Duvernay Oil Corp.
TSX : DDV

Duvernay Oil Corp.

March 20, 2008 06:55 ET

Duvernay Enjoys Record 2007

CALGARY, ALBERTA--(Marketwire - March 20, 2008) - Duvernay Oil Corp. (TSX:DDV) is pleased to announce very strong 2007 financial and operating results and several new pool discoveries.

Highlights

2007 proved plus probable reserve additions of 55.0 mmboe yielding a 2007 year end total of 148.2 mmboe added at a cost of $8.89/boe.

Proved producing reserves were increased by 31%. Total proved reserves increased by 51%, proved plus probable reserves were increased by 47% in 2007, net of production.

Production replacement of 719% on a proved plus probable basis and 522% on a proved basis.

Current daily production has reached the 26,000 boepd level in mid-March.

Production was increased by 33% in 2007 over 2006.

Record fourth quarter production of 22,020 boe/d, an increase of 10% over third quarter 2007.

Record funds from operations in the fourth quarter of $69.1 million ($1.17 per diluted share).

Top decile operating costs in 2007 of $5.81/boe and G and A cash costs of ($0.89/boe) yielding a strong unit operating net-back of $33.80/boe.

The Company drilled 94 wells in 2007 with a 99% success rate.

The Company's first two Triassic Montney horizontals in the Sunset-Groundbirch complex production tested at rates in excess of 5.0 mmcfpd.

Exploration new pool gas discoveries at Edson, Deep Groundbirch and West Groundbirch.

Financial Results and Outlook

Duvernay delivered record financial results in 2007. Funds from operations of $237.7 million ($4.15 per diluted share) compared to 2006 of $184.2 million ($3.45 per diluted share) increased by 29% (20% on a per share basis). Similarly earnings of $61.3 million ($1.07 per diluted share) reached record levels when compared to $58.4 million ($1.09 per diluted share) achieved in 2006.

Unit operating netbacks for 2007 of $33.80/boe are amongst the strongest in the industry. Continued cost control discipline has resulted in operating costs of $5.81/boe slightly higher than $5.51/boe for 2006 in a climate of intense competition for field services. The Company is expecting operating costs to approach $5.00/boe in 2008. The Company's effective royalty rate of 14% is due to the benefits derived from various royalty relief programs in Alberta and B.C. Finally cash general and administrative costs averaged $0.89/boe in 2007 higher by 44% from the 2006 level of $0.62/boe, as the Company has staffed up to be prepared for strong 2008 growth.

Total cash costs of $10.75/boe (including operating expenses, cash general and administrative costs and interest) remain amongst the lowest in the industry.

Improved natural gas prices in 2008 and a continuing strong production outlook have lead the Company to increase its cash flow outlook for 2008 to $378.0 million from $325.0 million. Duvernay has 76 mmcfpd hedged for summer 2008 at an average AECO price of $7.90/mcf.

Production Outlook

Fourth quarter 2007 production of 22,020 boe/d was 10% higher than third quarter 2007 and 21% higher than fourth quarter 2006. Full year 2007 average production of 20,966 boe/d was 33% higher than 2006 production of 15,806 boe/d.

Duvernay reached the production level of 26,000 boe/d in early March with the startup of the Oldman Plant. The Company has a further 1,500 - 2,000 boe/d to bring on stream in its two core operating areas prior to Spring breakup. This leaves the Company on track to achieve the full year production target of 29,000 boe/d.

2007 Reserves

During 2007 total proved reserves were increased 51% to 95.9 mmboe net of production and proved plus probable reserves were increased 47% to 148.2 mmboe net of production. The total proved plus probable addition of 55.0 mmboe is the largest net reserve addition of companies in the Intermediate sector or equivalent sized oil and gas Trusts. All of the 2007 reserve additions were achieved via the drill bit.

The Company replaced 2007 production by 7.2 times on a proved plus probable basis and 5.2 times on a proved basis. Proved reserve life index is 12.5 years using average 2007 production. Proved plus probable reserve life index is 19.4 years using average 2007 production. Proved plus probable 2007 recycle ratio is 2.0.

Total proved reserves were added at a cost of $ 12.25/boe prior to future capital and $20.83/boe including future capital, 33% lower than 2006 costs. Proved plus probable reserve addition costs were $8.89/boe prior to future capital and $16.88/boe including future capital, 34% lower than 2006 costs.

Average recognized reserves for Deep Basin wells drilled by Duvernay in 2007 were 2.57 bcf/well, reflecting the continually improving results. Average per well reserves in the engineering report for undrilled future locations in the Deep Basin is only 1.58 bcf, although the full drilling, completion and tie-in capital is carried in future development capital. This represents a significant future reserve opportunity for the 324 future locations in the Deep Basin currently recognized in the report. Duvernay has an additional estimated 1700 development locations in inventory in its two core operational areas that have not been assigned reserves in the 2007 report.



----------------------------------------------------------------------------
Finding, Development and Acquisition Costs
----------------------------------------------------------------------------
(excluding future capital) (with future capital)
$/boe $/boe
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2007
----------------------------------------------------------------------------
Proved + Probable $8.89 $16.88
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Proved $12.25 $20.83
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Inception
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Proved + Probable $11.14 $17.07
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Proved $16.11 $22.08
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Reserves Summary January 2008

Company Interest (includes working interests and royalty interests)

2007 2006

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

Proved
Producing 1,609 226,553 2,436 41,804 1,679 169,161 2,140 32,012 9,792

Proved non
producing 317 33,295 369 6,235 109 35,146 578 6,544 (309)
Proved
Undeveloped 1,010 261,984 3,223 47,897 1,520 130,009 1,897 25,086 22,811

TOTAL
PROVED 2,935 521,833 6,028 95,936 3,308 334,316 4,615 63,642 32,294

Probable 1,337 288,654 2,814 52,260 1,662 197,842 2,547 37,183 15,077

PROVED +
PROBABLE 4,272 810,487 8,842 148,196 4,969 532,158 7,162 100,825 47,371

May not add due to rounding


Reserves Summary January 2008

Company Interest (includes working interests and royalty interests)

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

(Thousands of dollars)
0% 10% 15%
---------- ---------- ----------

Proved Producing 1,396,713 848,757 721,045

Proved non producing 200,081 119,405 99,655

Proved Undeveloped 1,065,543 463,786 325,289
------------------------------------------------

TOTAL PROVED 2,662,337 1,431,947 1,145,989

Probable 1,682,859 574,419 399,600
------------------------------------------------
PROVED plus PROBABLE 4,345,196 2,006,366 1,545,589


Capital Program

The 2008 capital budget remains at $400 million compared to $498 million in 2007. This will allow Duvernay to continue with an eight to nine drilling rig program continuously through the balance of the year. First half 2007 capital spending of approximately $160 million ($100 million Q1, $60 million Q2) is essentially a cash flow budget (1H cash flow $160-170 million).

The Company has entered into an arms length transaction with a private oil and gas company whereby Duvernay will dispose of certain assets on the East flank of the Peace River High for proceeds of $40.0 million. This transaction, involving approximately 625 boepd of Duvernay production is expected to close in early May.

2007 EP Program Update

In 2006 Duvernay operated or participated in a total of 94 wells with an overall success rate of 99%.

Duvernay operated nine drilling rigs in the first quarter of 2007 and plans to operate between eight and nine rigs for the balance of the year. One rig is still active in NEBC, finishing drilling the fourth Montney horizontal well. The Company operated between 10 and 12 service rigs during the first quarter, 5 are currently still active. Pipeline operations will continue in both large project areas until surface conditions prevent further access.

