair value and subsequently marked-to-market in each reporting period. The gains and losses associated with marking these instruments to market in each period will be recorded in income as a non-cash item until their settlement. Future reporting periods will be impacted by these standards and the resulting impacts will be assessed at that time.

Disclosure Controls and Procedures

Disclosure controls and procedures have been designed to ensure that information required to be disclosed by the Company is accumulated and communicated to the Company's management as appropriate to allow timely decisions regarding required disclosure. The Company's Chief Executive Officer and Chief Financial Officer have concluded, based on their evaluation as of the end of the period covered by the Company's annual filings for the most recently completed financial year, that the Company's disclosure controls and procedures as of the end of such period are effective to provide reasonable assurance that material information related to the Company, including its consolidated subsidiaries, is made known to them by others within those entities.

Internal Controls Over Financial Reporting

Internal controls have been designed to provide reasonable assurance regarding the reliability of the Company's financial reporting and the preparation of financial statements together with the other financial information for external purposes in accordance with the Canadian GAAP. The Company's Chief Executive Officer and Chief Financial Officer have designed or caused to be designed under their supervision internal controls over financial reporting related to the Company, including its consolidated subsidiaries.

The Company's Chief Executive Officer and Chief Financial Officer are required to cause the Company to disclose herein any change in the Company's internal control over financial reporting that occurred during the Company's most recent interim period that materially affected, or is reasonably likely to materially affect the Company's internal control over financial reporting. During 2006, the Company engaged external consultants to assist in documenting and assessing the Company's design of internal controls over financial reporting. No material changes were identified in the Company's internal control of financial reporting during the three months ended December 31, 2006, that had materially affected, or are reasonably likely to materially affect, the Company's internal control of financial reporting.

It should be noted that a control system, including the Company's disclosure and internal controls and procedures, no matter how well conceived, can provide only reasonable, but not absolute, assurance that the objectives of the control system will be met and it should not be expected that the disclosure and internal controls and procedures will prevent all errors or 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 and which are also available on Duvernay's website www.duvernayoil.com.



DUVERNAY OIL CORP.
Balance Sheets
December 31, 2006 and 2005
(Thousands of Dollars)

----------------------------------------------------------------------------
----------------------------------------------------------------------------
2006 2005
----------------------------------------------------------------------------
Assets

Current assets:
Accounts receivable $ 62,446 $ 58,215
Prepaid expenses and deposits 1,230 530
----------------------------------------------------------------------------
63,676 58,745

Investment (note 9) 15,000 -

Property, plant and equipment (note 2) 1,193,895 768,518
----------------------------------------------------------------------------
$ 1,272,571 $ 827,263
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Liabilities and Shareholders' Equity

Current liabilities:
Accounts payable and accrued liabilities 157,213 98,925
----------------------------------------------------------------------------
157,213 98,925

Long-term debt (note 3) 324,590 175,481

Asset retirement obligations (note 4) 11,686 9,491

Future income tax (note 6) 95,799 61,054

Shareholders' equity:
Share capital (note 5) 531,651 396,450
Contributed surplus (note 5) 12,323 4,915
Retained earnings 139,309 80,947
----------------------------------------------------------------------------

Commitments (note 10) 683,283 482,312
Subsequent events (notes 7 and 11)
----------------------------------------------------------------------------
$ 1,272,571 $ 827,263
----------------------------------------------------------------------------

See accompanying notes to financial statements.


DUVERNAY OIL CORP.
Statements of Earnings and Retained Earnings
Years ended December 31, 2006 and 2005
(Thousands of Dollars, Except Per Share Amounts)

----------------------------------------------------------------------------
----------------------------------------------------------------------------
2006 2005
----------------------------------------------------------------------------

Revenue:
Petroleum and natural gas $ 272,522 $ 210,741
Royalties (41,349) (41,447)
Processing and other income 7,368 2,226
----------------------------------------------------------------------------
238,541 171,520

Expenses:
Operating 31,760 21,396
Transportation 6,625 4,329
General and administration 3,586 3,521
Stock-based compensation 5,741 3,881
Interest 12,391 3,592
Depletion, depreciation and accretion 112,077 60,091
----------------------------------------------------------------------------
172,180 96,810
----------------------------------------------------------------------------
Earnings before taxes 66,361 74,710

Income taxes (note 6):
Capital - 1,228
Future 7,999 23,407
----------------------------------------------------------------------------
7,999 24,635
----------------------------------------------------------------------------
Net earnings 58,362 50,075

Retained earnings, beginning of year 80,947 30,872

----------------------------------------------------------------------------
Retained earnings, end of year $ 139,309 $ 80,947
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Earnings per share:
Basic $ 1.12 $ 1.07
Diluted $ 1.09 $ 1.02
----------------------------------------------------------------------------
----------------------------------------------------------------------------

See accompanying notes to financial statements.


