Duvernay Oil Corp.
TSX : DDV

Duvernay Oil Corp.

November 08, 2007 17:22 ET

Duvernay Oil Corp.: NEBC Exploration Discoveries and Sundance Gas Plant Start-Up Highlight Recent Activities

CALGARY, ALBERTA--(Marketwire - Nov. 8, 2007) - Duvernay Oil Corp. (TSX:DDV) -

HIGHLIGHTS

- THE SUNDANCE ALBERTA GAS PLANT START-UP ON NOVEMBER 5 HAS ALLOWED FOR RECORD PRODUCTION LEVELS OF 24,600.

- SIGNIFICANT DEEP EXPLORATION DISCOVERY AT GROUNDBIRCH B.C.

- STRONG RESERVE PERFORMANCE THUS FAR IN 2007.

- APPROVAL OF A $400 MILLION 2008 CAPITAL PROGRAM.

- SIGNIFICANT PRODUCTION AND RESERVE OPPORTUNITY AT DAWSON EMPLOYING NEW TECHNOLOGY TO ENHANCE RECOVERY IN DUVERNAY'S BLUESKY HEAVY OIL ASSET.

- HIGH RATE, NEW POOL OIL DISCOVERY IN NORTHEAST B.C.

PRODUCTION OUTLOOK

Third quarter 2007 production was 20,045 boepd, a 25% increase over third quarter 2006. Third quarter 2007 production was negatively impacted by several factors including:

1. Third party facility restrictions in the Sundance area resulting in a production drop of 750 boepd from second quarter 2007. In addition, a further 10.0 mmcfpd of incremental new production remained shut-in. The start-up of the new Duvernay operated Sundance plant on November 5 has eliminated this production issue, adding approximately 2,000 boepd of production.

2. Third party facility restrictions in the Fir Oldman area of Alberta resulted in over 12.5 mmcfpd of new production remaining shut-in. Both the 100% Duvernay interest Fir 14-36 and Fir 13-4 high rate gas wells were tied in during early August but were never brought on production in the quarter due to unforeseen, ongoing third party facility issues in the general area. These wells will likely not be brought on production until the Duvernay Oldman gas plant is completed in February 2008.

3. Shut in of Duvernay's Seal Bluesky gas pool in July reduced third quarter volumes by 200 boepd. The Company participated in an EUB hearing related to the pool in October and is awaiting a decision regarding future production. Dawson oil volumes were also reduced due to weather related access, reducing volumes by a further 150 boepd.

4. Intermittent, unplanned production interruptions in the Deep Basin resulted in an additional 300 boepd reduction during the quarter.

With the start-up of the Sundance plant on November 5, Duvernay's average daily production volumes have reached 24,600 boepd, more than 20% ahead of Duvernay's third quarter average. Further tie-ins at Wroe Creek, Brassey, Sundown and Fir are expected to yield a 2007 exit volume in the 27,000-28,000 boepd range. Given the third quarter curtailments and other delays in start-ups, the Company expects a full year daily production average of 21,500 boepd. The Company is expecting average daily production volumes of between 29,000 and 30,000 boepd for 2008, representing an annual growth range of 35-40%, comparable to 2007 growth. The 2008 estimates do not include contributions from Exploration activities, including recent Sunset-Groundbirch Paleozoic discoveries.

CAPITAL PROGRAM AND FINANCIAL OUTLOOK

Capital spending during the first nine months was $346 million. Duvernay expects full year capital spending of $430.0 million, reflecting the somewhat reduced drilling and completion activity in the fourth quarter. Nine month 2007 capital spending was 15% lower than the comparable period in 2006, while maintaining the same level of drilling and completion activity. As previously disclosed, the Company is focusing capital almost entirely on drilling, completions and tie-ins, yielding steadily improving capital efficiencies. Nine month 2007 land expenditures were $3.1 million compared to $33.1 million in 2006 as the undeveloped land inventory in the two large gas complexes continues to be expanded primarily through farm-ins rather than Crown land sales. The majority of the new lands are targeting zones at 3,000 metres or deeper hence the new proposed royalty regime for 2009 will have only a minimal impact. The Company has experienced a significant reduction in service costs related to drilling and completion operations during the past four months.

Duvernay plans to continue to pursue minor, non-core asset sales during the balance of the year and has initiated a review of the company's LOC with the existing banking syndicate. The Company expects to have the review completed and anticipated LOC increase, driven by very strong reserve performance thus far in 2007, in place by early December. Subsequent to the end of the third quarter Duvernay completed a $43.1 million flow through share offering, further strengthening the company's financial position.