Sunset - Groundbirch, B.C.

The winter program results at Sunset-Groundbirch have been spectacular with success in the Triassic Montney play and new pool discoveries at Saturn, West Groundbirch and Deep Groundbirch. Record BC production levels have also been recently achieved.

The Company's first two Montney horizontals both production tested at gas rates in excess of 5.0 mmcfpd, two additional horizontals are planned for completion in March. Four successful vertical Montney gas wells were also drilled, completed and stimulated in the first quarter. Duvernay has an inventory of up to 500 future Montney horizontal drilling locations on the approximately 180 net sections of Montney interests in the greater Sunset-Groundbirch complex. The Company plans to drill in excess of 10 additional Montney horizontals during the balance of 2008.

New pool multiple objective gas discoveries were made at Saturn and West Groundbirch and are currently being production tested. West Groundbirch will be further delineated in the second half of 2008 prior to facilities construction. A major pipeline project along the northern end of the original Groundbirch Doig gas pool was completed in the first quarter bringing six new wells at Worth and Saturn on-stream prior to Spring break-up.

The Deep Groundbirch 2-10 Paleozoic gas discovery has production tested both sweet and sour gas from multiple pay zones in the Mississippian. The 2-10 well flowed sweet gas at stabilized rates of 160 e3m3/d (5.5 mmcfpd) at a pressure of 9800 kpa from one of the sweet pay zones in the Mississippian. This significant new gas discovery is expected to be brought on stream prior to Spring break-up. Duvernay has a 100% working interest in the discovery and follow-up drilling after break-up is planned.

Alberta Deep Basin

Duvernay operated or participated in 65 wells in the Alberta Deep Basin in 2007 with a 100% success rate.

Fifteen new gas wells have been drilled in the Deep Basin thus far in the first quarter of 2008. High rate gas wells have been drilled and completed recently at Oldman, South Fir, Pedley, Obed and Wroe as well results continue to improve. The Company expects to continue to operate between five and six drilling rigs in the Deep Basin after Spring break-up for the balance of the year.

The Oldman 10-24 plant commenced production during the week of March 4 bringing Deep Basin production volumes to a new record. With Oldman now on stream, Duvernay has three 100% owned and operated plants capable of processing up to 160 mmcfpd of natural gas. The Company is targeting to reach the 150 mmcfpd level of equity gas production in the Deep Basin by late this year. Start-up of the Oldman plant is also expected to drive corporate operating costs below the $5.00/boe level.

Edson, Alberta

The Edson 8-13-54-19W5 well (ProspEx 35% working interest) has been successfully drilled and production tested in the Devonian Wabamun formation. The well flowed high pressure sour gas (14.4% H2S) at controlled rates of up to 7 mmcfpd, with no water and minor condensate.

Tie-in operations are expected to proceed consistent with previous regulatory approvals. Additional drilling in the second half of 2008 is planned (pending regulatory approval) to follow-up this discovery.

MANAGEMENT DISCUSSION AND ANALYSIS

This management's discussion and analysis should be read in conjunction with Duvernay's comparative audited annual financial statements for the year ended December 31, 2007 and comparative information included therein. This management's discussion and analysis is dated March 20, 2008.

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. The following table shows the reconciliation of funds from operations to operating cash flows as defined by GAAP:



Three Months Ended Year Ended
December 31 December 31
----------------------------------------
(000s) 2007 2006 2007 2006
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Operating Cash Flow, per Cash Flow
Statement 49,799 53,904 239,222 175,798
Changes in non-cash working capital 19,295 1,941 (1,568) 8,001
Abandonment costs incurred - - - 380
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Funds from operations, as disclosed 69,094 55,845 237,654 184,179
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Operating netback is calculated on a per $/BOE basis and is defined as
revenue less royalties, transportation costs and operating expenses, as
shown below:

Three Months Ended Year Ended
December 31 December 31
----------------------------------------
($/BOE) 2007 2006 2007 2006
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Revenue, excluding unrealized gains and
losses on financial instruments and
processing fee income 45.62 46.10 47.25 47.24
Royalties (1.54) (4.41) (6.35) (7.17)
Transportation Costs (1.17) (1.10) (1.29) (1.14)
Operating Expenses (5.85) (5.67) (5.81) (5.51)
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Operating Netback 37.06 34.92 33.80 33.42
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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, 2007 compared to the Year ending December 31, 2006

Production

Production volumes for the year ended December 31, 2007 averaged 20,966 boe/d compared to 15,806 boe/d for the same period in 2006, an increase of 33%. Fourth quarter 2007 production volumes averaged 22,020 boe/d, an increase of 21% over the 18,230 boe/d reported for the same quarter in 2006. The following table summarizes production volumes by product:



Three Months Ended
December 31 Year Ended December 31
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2007 2006 Change 2007 2006 Change
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Natural Gas (mcf/d) 120,072 96,583 24% 111,980 84,618 32%
Crude Oil and
Liquids (bbl/d) 2,008 2,133 (6)% 2,303 1,703 35%
Oil Equivalent -
boe's 2,025,840 1,677,162 21% 7,652,544 5,769,326 33%
Oil Equivalent -
boe/d 22,020 18,230 21% 20,966 15,806 33%
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Duvernay's production profile continued to be natural gas weighted during 2007 with 89% natural gas and 11% oil and liquids, consistent with the 2006 product mix. The decrease in crude oil production in the fourth quarter over the same quarter in 2006 is due to dispositions, offset with the growth in NGLs via the growing gas production. Production by property is as follows:



Three Months Ended
December 31 Year Ended December 31
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2007 2006 Change 2007 2006 Change
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Northeast BC 5,663 6,078 (7)% 6,037 5,135 18%
Deep Basin 15,882 11,581 37% 14,369 9,566 50%
Other Minor Properties 475 571 (17)% 560 1,105 (49)%
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22,020 18,230 21% 20,966 15,806 33%
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Production increases in 2007 over 2006 occurred as a result of growth from both the Alberta Deep Basin where 80 new wells were tied in and Northeast BC where 26 new wells were tied in during the year. Full year Deep Basin production for the year averaged 14,369 boe/d for an increase of 50 % compared to 2006. In a like manner, Groundbirch/Sunset production improved to 6,037 boe/d or an increase of 18 % from 2006 and a decrease in production from other areas is due to the impact of the property sales which occurred late in 2006.

Revenue & Royalties

Revenue for the year ended December 31, 2007 was $358.5 million representing a 28% increase over revenue of $279.9 million for the same period in 2006. Revenue includes all petroleum and natural gas sales and income from third party natural gas processing, and has been adjusted for the effects of commodity hedging (realized gains and losses). Duvernay's realized corporate gas prices continued to outperform the AECO spot price during 2007 ($7.15 - net of transportation and realized hedging gains versus AECO at $6.47). AECO natural gas prices stayed relatively constant year over year, with a small decrease of under 1%. Duvernay's realized gas price also stayed relatively constant, with a small drop of 2%. Realized oil and liquids prices for 2007 averaged $70.71 per barrel (including realized hedging gains of $1.99 per barrel) compared to $65.05 per barrel in 2006 (including realized hedging losses of $0.44 per barrel), an increase of 9%. World oil price benchmarks increased by $6.16 U.S. in 2007 when compared to 2006.

Fourth quarter 2007 revenue increased 12% over the fourth quarter in 2006 ($89.7 million in the fourth quarter 2007 compared to $79.9 million in 2006) mainly due to increased production. Realized natural gas prices decreased 6% from $7.25/mcf in the fourth quarter of 2006 to $6.79/mcf in the fourth quarter of 2007. The decrease in Duvernay's realized gas price is consistent with the decreases in benchmark prices, offset by strength in marketing operations and hedging activities.