Statements of Cash Flows
Years ended December 31, 2006 and 2005
(Thousands of Dollars)

----------------------------------------------------------------------------
----------------------------------------------------------------------------
2006 2005
----------------------------------------------------------------------------
Cash provided by (used in):

Operations:
Net earnings $ 58,362 $ 50,075
Items not involving cash:
Depletion, depreciation, and accretion 112,077 60,091
Stock-based compensation 5,741 3,881
Future income taxes 7,999 23,407
Abandonment expenditures (380) (300)
Change in non-cash operating working capital (note 8) (8,001) (15,301)
----------------------------------------------------------------------------
175,798 121,853

Financing:
Issue of common shares, net of share issue costs 159,216 127,656
Increase in long-term debt 149,109 134,757
----------------------------------------------------------------------------
308,325 262,413

Investments:
Additions to property, plant, and equipment (605,324) (441,822)
Property acquisitions (37,434) (15,748)
Property dispositions 97,277 31,262
Change in non-cash working capital (note 8) 61,358 41,899
----------------------------------------------------------------------------
(484,123) (384,409)

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

Cash, beginning of year - 143
----------------------------------------------------------------------------

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

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, 2006 and 2005
(tabular amounts in thousands of dollars)


Nature of operations:

Duvernay Oil Corp. (the "Company") was incorporated under the laws of the Province of Alberta on June 27, 2001. The principle business of the Company is the exploration, exploitation, development and production of oil and gas reserves.

1. Significant accounting policies:

(a) Capital assets:

The Company 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 including capitalized stock-based compensation, exploration and development activities.

Capitalized costs, excluding costs relating to unproved properties and estimated salvage values, are depleted using the unit-of-production method based on estimated proved 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 proved 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 Company 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 proved reserves, plus the cost of undeveloped land, less impairment. Future net revenues are calculated using the undiscounted net production revenue assigned by independent reserve engineers and the cost of unproved properties. 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 operations:

Some of the Company's oil and gas exploration and development activities are conducted jointly with others and, accordingly, the financial statements reflect only the Company'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 Company 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:

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 Company 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 Company 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 Company's asset retirement obligation is recorded in the period in which it is incurred, discounted to its present value using the Company'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) Investment:

The investment represents common shares held in a private company. The Company does not exercise significant influence in the investment and therefore accounts for it at cost. The Company evaluates the carrying value of the investment at least annually or more frequently should economic events dictate. If there has been a decline in the value of an investment, other than a temporary decline, the investment is written down to its market value and the impairment charged to net income.

(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) Revenue recognition:

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

(m) Comparative information:

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



2. Capital assets:

----------------------------------------------------------------------------
----------------------------------------------------------------------------
Accumulated Net book
2006 Cost depletion value
----------------------------------------------------------------------------

Petroleum and natural gas properties $ 1,278,089 202,050 $ 1,076,039
Gas processing facilities 129,918 12,782 117,136
Furniture, fixtures and leasehold
improvements 1,309 589 720

----------------------------------------------------------------------------
$ 1,409,316 215,421 $ 1,193,895
----------------------------------------------------------------------------
----------------------------------------------------------------------------

2005
----------------------------------------------------------------------------

Petroleum and natural gas properties $ 804,588 98,788 $ 705,800
Gas processing facilities 67,293 4,868 62,425
Furniture, fixtures and leasehold
improvements 676 383 293
----------------------------------------------------------------------------
$ 872,557 104,039 $ 768,518
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The cost of unproven lands at December 31, 2006 of $87,177,000 (2005 - $114,239,000) has been excluded from the depletion calculation. Future development costs of proved reserves in 2006 of $353,960,000 (2005 - $156,997,000) have been included in the depletion calculation.

General and administrative expenditures of $6,183,000 (2005 - $1,707,000) have been capitalized and included as costs of petroleum and natural gas properties. Included in this amount is the non-cash related stock-based compensation of $3,092,000. The future tax liability of $1,306,000 associated with the capitalized stock-based compensation has also been capitalized.