The Board of Directors of Duvernay has approved a 2008 base case capital budget of $400.0 million. The main highlights and objectives of the 2008 capital program are as follows:

- Maintain annual production and reserve growth of 35-40%, reaching 30,000 boepd by Q3 2008.

- Complete Alberta Deep Basin facility network with Q1 start-up of Oldman plant and expansion of Wroe facility in turn achieving corporate operating cost target of $5.00/boe.

- Delineate and expand emerging Paleozoic gas play at Sunset-Groundbirch.

- Execute Phase 1 West Groundbirch EP gas project establishing first production by Q2 2008.

- Establish connection to McMahon sour plant in NEBC by Q2 2008 via joint Duvernay/Duke project.

- Test large volume, deep Edson gas exploration prospect in Q1 2008.

RESERVE UPDATE

Duvernay expects 2007 reserve performance to be equal to or better than the top quartile reserve growth achieved in 2006. Significant increases have been realized in all reserve categories thus far in 2007, the Company estimates that it has added approximately 20.0 mmboe to proved producing reserves, a 62% increase over 2006. To expedite year-end reserve reporting, Duvernay has commenced reviews of certain areas and properties within the overall EP portfolio. Thus far one such independent evaluation has been completed, at Wroe Creek in the Alberta Deep Basin, yielding an 8.64 mmboe total proved reserve addition, net of production, through activity in the first eight months of 2007. The Wroe Creek area represents approximately 25% of the Company's total Deep Basin activities in 2007. Drilling results and well performance in the other Deep Basin activity areas has been equally strong.

DRILLING OUTLOOK

Duvernay operated between 11 and 12 drilling rigs during the majority of the third quarter. This rig fleet was reduced to six rigs during October and increased to seven during the past two weeks. A first quarter 2008 drilling fleet of between 8 and 10 rigs is planned, with the level of activity contingent upon natural gas prices.

SUNSET-GROUNDBIRCH NEBC

Duvernay is currently operating four drilling rigs in NEBC pursuing a suite of Triassic Doig development targets, new Triassic Montney gas opportunities, and large volume deep Paleozoic gas prospects. The Company is enjoying success throughout this portfolio.

During the past 18 months the Company has successfully completed 14 Triassic Montney gas zones in vertical wells, generally as a complementary deeper zone to the main Doig gas zone uphole. This widely spaced evaluation program of the Company's 100 net sections of Montney rights is now complete. The Company now intends to drill a large number of Montney horizontal wells utilizing the information obtained via the vertical evaluation program. Similar horizontals in the off-setting Dawson Creek - Swan areas by competitors have been very successful from both a production and reserve recovery standpoint. Duvernay estimates an upper Montney gas in place target of approximately 50 bcf per section and controls 100 net sections on the reservoir fairway.

The Company has been pursuing the deep Paleozoic gas plays beneath the Sunset-Groundbirch Mesozoic complex. The Groundbirch 2-10 well, which is currently sidetracking, has encountered significant gas pay and high pressure gas flows from the first three Paleozoic formations encountered. The well has 35.0 m of net gas pay in the Belloy, Kiskatinaw and Debolt formations from wireline logs, and has flared gas at surface at rates in excess of 10 mmcfpd. Full production tests of these zones with adequate flow periods will be required to quantify reserves and longer term productivity. Deeper targets, imaged on 3D seismic, in the Mississippian Banff and Devonian Wabamun have yet to be penetrated. Duvernay expects to complete drilling and production testing operations at 2-10 by year end. Duvernay plans to accelerate this deep exploration program in 2008 with both step-outs to the initial discovery and separate, large volume new pool wildcats.

Duvernay has discovered a new Cecil oil pool at Sunset-Groundbirch with the A10-24 horizontal well, drilled in September. The well tested clean oil at rates up to 500 bopd, and several follow-up locations exist. The oil is sour (associated gas 3-4% H2S) and can only be produced at restricted rates due to the current capability of the Duvernay facilities. The connection to the Duke system in early 2008 will allow for higher production rates and the drilling of identified step-outs.

ALBERTA DEEP BASIN

The Company has drilled a total of 46 successful new gas wells thus far in 2007. Application of the continuously improving multi-zone completion technology, coupled with subsequent production commingling, continues to yield very strong gas wells. Duvernay is averaging 7 completed gas zones per wellbore in the Deep Basin in 2007 compared to 5 zones in 2006.