Duvernay Realized Prices

Three Months Ended
December 31 Year Ended December 31
------------------------- -------------------------
2007 2006 Change 2007 2006 Change
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Natural Gas ($/mcf) $ 6.79 $ 7.25 (6)% $ 7.15 $ 7.30 (2)%
Crude Oil and Liquids
($/bbl) $ 81.56 $56.17 45% $ 70.71 $65.05 9%
Oil Equivalent
($/boe) $ 44.46 $45.00 (1)% $ 45.97 $46.09 0%
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Benchmark Oil and Gas Prices

Three Months Ended Year Ended
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December 31 December 31
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2007 2006 Change 2007 2006 Change
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Natural Gas
NYMEX Henry Hub U.S. $ 7.39 $ 7.25 2% $ 7.12 $ 6.98 2%
AECO Cdn $ 6.16 $ 6.91 (11)% $ 6.47 $ 6.53 (1)%

Oil
NYMEX U.S. $ 90.51 $ 60.16 50% $ 72.41 $ 66.25 9%
Edmonton Par Cdn. $ 87.36 $ 65.14 34% $ 77.71 $ 73.72 5%

Currency $1.0193 $0.8778 16% $0.9311 $0.8817 6%
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Reconciliation of AECO Index to Duvernay's realized Natural Gas Prices

Three Months Ended Year Ended
December 31 December 31
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($/boe) 2007 2006 2007 2006
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AECO Index Price $ 6.16 $ 6.91 $ 6.47 $ 6.53
Transportation (0.14) (0.16) (0.15) (0.17)
Heat/Quality Differential 0.54 0.36 0.33 0.63
Financial Instruments 0.23 0.14 0.50 0.31
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Duvernay realized natural gas price $ 6.79 $ 7.25 $ 7.15 $ 7.30
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Revenue is analyzed as follows:

Three Months Ended
December 31 Year Ended December 31
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Revenue(1) 2007 2006 Change 2007 2006 Change
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Natural Gas $ 72,257 $ 65,822 10% $ 289,132 $ 230,592 25%
Oil and Liquids
Revenue 15,240 11,495 33% 62,549 41,930 49%
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Revenue from oil and
gas sales $ 87,497 $ 77,317 13% $ 351,681 $ 272,522 29%
Processing and other
income 2,162 2,543 (15)% 6,846 7,368 (7)%
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Total Revenue $ 89,659 $ 79,860 12% $ 358,527 $ 279,890 28%
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(1) 2006 Revenues have been restated to remove the reduction for
transportation costs


Transportation costs for 2007 were 2.8% of gross revenue or $1.29/boe, which is up from $1.15/boe in 2006. The increase is primarily due to higher NGL transportation costs from the Cecilia gas plant. For the fourth quarter of 2007 transportation costs were 2.7% of gross revenue, consistent with 2.4% of gross revenue in the same period in 2006. Third party processing income of $6.8 million decreased slightly as equity gas increases more than offset the growth in capacity from facility expansion.



Duvernay's royalties are summarized as follows:

Three Months Ended
December 31 Year Ended December 31
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Royalties 2007 2006 Change 2007 2006 Change
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Natural Gas $ 78 $ 6,580 (99)% $ 35,205 $ 35,099 1%
Oil and Liquids 3,046 809 277% 13,401 6,750 99%
ARTC - - - - (500) (100)%
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Total Royalties $ 3,124 $ 7,389 (58)% $ 48,606 $ 41,349 18%
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For the year ended December 31, 2007 the average effective royalty rate was 14% down 1% from the same period in 2006. In the fourth quarter, the Company had an effective royalty rate of 4% compared to 9% for the same quarter in 2006. 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, $27 million was received in 2007 compared to $21.7 in 2006. In addition, a large part of the decrease is due to the timing of recognition of royalty holidays in Alberta. Also, weaker gas prices led to a slight decrease in the effective royalty rate in 2007 compared to 2006. 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. 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 increased from $5.51/boe in 2006 to $5.81/boe in 2007. Total operating expenses for 2007 were $44.5 million compared to $31.8 million for 2006. This increase is attributable mainly to increases in production volumes. For the fourth quarter of 2007, operating expenses were up compared to the same quarter in 2006 ($5.85/boe compared to $5.67/boe). For 2007, the Company was still dealing with some inflationary pressures arising from competition for many field services. On a barrel of oil equivalent basis, third party processing, treating and compression costs were 24% of total operating expenses, consistent with 25% in 2006. For the fourth quarter 2007 third party processing fees per barrel of oil equivalent increased slightly to 23% of operating costs, from 21% in the same period in 2006. Late in 2007 Duvernay commissioned a new 20 mmcfpd gas plant at Sundance and a similar facility is commencing operations in the first quarter of 2008 at Oldman. These new gas plants are expected to result in an overall reduction in Duvernay's 2008 third party processing fees.



General & Administrative Expenses

General and Administrative (G&A) Expenses are summarized as follows:

Three Months Ended Year Ended
December 31 December 31
-----------------------------------------------------------
(000s) 2007 2006 Change 2007 2006 Change
----------------------------------------------------------------------------
General and
administrative
expenses $ 5,956 $ 4,224 41% $ 18,010 $ 14,141 27%
Administrative
and operating
recovery (489) (630) (22)% (1,796) (1,787) 1%
Capital recovery (1,972) (2,064) (4)% (5,833) (6,982) (16)%
Capitalized G&A (1,200) (526) 128% (3,594) (1,786) 101%
Stock based
compensation 4,753 3,137 52% 15,787 10,139 56%
Capitalized
stock based
compensation
(excluding
income tax
effect) (1,992) (1,361) 46% (6,614) (4,398) 50%
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Total G&A $ 5,056 $ 2,780 82% $ 15,960 $ 9,327 71%
Oil equivalent
($/boe) $ 2.50 $ 1.66 51% $ 2.09 $ 1.62 29%
Oil equivalent
cash costs
($/boe) $ 1.13 $ 0.60 88% $ 0.89 $ 0.62 44%
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General and administrative expenses for the year ended December 31, 2007 increased to $16.0 million from $9.3 million for the same period in 2006. On a per unit of production basis, the rate increased from $1.62/boe in 2006 to $2.09 in 2007. On a cash basis, G&A for 2007 increased to $0.89/boe from $0.62/boe in 2006 as operational growth has led to larger administrative spending to maintain a larger proved asset base. Regulatory and governance requirements have also continued to increase leading to a commensurate increase in office costs. In a like manner, fourth quarter 2007 G&A cash costs of $1.13 per boe have increased over the same quarter for 2006 of $0.60 per boe. Stock based compensation expense has increased as the effects of two large issues of employee stock options, one late in 2006 and another in mid-2007, are recognized in income.

The percentage of head office expenses attributed to exploration activities and capitalized was 35% consistent with 2006.

Depletion, Depreciation and Accretion

Depletion, depreciation and site restoration expense increased to $157.8 million during 2007 from $112.1 million during 2006. On a dollars per boe basis, full year unit of production DD&A increased in 2007 to $20.49 from $19.43 in 2006, an increase of 5%. The rate increase is primarily attributable to increases in future development costs associated with the large increases in proved reserves. The 2007 Depletion, Depreciation and Accretion rate of $20.29 is comparable to the one year finding and development costs on proved reserves of $20.83/boe. For the fourth quarter of 2007 the DD&A rate of $22.04/boe compares favourably to $22.53/boe for the fourth quarter of 2006.