At December 31, 2006, the Company applied a ceiling test to its petroleum and natural gas assets using expected future market prices of:




----------------------------------------------------------------------------
----------------------------------------------------------------------------
Benchmark reference price forecast 2007 2008 2009 2010 2011 2012-2017
----------------------------------------------------------------------------
WTI ($US/bbl 62.00 60.00 58.00 57.00 57.00 60.42
AECO ($Cdn/mcf) 7.20 7.45 7.75 7.80 7.85 8.61
----------------------------------------------------------------------------
----------------------------------------------------------------------------


After 2017 the price forecast for WTI and AECO escalate at 2% per year to the end of the reserve life.

3. Long-term debt:

The Company has a financing arrangement with a Canadian chartered bank for an extendible revolving term loan in the amount of $375 million in addition to a $25 million operating line. As at December 31, 2006, $324,590,000 (2005 - $175,481,000) 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 $1,000 million demand loan debenture secured by a first floating charge over all assets. In May 2007, 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 Company is required to meet certain financial based covenants to maintain the facility. The effective interest rate on the long term debt was 4.4% for the year ended December 31, 2006.

4. Asset retirement obligations:

The Company's asset retirement obligations result from net ownership interests in petroleum and natural gas assets including well sites, gathering systems and processing facilities. The Company estimates the total undiscounted amount of cash flows required to settle its asset retirement obligations is approximately $31,946,000 (2005 - $17,775,000) which will be incurred between 2014 and 2022. A credit-adjusted risk-free rate of 7% and an inflation rate of 3% were used to calculate the fair value of the asset retirement obligations.



A reconciliation of the asset retirement obligations is provided below:

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----------------------------------------------------------------------------
2006 2005
----------------------------------------------------------------------------

Balance, beginning of year $ 9,491 $ 5,849
Accretion expense 696 641
Change in estimate 230 -
Liabilities incurred 3,368 3,301
Liabilities settled (380) (300)
Dispositions (1,719) -
----------------------------------------------------------------------------
Balance, end of year $ 11,686 $ 9,491
----------------------------------------------------------------------------



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, 2004 44,286,924 $ 248,651
For cash on private placement of flow-through
shares 1,950,000 82,425
For cash on public share issue 1,800,000 49,950
For cash on exercise of stock options 598,384 2,428
For acquisition of properties 710,000 26,015
Contributed surplus on exercise of stock options - 293
Share issue costs - (7,146)
Tax effect on share issue costs - 2,415
Tax effect on flow-through renunciation (8,581)
----------------------------------------------------------------------------
Balance, December 31, 2005 49,345,308 396,450
For cash on private placement of flow-through
shares 2,100,000 104,125
For cash on public share issue 1,250,000 55,625
For cash on exercise of stock options 1,266,299 7,105
Contributed surplus on exercise of stock options - 1,425
Share issue costs - (7,639)
Tax effect on share issue costs - 2,416
Tax effect on flow-through renunciation - (27,856)
----------------------------------------------------------------------------
Balance, December 31, 2006 53,961,607 $ 531,651
----------------------------------------------------------------------------
----------------------------------------------------------------------------


On February 9, 2006, the Company 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 May 31, 2006 Duvernay issued 1,000,000 common shares on a flow-through basis at an issue price of $56.00 per share for gross proceeds of $56 million. On October 12, 2006 the Company issued 1,100,000 common shares on a flow-through basis at an issue price of $43.75 for gross proceeds of $48.125 million. Effective December 31, 2006 the Company renounced $104.125 million to be incurred on qualifying expenditures on or before December 31, 2007.

During the year ending December 31, 2006 Duvernay fulfilled its remaining obligation of $82.425 million of capital expenditures related to its 2005 flow-through offering of the same amount. As at December 31, 2006 the Company estimates that it fulfilled its obligation on the May 2006 offering and has a $23.0 million remaining obligation for the October 2006 offering which must be completed by December 31, 2007.



(d) Contributed surplus:

----------------------------------------------------------------------------
----------------------------------------------------------------------------
2006 2005
----------------------------------------------------------------------------

Contributed surplus, beginning of year $ 4,915 $ 1,327
Stock-based compensation 8,833 3,881
Exercise of stock options (1,425) (293)

----------------------------------------------------------------------------
Contributed surplus, end of year $ 12,323 $ 4,915
----------------------------------------------------------------------------
----------------------------------------------------------------------------



(e) Stock options:

The Company has a rolling stock option plan. Under the employee stock option plan, the Company may grant options to its employees for up to 10% of outstanding common stock. The exercise price of each option equals the market price of the Company'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:

----------------------------------------------------------------------------
----------------------------------------------------------------------------
2006 2005
---------------------- -----------------------
Weighted Weighted
Average Average
Number of Exercise Number of Exercise
Options Price Options Price
----------------------------------------------------------------------------

Stock options outstanding,
beginning of year 4,653,284 $ 14.44 3,924,168 $ 6.55
Granted 1,733,000 34.81 1,327,500 33.07
Exercised (1,266,299) 5.61 (598,384) 4.06
Forfeitures - - - -

----------------------------------------------------------------------------
Stock options outstanding,
end of year 5,119,985 $ 23.51 4,653,284 $ 14.44
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Exercisable, end of year 2,117,818 $ 11.69 2,392,451 $ 5.40
----------------------------------------------------------------------------
----------------------------------------------------------------------------



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

$3.50-6.25 1,445,652 4.88 1.19 1,445,652 4.88
10.90-17.18 630,833 15.13 2.77 246,666 14.15
25.20-39.00 3,043,500 34.10 4.25 425,500 33.37
----------------------------------------------------------------------------
5,119,985 23.51 3.20 2,117,818 11.69
----------------------------------------------------------------------------
----------------------------------------------------------------------------


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:




----------------------------------------------------------------------------
----------------------------------------------------------------------------
2006 2005
----------------------------------------------------------------------------

Risk-free interest rate (%) 4.5 4.5
Expected life (in years) 3.5 3.5
Expected volatility (%) 30-40 40-50
Expected dividend - -
Expected forfeitures (%) 10 10


The weighted average fair value of the stock options granted during the year was $10.52 (2005 - $11.53) 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, 2006 was 52,069,456 (2005 - 46,832,318).

In computing diluted earnings per share for the period ended December 31, 2006, 1,243,889 (2005 - 2,118,880) shares were added to the weighted average number of common shares outstanding for the dilution from the stock options. Excluded from the diluted earnings per share calculation were 80,000 options on the basis that they were anti-dilutive. No adjustments to net income are required for purposes of calculating diluted earnings per share.

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




----------------------------------------------------------------------------
----------------------------------------------------------------------------
2006 2005
----------------------------------------------------------------------------

Earnings before taxes $ 66,361 $ 74,710
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Combined federal and provincial tax rate 34.8% 37.8%

Computed "expected" income tax expense $ 23,124 $ 28,237

Increase (decrease) resulting from:
Non-deductible Crown charges 4,508 9,081
Resource allowance (7,236) (11,362)
Effect of change in tax rate (14,758) (4,083)
Stock based compensation 2,001 1,467
Other 360 67
----------------------------------------------------------------------------
Future income taxes 7,999 23,407

Capital taxes - 1,228

----------------------------------------------------------------------------
$ 7,999 $ 24,635
----------------------------------------------------------------------------
----------------------------------------------------------------------------

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

----------------------------------------------------------------------------
----------------------------------------------------------------------------
2006 2005
----------------------------------------------------------------------------

Future tax assets:
Asset retirement obligation $ 3,439 $ 3,207
Share issue expenses 3,924 3,550
----------------------------------------------------------------------------
7,363 6,757
Future tax liabilities:
Property, plant and equipment (103,162) (67,811)

----------------------------------------------------------------------------
Net future tax liability $ (95,799) $ (61,054)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


7. Financial instruments:

(a) Foreign currency exchange risk:

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

(b) Interest and Credit risk:

Duvernay is exposed to interest rate risk to the extent that the bank debt is at a floating rate of interest. Duvernay's accounts receivable are with customer and joint venture partners in the oil and natural gas business and are subject to normal credit risks. Concentration of credit risk is mitigated by marketing production to numerous purchasers under normal industry purchase and payment terms. Duvernay may be exposed to certain losses in the event of non-performance by counterparties to commodity price contracts, Duvernay attempts to mitigate this risk by entering into transactions with major financial institutions and commodity marketers.

(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 bears interest at a floating market rate and accordingly the fair market value approximates the carrying value.

(d) Commodity price risk management:



As at December 31, 2006, the Company had fixed the price applicable to
future production as follows:

----------------------------------------------------------------------------
----------------------------------------------------------------------------
Contract
Time period Type of contract Quantity price
----------------------------------------------------------------------------
2007 January-June Put (floor) 200 bbls/day $72.90 U.S. W.T.I.
2007 January-December Put (floor) 100 bbls/day $79.55 U.S. W.T.I.
2007 July-December Put (floor) 200 bbls/day $72.59 U.S. W.T.I.
2007 January-March Put (floor) 100 bbls/day $66.00 U.S. W.T.I.
$9.55 Cdn/gj
2007 January-March Swap 13,000 gj's/day average
$8.14 Cdn/gj
2007 January-March Swap 7,000 gj's/day average
2007 January-December Swap 3,000 gj's/day $7.76 Cdn/gj
2007 January-March Put (floor) 10,000 gj's/day $7.00 Cdn/gj
$7.00 Cdn/gj Floor
$8.57 Cdn/gj
2007 April-October Collar 10,000 gj's/day Ceiling

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

If the contracts were terminated at December 31, 2006, the Company would
receive $9.6 million.