Duvernay has completed the upgrading of the existing Sundance compressor site to a full sweet gas plant with production commencing on November 5th 2007. This allows significant shut-in gas volumes to come on-stream on an uninterrupted basis. Current gas rates at the plant outlet are 21 mmcfpd.

A similar compressor site upgrade to a full sweet gas plant is underway at Fir-Oldman which will allow 12.5 mmcfpd of currently shut-in production to come on-stream. This project will be completed by mid-February 2008; limited gas volumes may flow through third party facilities in the interim period.

Duvernay continues to expand the land and drilling inventory in the Deep Basin complex with approximately 110 sections of new lands added, primarily through farm-in deals, thus far in 2007. The Company is capitalizing on these new, previously unavailable opportunities in the Deep Basin during this period of low natural gas prices royalty uncertainty and general Industry activity slow down.

The majority of these new lands are on the southern and western portions of Duvernay's Deep Basin complex where the gas targets are at drilling depth, of 3,000 metres and greater. This depth of gas well is treated more favourably under the proposed 2009 revised provincial royalty framework.

EAST FLANK PEACE RIVER HIGH

The Company has been striving to expand the East Flank of the Peace River High area into a third significant core area for the company, with a strong oil focus. Considerable progress has been made in 2007, including the following;

1. A second Dawson Slave Point light oil discovery, which tested at rates of 175 bopd and came on production on October 26. This new pool has additional potential and compliments the multi-well Slave Point light oil pool discovered in 2006.

2. Heavy oil joint venture development in the Company's Dawson Cretaceous Bluesky oil asset with Petrobank Energy Resources Ltd. utilizing Petrobank's new THAI technology. Considerable reserve and production upside exists should the application of the new technology prove successful. Current mapped OIP on Duvernay lands is in excess of 100 mmboe.

3. New pool Devonian oil and Cretaceous gas discoveries in 2007 at Puskwa, with several additional new prospects defined.

4. New pool Cretaceous gas discovery at Gold Creek Alberta, and plans to test a deep Devonian light oil prospect in the immediate vicinity.

MANAGEMENT'S DISCUSSION AND ANALYSIS

Certain information set forth in this management's discussion and analysis 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.

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 the Corporation'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. Duvernay defines funds from operations as cash from 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 flow as defined by GAAP:



Three Months Ended Nine Months Ended
September 30 September 30
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(000s) 2007 2006 2007 2006
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Operating Cash Flow, per Cash flow
Statement $ 55,794 $ 32,940 $ 189,422 $ 121,894
Changes in non-cash working
capital (10,687) 12,847 (20,862) 6,060
Abandonment costs incurred - 294 - 380
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Funds from operations, as
disclosed $ 45,107 $ 46,081 $ 168,560 $ 128,334
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Operating netback is calculated on a $/BOE basis and is defined as revenue
less royalties, transportation costs and operating expenses, as shown below:

Three Months Ended Nine Months Ended
September 30 September 30
-----------------------------------------
($/BOE) 2007 2006 2007 2006
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Revenue, excluding unrealized
gains and losses on
financial instruments and
processing fee income $ 42.52 $ 44.91 $ 47.84 $ 47.70
Royalties (7.81) (5.88) (8.08) (8.30)
Transportation costs (1.24) (1.33) (1.34) (1.16)
Operating Expenses (5.96) (5.28) (5.79) (5.44)
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Operating Netback $ 27.51 $ 32.42 $ 32.63 $ 32.80
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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.

This management's discussion and analysis should be read in conjunction with Duvernay's unaudited interim financial statements for the nine months ended September 30, 2007 and audited financial statements and notes for the year ended December 31, 2006 and comparative information included therein.

This management's discussion and analysis is dated November 8, 2007.

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.

Quarter ending September 30, 2007 compared to the Quarter ending September 30, 2006

PRODUCTION

The Corporation's production for the three months ended September 30, 2007 averaged 20,045 boe/d compared with 16,046 boe/d for the same period in 2006, an increase of 25%. Average production fell slightly compared to the second quarter of 2007. The third quarter production shortfall was due primarily to the following reasons:

- Third party facility restrictions in Sundance dropping production by 750 boe/day compared to the second quarter of 2007

- Third party facility restrictions in Fir-Oldman resulted in 12.5 mmcf/day of new production being delayed

- A shut in of 200 boe/d of Duvernay's Seal Bluesky gas pool awaiting the decision from an AEUB hearing

- Weather related surface access issues reduced Dawson oil volumes by 150 boe/d

- Intermittent, unplanned production interruptions resulted in an additional 300 boe/d disruption during the third quarter

The Corporation did not participate in any significant property or corporate acquisitions or dispositions during the first nine months of the year. The Corporation's average production rate for the third quarter of 2007 of 20,045 boe/d was significantly below overall production capability.