Income Taxes

Duvernay did not incur any cash tax expense in 2007. Duvernay does not expect to pay any cash taxes in 2008 based on existing tax pools, planned capital expenditures and the most recent forecast of 2008 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 one to two years. Previously announced federal tax rate reductions 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 and fourth quarters, respectively, resulting in a $0.5 million recovery of full year future income tax expense, compared to a 12% charge to pre-tax income in 2006. The rate reductions announced late in the year created a $12.5 million recovery of future taxes in the fourth quarter of 2007.



Duvernay's tax pools at December 31, 2007 and December 31, 2006 are as
follows:


($ millions) Maximum Deduction 2007 2006
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COGPE 10% $ 37 $ 37
CDE 30% 491 389
CEE 100% 101 144
UCC 25% 368 274
Other 15 13
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$ 1,012 $ 857
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Subsequent to December 31, 2007 Duvernay renounced exploration expenditures related to 2007 flow-through share obligations resulting in reductions of the tax pool balances of $84.6 million.

Funds From Operations and Earnings

Funds from operations increased by 29% to $237.7 million ($4.15 per diluted Equity Share) for the twelve months ending December 31, 2007 from $184.2 million ($3.45 per diluted Equity Share) for the comparable period in 2006. This is due to the growth in production volumes coupled with relatively stable operating netbacks when compared to 2006. Full year funds from operations guidance announced in November of 2007 was $233.4 million ($4.06/diluted share) which was 2% lower than actual results, primarily due to lower royalty rates than originally expected. After tax earnings increased by 5% for 2007 to $61.3 million when compared to 2006 of $58.4 million. On a per share basis, diluted earnings decreased by 2% to $1.07 per share for 2007 compared to $1.09 for 2006.

Fourth quarter after tax earnings increased 109% to $0.48 per diluted equity share in 2007, up from $0.23 for the same period in 2006, due mainly to a reduction in the federal corporate tax rate in late 2007.



Three Months Ended Year Ended
December 31 December 31
------------------------- ---------------------------
2007 2006 Change 2007 2006 Change
----------------------------------------------------------------------------
Fund from Operations
per Equity Share (1) $ 1.17 $ 1.03 14% $ 4.15 $ 3.45 20%

Earnings per Equity
Share (1) $ 0.48 $ 0.23 109% $ 1.07 $ 1.09 (2)%

Operating Netback
per boe $ 37.06 $ 34.92 6% $ 33.80 $ 33.42 1%
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(1) diluted



2007 2006
----------------------------------------------------------------------------
Net Earnings $ 61,293 $ 58,362
Items not involving cash:
Unrealized Loss on Financial Instruments 9,932 -
Depletion, depreciation and accretion 157,803 112,077
Stock-based compensation 9,173 5,741
Future income taxes (547) 7,999
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Funds from Operations $ 237,654 $ 184,179
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Liquidity and Capital Resources

Duvernay invested $489.2 million in 2007 compared to $529.1 million in 2006,
as set out in the following table:

Year Ended December 31
-------------------------------
($ thousands) 2007 2006
----------------------------------------------------------------------------
Land and seismic $ 11,777 $ 44,419
Drilling and completions 379,815 440,331
Facilities 94,072 118,142
Property Acquisition 1,436 37,446
Property Disposition (1,740) (112,277)
Other 3,796 1,038
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Cash investments in Capital Resources $ 489,156 $ 529,099
----------------------------------------------------------------------------


During 2007, Duvernay drilled 94 gross (75.1 net) wells, resulting in 84 gas wells, 7 oil wells, and 3 suspended or abandoned wells. The Company also tied in 106 new wells during 2007. A reduction in both facilities (20% decrease) and land and seismic (73% decrease) spending has led to better capital efficiencies as a larger percentage of the corporations capital program was dedicated to drilling activities than in prior years.

Duvernay's base capital budget for 2008 is $400 million with approximately $60 million allocated to exploration activities and approximately $340 million allocated to development drilling and facilities. The 2008 budget contemplates drilling between 100-110 wells, approximately 95 of which will be development locations. Capital spending plans ensure sufficient exploration capital to discharge previous flow through share issue obligations that come due in 2008. At the end of 2007, such obligations are estimated to be $22.9 million. This capital program will be funded through a combination of cash flow, bank debt and the recently completed equity financing. The Company currently forecasts 2008 Funds from Operations to be $378 million. Subsequent to the end of the year Duvernay has also entered into an agreement to sell certain non-core assets to a private company for cash consideration of $40 million. The assets contribute approximately 625 boepd and the transaction is expected to close in May 2008.

Duvernay participated in the following equity financings during 2007, the proceeds from which were dedicated to the capital spending program:



February flow through-private placement 1,000,000 $41.50 $41,500,000
June public equity issue 1,500,000 $40.35 $60,525,000
October flow through-private placement 1,000,000 $43.10 $43,100,000


The Company estimates that it has completed its commitment to invest $41.5 million in exploration spending from the February 2007 flow through share issue and that approximately $20.2 million of the October 2007 flow through share issue has been spent by December 31, 2007.

At December 31, 2007, Duvernay had a working capital deficiency of $76.4 million and the bank line was drawn to $449.4 million for net debt of $525.8 million or 1.4 times 2008 forecast funds from operations. The Duvernay syndicated bank facility with a group of five banks currently has borrowing capacity of $490 million. In addition the Company has established a $25 million operating line. Based on the strength of the 2007 reserve report, the Corporation estimates that its credit lines can be expanded between 15 - 20% from existing levels. 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 billion demand loan debenture secured by a first floating charge over all assets.



The Company plans on funding the 2008 capital budget as follows:
(millions)
Internally generated cash flow $ 378.0
Minor property asset sales 50.0
Flow through share equity issue(1) 30.0
--------
2008 Cash inflows 458.0
2008 Capital Budget 400.0
--------
Excess dedicated to reduction in working capital deficiency 58.0
--------
(1) completed in February 2008


Duvernay's growth plan includes funding the future development costs related to proved reserves of $700.2 million over the next 3 to 5 years in an orderly manner primarily from internally generated cash flow.

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 ($515 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 increased slightly in 2007 to 5.4% from 4.44% in 2006. Interest expense increased to $21.1 million in 2007.

As at December 31, 2007, the Company had issued and outstanding common shares of 58,481,774 and outstanding stock options of 5,777,818. As at March 20, 2008 the Company had issued and outstanding common shares of 59,482,774 and outstanding stock options of 5,546,817.

Financial Instruments

The Company makes use of specific commodity financial 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 2008 and 2009 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 are 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.