The Company has entered into the following contracts subsequent to December
31, 2006:

----------------------------------------------------------------------------
----------------------------------------------------------------------------
Contract
Time period Type of contract Quantity price
----------------------------------------------------------------------------
2007 April-October Put (floor) 5,000 gj's/day $7.30 Cdn/gj
2007 April-October Collar 6,000 gj's/day $6.02 Cdn/gj Floor/
$7.05 Cdn'gj
Ceiling
2007 April-October Collar 4,000 gj's/day $6.25 Cdn/gj Floor/
$7.37 Cdn/gj
Ceiling
2007 April-October Collar 5,000 gj's/day $7.00 Cdn/gj Floor/
$8.91 Cdn/gj
Ceiling
2007 April-October Collar 3,000 gj's/day $7.65 Cdn/gj Floor/
$8.17 Cdn/gl
Ceiling
2007 April-October Collar 5,000 gj's/day $7.00 Cdn/gj Floor/
$7.80 Cdn/gj
Ceiling
2007 April-October AECO/Nymex 5,000 MMBTU/d Nymex less
Differential Swap $0.83/mmbtu



8. Supplemental Cash Flow Information:

----------------------------------------------------------------------------
----------------------------------------------------------------------------
2006 2005
----------------------------------------------------------------------------
Accounts receivable $ (4,231) $(27,295)
Prepaid expenses (700) 432
Accounts payable and accrued liabilities 58,288 53,461
----------------------------------------------------------------------------
Change in non-cash working capital $ 53,357 $ 26,598
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Relating to:
Operations $ (8,001) $(15,301)
Investments 61,358 41,899
----------------------------------------------------------------------------
Change in non-cash working capital $ 53,357 $ 26,598
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Interest and taxes paid:
----------------------------------------------------------------------------
Interest paid $ (13,529) $ (3,403)
Taxes paid (1,279) (899)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


9. Related Party Transaction

The Company sold certain non-core oil and gas producing assets to a private corporation related to Duvernay. Duvernay's chief executive officer is a member of the Board of Directors of the related company and the related company's chief operating officer is a member of the Duvernay board of directors. The Company received $70 million cash plus $15 million in shares (5 million shares at $3.00 each) of the private corporation in consideration for oil and gas properties and gas processing facilities. The transaction was accounted for at its fair value.

10. Commitments

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 2008- 2009-
Total 2007 2009 2010 Thereafter
----------------------------------------------------------------------------

Operating leases 1,345 572 773 - -

Firm transportation
agreements 12,972 5,138 7,444 290 100
----------------------------------------------------------------------------
$ 14,317 $ 5,710 $ 8,217 $ 290 $ 100
----------------------------------------------------------------------------


11. Subsequent Event

On February 27, 2007 Duvernay completed an equity financing issuing 1,000,000 common shares on a flow-through basis at an issue price of $41.50 per share for gross proceeds of $41.5 million.

Forward Looking Information

This press release contains certain forward-looking statements. These statements are based on Duvernay's current expectations and assumptions that could prove to be incorrect. The forward-looking statements are not guarantees of future performance and undue reliance should not be placed on them. Actual results may differ materially as a result of risks, uncertainties and other factors, such as: changes in the general economic, market, regulatory, industry and business conditions; fluctuations in commodity prices and currency exchange rates; the successful and timely implementation of growth projects; imprecision of reserve estimates; environmental risks; competition from other industry participants; availability of capital; and uncertainties resulting from potential delays or changes in plans, among others. See Duvernay's Annual Information Form and other documents Duvernay files with Canadian securities regulatory authorities for further details, copies of which are available from Duvernay directly or on its website; www.duvernayoil.com or on the SEDAR website www.sedar.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
    or
    Duvernay Oil Corp.
    1500 - 202 6th Avenue S.W.
    Calgary, AB T2P 2R9
    (403) 571-3600
    (403) 269-6510 (FAX)
    Email: info@duvernayoil.com
    Website: www.duvernayoil.com