Contracts in place at March 20, 2008:



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

AECO Fixed Price 3,000 gjs/day April - October 2008 $6.45 Cdn/gj
January - December
AECO Fixed Price 10,000 gjs/day 2008 $6.45 Cdn/gj average
AECO Fixed Price 21,000 gjs/day January - March 2008 $6.62 Cdn/gj average
AECO Fixed Price 5,000 gjs/day January - March 2008 $6.63 Cdn/gj
W.T.I. Fixed Price 100 bbls/day April - June 2008 $90.70 U.S./bbl
W.T.I. Fixed Price 100 bbls/day Jan - Dec 2008 $86.25 U.S./bbl
W.T.I. Fixed Price 200 bbls/day Jan - Dec 2008 $90.77 U.S./bbl
W.T.I. Fixed Price 100 bbls/day Jan - June 2008 $88.10 U.S./bbl
W.T.I. Fixed Price 200 bbls/day Jan - Mar 2008 $86.68 U.S./bbl
average
AECO Fixed Price(i) 35,000 gjs/day April - October 2008 $7.06 Cdn/gj average
April - December
AECO Fixed Price(i) 12,000 gjs/day 2008 $7.43 Cdn/gj average
AECO Costless
Collar(i) 10,000 gjs/day April - October 2008 $8.00 Cdn/gj ceiling
$6.70 Cdn/gj floor
Stn #2 Fixed
Price(i) 15,000 gjs/day April - October 2008 $7.30 Cdn/gj average
November 2008 -
AECO Fixed Price(i) 15,000 gjs/day March 2009 $8.65 Cdn/gj average
AECO Written
Call(i) 10,000 gjs/day April - October 2008 $7.00 Cdn/gj

(i) Contract(s) entered into in 2008



DUVERNAY OIL CORP.
SELECTED QUARTERLY INFORMATION

2007
Q4 Q3 Q2 Q1
---------------------------------------------------------------------------

PRODUCTION
Crude oil and liquids (bbls) 184,732 205,034 247,865 202,719
Gas (mcf) 11,046,655 9,834,454 9,930,573 10,060,881
Oil equivalent (boe) 2,025,840 1,844,110 1,902,961 1,879,533
Crude oil and liquids (bbls/d) 2,008 2,229 2,724 2,252
Gas (mcf/d) 120,072 106,896 109,127 111,788
Oil equivalent (boe/d) 22,020 20,045 20,912 20,884
---------------------------------------------------------------------------

FINANCIAL
($ thousands, except as noted)
Gross Revenue, net of
royalties 86,536 63,531 84,880 74,976
Cash Flow from Operations 49,800 55,794 64,871 68,757
Funds from operations 69,094 45,107 59,757 63,696
Per share basic 1.17 0.79 1.06 1.16
Net earnings 28,432 3,530 18,643 10,688
Per share basic 0.49 0.06 0.33 0.19
Per share diluted 0.48 0.06 0.33 0.19
Total assets 1,613,649 1,506,322 1,408,797 1,376,671
Bank debt 449,377 399,452 399,452 374,585
Cash and working capital
(deficiency) (76,355) (88,555) (7,213) (72,948)
Basic outstanding shares 58,482 57,445 57,357 55,608
---------------------------------------------------------------------------

PER UNIT
Gas, net of transportation
($/mcf) 6.79 6.23 7.54 8.05
Crude oil and liquids, net of
transportation ($/bbl) 81.56 71.76 62.11 68.87(1)
Revenue, net of
transportation ($/boe) 44.46 41.27 47.46 50.68(1)
Operating netback ($/boe) 37.06 27.51 34.30 35.97(1)
---------------------------------------------------------------------------


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)
Gross Revenue, net
of royalties 72,472(2) 60,355(2) 52,183(2) 53,531(2)
Cash Flow from
Operations 53,904 32,940 41,868 47,086
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
----------------------------------------------------------------------------
(1) restated to include realized hedging gains
(2) restated to exclude transportation costs


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. Volume and revenue growth in the third quarter of 2007 was muted by facility restrictions, shut-ins and decreases in market prices.



DUVERNAY OIL CORP.
SELECTED ANNUAL
INFORMATION
2007 2006 2005
----------------------------------------------------------------------------

PRODUCTION
Crude oil and liquids (bbls) 840,350 621,759 813,502
Gas (mcf) 40,872,563 30,885,399 18,046,197
Oil equivalent (boe) 7,652,444 5,769,326 3,821,202
Crude oil and liquids (bbls/d) 2,303 1,703 2,229
Gas (mcf/d) 111,980 84,618 49,442
Oil equivalent (boe/d) 20,966 15,806 10,469
----------------------------------------------------------------------------

FINANCIAL
($ thousands, except as noted)
Gross Revenue 358,527 279,890(1) 212,967(1)
Cash Flow from Operations 239,222 175,798 121,853
Funds from operations 237,654 184,179 137,454
Per share basic 4.19 3.54 2.94
Net earnings 61,293 58,362 50,075
Per share basic 1.08 1.12 1.07
Per share diluted 1.07 1.09 1.02
Total assets 1,613,649 1,272,571 827,263
Bank Debt 449,377 324,590 175,481
Cash and working capital (deficiency) (76,355) (93,537) (40,180)
Basic outstanding shares 58,482 53,962 49,345
----------------------------------------------------------------------------

PER UNIT
Gas ($/mcf) 7.15 7.30 8.93
Crude oil and liquids ($/bbl) 70.71 65.05 55.73
Revenue ($/boe) 45.97 46.09 54.02
Operating netback ($/boe) 33.80 33.42 37.57
----------------------------------------------------------------------------
(1) restated to exclude transportation costs


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

Commitments and Contractual Obligations

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



Payments due by period
Less
than 1 - 3 4 - 5 There-
($millions) Total 1 year years years after
---------------------------------------------------------------------------
Long-term debt $ 449.4 $ - $ 449.4 $ - $ -
Flow-through obligation 53.3 22.9 30.4 - -
Operating leases 1.0 0.6 0.3 0.1 -
Firm transportation
agreements 23.0 8.4 11.2 3.2 0.2
---------------------------------------------------------------------------
$ 526.7 $ 31.9 $ 491.3 $ 3.3 $ 0.2
---------------------------------------------------------------------------

Drilling Results

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

2007 2006
------------------------------------------------------------------------
Gross Net Gross Net
------------------------------------------------------------------------
Natural gas 84 65.4 112 84.4
Crude oil 7 6.3 7 5.6
Suspended 2 2.5 5 4.2
Dry and abandoned 1 0.9 2 1.5
------------------------------------------------------------------------
Total wells 94 75.1 126 95.7
------------------------------------------------------------------------

Landholdings

Duvernay's developed and undeveloped landholdings as at December 31, 2006
and 2007 are set forth below (excludes land held under option):

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


2007
-------------------------------------------------------------------------
Alberta 230,666 160,908 132,800 85,478 363,466 246,386
British Columbia 106,210 89,548 117,932 113,312 224,142 202,860
-------------------------------------------------------------------------
Total 336,876 250,456 250,732 198,790 587,608 449,246
-------------------------------------------------------------------------


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 Depreciation 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 charged 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.

Changes In Accounting Policies

FINANCIAL INSTRUMENTS/OTHER COMPREHENSIVE INCOME/HEDGES

In 2005, the CICA approved Handbook section 3855 "Financial Instruments - Recognition and Measurement, "section 1530 "Comprehensive Income" and section 3865"Hedges". Effective January 1, 2007, these standards require the presentation of financial instruments at fair value on the balance sheet.

Under adoption of these standards, cash and cash equivalents are designated as held-for-trading and are measured at carrying value, which approximates fair value due to the short-term nature of these instruments. Accounts receivable and accrued revenues are designated as loans and receivables. Accounts payable and accrued liabilities and long-term debt are designated as other liabilities. Risk management assets and liabilities are derivative financial instruments classified as held-for-trading, see further discussion in note 1(a) of the financial statements.

These standards must be applied prospectively with an initial recognition adjustment to retained earnings and accumulated other comprehensive income. Upon implementation and initial measurement under the new standards at January 1, 2007, the following adjustments were recorded to the balance sheet:



Increase (decrease) At January 1, 2007
-------------------------------------------------------------------------
Fair value of financial instruments $ 9,600
Future income tax liability (3,124)
Retained earnings 6,476
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Additional disclosure requirements for financial instruments have been approved by the CICA, and will be required disclosure for the Company beginning January 1, 2008.

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 2007, 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, 2007, 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.

Convergence with International Reporting Standards

On February 13, 2008, Canada's Accounting Standards Board confirmed January 1, 2011 as the effective date for the convergence of Canadian GAAP to International Financial Reporting Standards. The Canadian Securities Administrators are in the process of examining changes to securities rules as a result of this initiative. As this change initiative is in its infancy, Duvernay has not determined its impact on its financial position or results of operations.

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.

Impact of New Environmental Regulations

Environmental legislation, including the Kyoto Accord, the federal government's "EcoACTION" plan and Alberta's Bill 3 - Climate Change and Emissions Management Amendment Act, is evolving in a manner expected to result in stricter standards and enforcement, larger fines and liability and potentially increased capital expenditures and operating costs.

Given the evolving nature of the debate related to climate change and the resulting requirements, it is not possible to determine the operational or financial impact of those requirements on Duvernay.

Impact of Changes in Alberta Royalty Regulations

On October 25, 2007, the Government of Alberta announced changes to conventional oil and gas royalties. These changes are to be implemented effective January 1, 2009. Using currently available information, Duvernay has estimated that the impact on 2007 cash flow based on current gas prices would result in approximately a 7% cash flow reduction. The Alberta Deep Gas Royalty holiday will be eliminated, replaced under the new system by a royalty rate adjustment for "Deep Marginal Gas Wells". Based on the average depth of a Duvernay Deep Basin gas well, the impact on full cycle project economics is expected to be minimal.

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.



Financial Statements of DUVERNAY OIL CORP.

Years ended December 31, 2007 and 2006



DUVERNAY OIL CORP.
Balance Sheets

December 31, 2007 and 2006
(Thousands of Dollars)

----------------------------------------------------------------------------
----------------------------------------------------------------------------
2007 2006
----------------------------------------------------------------------------

Assets

Current assets:
Accounts receivable $ 61,171 $ 62,446
Fair value of financial instruments (note 7) 728 -
Prepaid expenses and deposits 1,148 1,230
----------------------------------------------------------------------------
63,047 63,676

Investment 15,000 15,000

Property, plant and equipment (note 2) 1,535,602 1,193,895

----------------------------------------------------------------------------
$ 1,613,649 $ 1,272,571
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Liabilities and Shareholders' Equity

Current liabilities:
Accounts payable and accrued liabilities 138,342 157,213
Fair value of financial instruments (note 7) 1,060 -
----------------------------------------------------------------------------
139,402 157,213

Long-term debt (note 3) 449,377 324,590

Asset retirement obligations (note 4) 15,424 11,686

Future income tax (note 6) 128,877 95,799

Shareholders' equity:
Share capital (note 5) 649,473 531,651
Contributed surplus (note 5) 24,018 12,323
Retained earnings 207,078 139,309
----------------------------------------------------------------------------
880,569 683,283
Commitments (note 10)

Subsequent events (notes 7 and 9)
----------------------------------------------------------------------------
$ 1,613,649 $ 1,272,571
----------------------------------------------------------------------------
----------------------------------------------------------------------------

See accompanying notes to financial statements.



DUVERNAY OIL CORP.
Statements of Earnings, Comprehensive Income and Retained Earnings

Years ended December 31, 2007 and 2006
(Thousands of Dollars, Except Per Share Amounts)

----------------------------------------------------------------------------
----------------------------------------------------------------------------
2007 2006
----------------------------------------------------------------------------
Revenue:
Petroleum and natural gas $ 339,491 $ 272,522
Realized gain on financial instruments 22,122 -
Unrealized gain (loss) on financial
instruments (9,932) -
----------------------------------------------------------------------------
351,681 272,522
Royalties (48,606) (41,349)
Processing and other income 6,846 7,368
----------------------------------------------------------------------------
309,921 238,541

Expenses:
Operating 44,453 31,760
Transportation 9,866 6,625
General and administration 6,787 3,586
Stock-based compensation 9,173 5,741
Interest 21,093 12,391
Depletion, depreciation and accretion 157,803 112,077
----------------------------------------------------------------------------
249,175 172,180

----------------------------------------------------------------------------
Earnings before taxes 60,746 66,361

Future Income taxes (note 6) (547) 7,999

----------------------------------------------------------------------------
Net earnings and comprehensive income 61,293 58,362

Retained earnings, beginning of year 139,309 80,947
Change in accounting policy (note 1) 6,476

----------------------------------------------------------------------------
Retained earnings, end of year $ 207,078 $ 139,309
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Earnings per share:
Basic $ 1.08 $ 1.12
Diluted $ 1.07 $ 1.09
----------------------------------------------------------------------------
----------------------------------------------------------------------------

See accompanying notes to financial statements.


DUVERNAY OIL CORP.
Statements of Cash Flows

Years ended December 31, 2007 and 2006
(Thousands of Dollars)

----------------------------------------------------------------------------
----------------------------------------------------------------------------
2007 2006
----------------------------------------------------------------------------

Cash provided by (used in):

Operations:
Net earnings $ 61,293 $ 58,362
Items not involving cash:
Depletion, depreciation and accretion 157,803 112,077
Stock-based compensation 9,173 5,741
Future income taxes (547) 7,999
Unrealized loss (gain) on financial instruments 9,932 -
Abandonment expenditures - (380)
Change in non-cash operating working
capital (note 8) 1,568 (8,001)
----------------------------------------------------------------------------
239,222 175,798

Financing:
Issue of common shares, net of
share issue costs 144,229 159,216
Increase in long-term debt 124,787 149,109
----------------------------------------------------------------------------
269,016 308,325

Investments:
Additions to property, plant and equipment (489,527) (605,324)
Property acquisitions (1,369) (37,434)
Property dispositions 1,740 97,277
Change in non-cash working capital (note 8) (19,082) 61,358
----------------------------------------------------------------------------
(508,238) (484,123)

----------------------------------------------------------------------------
Change in cash - -

Cash, beginning of year - -

----------------------------------------------------------------------------
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, 2007 and 2006
(tabular amounts in thousands of dollars, except per share amounts)

Nature of operations:

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

1. Significant accounting policies:

(a) Change In Accounting Policy

On January 1, 2007, the Company adopted the new Canadian accounting standards for financial instruments-recognition and measurement, financial instruments-presentation and disclosures, hedging and comprehensive income. Prior periods have not been restated.

At January 1, 2007, the following adjustments were made to the balance sheet relating to the fair value of derivative contracts, to adopt the new standards:



Increase (decrease) At January 1, 2007
----------------------------------------------------------------------------
Fair value of financial instruments $ 9,600
Future income tax liability (3,124)
Retained earnings 6,476
----------------------------------------------------------------------------
----------------------------------------------------------------------------


(i)Financial Instruments-Recognition And Measurement

Financial instruments are required to be measured at fair value on the balance sheet upon initial recognition of the instrument. Measurement in subsequent periods depends on whether the financial instrument has been classified in one of the following categories: held-for-trading, available-for-sale, held-to-maturity, loans and receivables, or other financial liabilities as defined under the new standard.

Under adoption of these standards, cash and cash equivalents are designated as held-for-trading and are measured at carrying value, which approximates fair value due to the short-term nature of these instruments. Accounts receivable and accrued revenues are designated as loans and receivables. The investment is a non-derivative portfolio investment that is not quoted in an active market, therefore it has not been marked-to-market. Accounts payable and accrued liabilities and long-term debt are designated as other liabilities. Risk management assets and liabilities are derivative financial instruments classified as held-for-trading, see further discussion below.

Additional disclosure requirements for financial instruments have been approved by the CICA, and will be required disclosure for the Company beginning January 1, 2008.

(ii) Derivatives

The Company continues to utilize derivatives, such as commodity sales contracts requiring physical delivery, to manage the price risk attributable to anticipated sale of petroleum and natural gas production. Refer to note 7 for additional disclosure on the Company's risk management objectives.

The Company has elected to account for its commodity contracts, whose purpose is to be held for receipt or delivery of non-financial items in accordance with the expected purchase, sale or usage requirements on a mark-to-market basis. Prior to adoption of the new standards, physical receipt and delivery contracts did not fall within the scope of the definition of a financial instrument and were accounted for on an accrual basis.

(iii) Embedded Derivatives

On adoption, the Company elected to recognize, as separate assets and liabilities, only for those embedded derivatives in hybrid instruments issued, acquired or substantively modified after January 1, 2003. The Company did not identify any significant embedded derivatives which required separate recognition and measurement.

(iv) Effective Interest Method

Transaction costs attributable to financial instruments classified as other than held-for-trading are included in the recognized amount of the related financial instrument and expensed over the life of the resulting financial instrument using the effective interest rate method. Prior to January 1, 2007, transaction costs were recorded as deferred charges and recognized in net earnings on a straight-line basis over the life of the financial instrument. On adoption, transaction costs are amortized using the effective interest rate method.

(v) Comprehensive Income

The new accounting standards for financial instruments, hedging and comprehensive income introduced the statements of comprehensive income and accumulated other comprehensive income to temporarily provide for gains, losses and other amounts arising from changes in fair value until they are realized and recorded in net earnings. The Company has determined that it had no items that would affect comprehensive income nor accumulated other comprehensive income for the period ended December 31, 2007 and therefore comprehensive income equals net income.

(vi) Transition to International Financial Reporting Standards

On February 13, 2008, Canada's Accounting Standards Board confirmed January 1, 2011 as the effective date for the convergence of Canadian GAAP to International Financial Reporting Standards. The Canadian Securities Administrators are in the process of examining changes to securities rules as a result of this initiative. As this change initiative is in its infancy, Duvernay has not determined its impact on its financial position or results of operations.

(b) 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, exploration and development activities, including capitalized stock-based compensation and related income tax effect.

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. If the carrying value of the petroleum and natural gas assets is not assessed to be recoverable, an impairment loss is recognized to the extent that the carrying value exceeds the sum of the discounted cash flows expected from the production of proved and probable reserves and the lower of cost and market of unproved properties. 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.

(c) 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.

(d) Cash and cash equivalents:

Cash is defined as cash and investments with a maturity of three months or less.

(e) 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.

(f) 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 future 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.

(g) 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. Financial instruments are based on estimates of the amounts that would have to be received or paid to settle the instruments prior to maturity given market prices and other relevant factors. Actual results could differ from these estimates.

(h) 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, consideration received, together with the amount previously recognized in contributed surplus, is recorded as an increase to share capital.

(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.



----------------------------------------------------------------------------
----------------------------------------------------------------------------
Accumulated Net book
2007 Cost depletion value
----------------------------------------------------------------------------

Petroleum and natural gas properties $ 1,731,513 347,860 $ 1,383,653
Gas processing facilities 174,783 23,471 151,312
Furniture, fixtures and leasehold
improvements 1,511 874 637

----------------------------------------------------------------------------
$ 1,907,807 372,205 $ 1,535,602
----------------------------------------------------------------------------
----------------------------------------------------------------------------

2006
----------------------------------------------------------------------------

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


The cost of unproven lands at December 31, 2007 of $111.6 million (2006 - $87.2 million) has been excluded from the depletion calculation. Future development costs of proved reserves in 2007 of $700.7 million (2006 - $354.0 million) have been included in the depletion calculation.

General and administrative expenditures of $10.2 million (2006 - $6.2 million) 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 $5.0 million. The future tax liability of $1.7 million associated with the capitalized stock-based compensation has also been capitalized.



At December 31, 2007, the Company applied a ceiling test to its petroleum
and natural gas assets using expected future market prices of:

Benchmark reference price 2013-
forecast 2008 2009 2010 2011 2012 2018
----------------------------------------------------------------------------
WTI ($US/bbl) 92.00 88.00 84.00 82.00 82.00 82.84
AECO ($Cdn/mcf) 6.75 7.55 7.60 7.60 7.60 8.05
Exchange Rate ($Cdn/$US) 1.00 1.00 1.00 1.00 1.00 1.00


After 2018 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 syndicate of banks for an extendible revolving term loan in the amount of $490 million in addition to a $25 million operating line. As at December 31, 2007, $449,377,000 (2006 - $324,590,000) 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 2008, 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 5.4% for the year ended December 31, 2007.

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 $39,194,031 (2006 - $31,946,000) which will be incurred between 2015 and 2023. A credit-adjusted risk-free rate of 7% (2006 - 7%) and an inflation rate of 3% (2006 - 3%) were used to calculate the fair value of the asset retirement obligations.



A reconciliation of the asset retirement obligations is provided below:

----------------------------------------------------------------------------
----------------------------------------------------------------------------
2007 2006
----------------------------------------------------------------------------

Balance, beginning of year $ 11,686 $ 9,491
Accretion expense 1,019 696
Liabilities incurred 2,719 3,368
Change in estimate - 230
Liabilities settled - (380)
Dispositions - (1,719)
----------------------------------------------------------------------------
Balance, end of year $ 15,424 $ 11,686
----------------------------------------------------------------------------


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, 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
For cash on private placement of flow-through shares 2,000,000 84,600
For cash on public share issue 1,500,000 60,525
For cash on exercise of stock options 1,020,167 6,270
Contributed surplus on exercise of stock options - 2,418
Share issue costs - (7,166)
Tax effect on share issue costs - 1,815
Tax effect on flow-through renunciation - (30,640)
----------------------------------------------------------------------------
Balance, December 31, 2007 58,481,774 $ 649,473
----------------------------------------------------------------------------
----------------------------------------------------------------------------


On June 5, 2007, the Company completed a bought-deal private placement of 1,500,000 common shares at $40.35 per share for gross proceeds of $60.5 million.

(c) Flow-through Shares:

On February 27, 2007 Duvernay issued 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. On October 4, 2007 the Company issued 1,000,000 common shares on a flow-through basis at an issue price of $43.10 for gross proceeds of $43.1 million. Effective December 31, 2007 the Company renounced $84.6 million to be incurred on qualifying expenditures on or before December 31, 2008.

During the year ending December 31, 2007 Duvernay fulfilled its remaining obligation of $104.125 million of capital expenditures related to its 2006 flow-through offerings of the same amount. As at December 31, 2007 the Company estimates that it fulfilled its obligation on the February 2007 offering and has a $22.9 million remaining obligation for the October 2007 offering which must be completed by December 31, 2008.



(d) Contributed surplus:

----------------------------------------------------------------------------
----------------------------------------------------------------------------
2007 2006
----------------------------------------------------------------------------

Contributed surplus, beginning of year $ 12,323 $ 4,915
Stock-based compensation 14,113 8,833
Exercise of stock options (2,418) (1,425)

----------------------------------------------------------------------------
Contributed surplus, end of year $ 24,018 $ 12,323
----------------------------------------------------------------------------
----------------------------------------------------------------------------


(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:

----------------------------------------------------------------------------
----------------------------------------------------------------------------
2007 2006
---------------------- -----------------------
Weighted Weighted
Average Average
Number of Exercise Number of Exercise
Options Price Options Price
----------------------------------------------------------------------------

Stock options outstanding,
beginning of year 5,119,985 $ 23.51 4,653,284 $ 14.44
Granted 1,718,000 35.87 1,733,000 34.81
Exercised (1,020,167) 6.15 (1,266,299) 5.61
Forfeitures (40,000) 30.59 - -

----------------------------------------------------------------------------
Stock options outstanding,
end of year 5,777,818 $ 30.21 5,119,985 $ 23.51
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Exercisable, end of year 2,570,318 $ 23.65 2,117,818 $ 11.69
----------------------------------------------------------------------------
----------------------------------------------------------------------------


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

$ 3.50-6.25 541,152 5.73 0.74 541,152 5.73
10.90-17.18 558,499 15.14 1.77 558,499 15.14
25.20-39.00 4,678,167 34.84 3.74 1,470,667 33.47
----------------------------------------------------------------------------
5,777,818 30.21 3.27 2,570,318 23.65
----------------------------------------------------------------------------
----------------------------------------------------------------------------


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:



----------------------------------------------------------------------------
----------------------------------------------------------------------------
2007 2006
----------------------------------------------------------------------------

Risk-free interest rate (%) 4.0 - 4.5 4.5
Expected life (in years) 3.5 3.5
Expected volatility (%) 30 - 40 30 - 40
Expected dividend - -
Expected forfeitures (%) 10 10
----------------------------------------------------------------------------


The weighted average fair value of the stock options granted during the year was $13.90 (2006 - $10.52) 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, 2007 was 56,710,487 (2006 - 52,069,456).

In computing diluted earnings per share for the period ended December 31, 2007, 590,883 (2006 - 1,243,889) 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 3,910,500 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:



----------------------------------------------------------------------------
----------------------------------------------------------------------------
2007 2006
----------------------------------------------------------------------------

Earnings before taxes $ 60,746 $ 66,361
----------------------------------------------------------------------------

Combined federal and provincial tax rate 32.5% 34.8%

Computed "expected" income tax expense $ 19,721 $ 23,124

Increase (decrease) resulting from:
Effect of change in tax rate (23,252) (14,758)
Stock based compensation and other 2,984 2,361
Non-deductible Crown charges - 4,508
Resource allowance - (7,236)

----------------------------------------------------------------------------
Future Income Taxes $ (547) $ 7,999
----------------------------------------------------------------------------
----------------------------------------------------------------------------


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

----------------------------------------------------------------------------
----------------------------------------------------------------------------
2007 2006
----------------------------------------------------------------------------

Future tax liabilities:
Property, plant and equipment 136,615 103,162

Future tax assets:
Asset retirement obligation $ (3,909) $ (3,439)
Share/Debt issue expenses (3,744) (3,924)
Net unrealized loss on financial instruments (85) -
----------------------------------------------------------------------------
(7,738) (7,363)

----------------------------------------------------------------------------
Net future tax liability $ 128,877 $ 95,799
----------------------------------------------------------------------------
----------------------------------------------------------------------------


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 marketers 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:

The fair value of all outstanding non-financial commodity contracts are reflected on the balance sheet with the change in fair value recognized as an unrealized gain or loss in income.



The following table reconciles the changes in the fair value of financial
instruments outstanding on December 31, 2007:

Fair value of financial instruments December 31, 2007
----------------------------------------------------------------------------
Balance, January 1, 2007 (note 1) $ 9,600
Unrealized loss on financial instruments (9,932)
----------------------------------------------------------------------------
Fair value of financial instruments, December 31, 2007 (332)
----------------------------------------------------------------------------
Fair value of financial instrument asset, December 31, 2007 728
Fair value of financial instrument liability,
December 31, 2007 (1,060)
----------------------------------------------------------------------------


As at December 31, 2007, the Company had fixed the price applicable to
future production as follows:

Fair
Volume Remaining Term Pricing Value

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

AECO April -
Fixed Price 3,000 gj's/day October 2008 $6.45 Cdn/gj (19)
AECO January -
Fixed Price 10,000 gj's/day December 2008 $6.45 Cdn/gj average (329)
AECO January -
Fixed Price 21,000 gj's/day March 2008 $6.62 Cdn/gj average 614
AECO January -
Fixed Price 5,000 gj's/day March 2008 $6.63 Cdn/gj 114
W.T.I. April -
Fixed Price 100 bbls/day June 2008 $90.70 U.S./bbl (28)
W.T.I.
Fixed Price 100 bbls/day Jan - Dec 2008 $86.25 U.S./bbl (243)
W.T.I.
Fixed Price 200 bbls/day Jan - Dec 2008 $90.77 U.S./bbl (167)
W.T.I.
Fixed Price 100 bbls/day Jan - June 2008 $88.10 U.S./bbl (117)
W.T.I.
Fixed Price 200 bbls/day Jan - Mar 2008 $86.68 U.S./bbl average (157)

----------------------------------------------------------------------------
Total Fair Value (332)
----------------------------------------------------------------------------


The Company has entered into the following contracts subsequent to December
31, 2007:


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

April -
AECO Fixed Price 35,000 gjs/day October 2008 $7.06 Cdn/gj average
April -
AECO Fixed Price 12,000 gjs/day December 2008 $7.43 Cdn/gj average
April -
AECO Costless Collar 10,000 gjs/day October 2008 $8.00 Cdn/gj ceiling
$6.70 Cdn/gj floor
April -
Stn #2 Fixed Price 15,000 gjs/day October 2008 $7.30 Cdn/gj average
November 2008 -
AECO Fixed Price 15,000 gjs/day March 2009 $8.65 Cdn/gj average
April -
AECO Written Call 10,000 gjs/day October 2008 $7.00 Cdn/gj

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


8. Supplemental Cash Flow Information:

2007 2006
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Accounts receivable $ 1,275 $ (4,231)
Prepaid expenses 82 (700)
Accounts payable and accrued liabilities (18,871) 58,288
----------------------------------------------------------------------------
Change in non-cash working capital $ (17,514) $ 53,357
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Relating to:
Operations $ 1,568 $ (8,001)
Investments (19,082) 61,358
----------------------------------------------------------------------------
Change in non-cash working capital $ (17,514) $ 53,357
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Interest and taxes paid:
----------------------------------------------------------------------------
Interest paid $ (23,450) $ (13,529)

Taxes paid - (1,279)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


9. Subsequent Event

On March 4, 2008 Duvernay completed an equity financing, issuing 720,000 common shares on a flow-through basis at an issue price of $42.25 per share for gross proceeds of $30.42 million.

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 Total 2008 2009- 2010- Thereafter
2010 2011
----------------------------------------------------------------------------

Operating leases 1,069 613 340 116 -
Firm transportation
agreements 22,936 8,354 11,175 3,238 169
----------------------------------------------------------------------------
$ 24,005 $ 8,967 $ 11,515 $ 3,354 $ 169
----------------------------------------------------------------------------


CONFERENCE CALL

A conference call will be held at 1000hr MST (1200hr EST) today. To listen to the conference call please dial 416.644.3414 in Toronto, or 800.733.7560 outside of Toronto. The reservation ID# is 21260172.

The conference call replay will be available from 11:30 on March 20, 2008 until 23:59 on April 3, 2008 by dialing 416.640.1917 in Toronto or 877.289.8525 outside of Toronto (toll free). The Passcode will be 21260172#.

FORWARD LOOKING INFORMATION

Certain information set forth in this press release contains forward-looking statements. Forward-looking statements are subject to numerous risks and uncertainties, some 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 lack of availability of qualified personnel or 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 imprecise 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 that 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.

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

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.

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