Three Months Ended Nine Months Ended
September 30 September 30
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2007 2006 Change 2007 2006 Change
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Natural gas (mcf/d) 106,896 85,184 25% 109,252 80,585 36%
Crude oil and
liquids (bbls/d) 2,229 1,848 21% 2,402 1,558 54%
Oil equivalent
- boe 1,844,110 1,476,203 25% 5,626,604 4,092,006 38%
Oil equivalent -
boe/d 20,045 16,046 25% 20,610 14,989 38%
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Area (boe/d) Third Quarter Second Quarter Third Quarter
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2007 2007 2006
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Northeast B.C. 5,865 6,315 5,467
Deep Basin 13,667 13,995 9,464
Other Areas 513 602 1,115
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20,045 20,912 16,046
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New production during the second quarter was sourced from the Deep Basin where 20 new wells were tied-in along with 11 new Northeast B.C. wells also being tied in during the quarter. These production additions offset natural declines and shut ins experienced in the third quarter. For the nine months ending September 30, 2007 corporate production volumes increased by 38% over the comparable period in 2006. The primary driver for this growth is the development drilling in the Company's two large tight gas projects in the Alberta Deep Basin and Northeast B.C. Light oil volumes also improved substantially as the 2006 Dawson light oil discovery produced consistently throughout 2007. Deep Basin production for the quarter averaged 13,667 boe/d for an increase of 44% compared to the third quarter of 2006. Groundbirch/Sunset production increased to 5,865 boe/d, or 7%, from the same quarter in 2006.

REVENUE AND ROYALTIES

Revenue for the three months ended September 30, 2007 was $77.9 million representing a 13% increase over revenue of $69.0 million for the same period in 2006. For the first nine months of 2007 revenues grew by 33% primarily as a result of strong production growth. Revenue includes all petroleum and natural gas sales, processing fee income and has been adjusted for the effects of commodity hedging (realized gains and losses). Realized oil and liquids prices for the third quarter of 2007 averaged $71.76 per barrel compared with $73.07 (including realized hedging gains of $0.04 per barrel) per barrel for the same period in 2006 (including realized hedging losses of $0.03 per barrel). When comparing Duvernay's third quarter 2007 oil and liquids price to the third quarter 2006, realized prices decreased 2%. World oil price benchmarks increased by $4.55 U.S. in the third quarter of 2007 when compared to the same time period in 2006, or 6%.

Duvernay's realized corporate gas price for the third quarter of 2007 continued to outperform the AECO spot price ($6.23 - net of transportation and realized hedging gains/losses versus $5.21). AECO natural gas prices decreased by 9% in the third quarter of 2007 compared to the third quarter of 2006. Duvernay's realized natural gas price decreased by 6% when comparing these quarters. Transportation costs for the third quarter of 2007 were 3.0% of gross revenue or $1.24/boe, compared to 2.9% of gross revenue or $1.33/boe in the third quarter of 2006. Third party processing income of $1.6 million decreased compared to the second quarter of 2007 primarily due to a ramp up of Duvernay equity gas replacing third party gas in Company owned facilities. Approximately 21 mmcf/d of third party natural gas continues to be processed through the 120 mmcf/d Cecilia 15-4 gas plant.



DUVERNAY PRICES

Three Months Ended Nine Months Ended
September 30 September 30
------------------------------------------------------
2007 2006 Change 2007 2006 Change
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Natural gas ($/mcf) $ 6.23 $ 6.62 (6)% $ 7.28 $ 7.32 (1)%
Crude oil and liquids
($/bbl) 71.76 73.07 (2)% 65.09 69.15 (6)%
Oil equivalent
($/boe) $ 41.27 $ 43.58 (5)% $ 46.51 $ 46.54 (1)%
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BENCHMARK OIL & GAS PRICES

Three Months Ended
September 30
--------------------------
2007 2006 Change
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Natural Gas
NYMEX Henry Hub U.S. $ 6.24 $ 6.18 1%
AECO $ 5.21 $ 5.72 (9)%
Oil
NYMEX U.S. $ 75.15 $ 70.60 6%
Edmonton Par Cdn. $ 82.09 $ 80.25 2%
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RECONCILIATION OF AECO INDEX TO DUVERNAY'S REALIZED NATURAL GAS PRICES

Three Months Ended
September 30
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($/boe) 2007 2006
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AECO Index Price $ 5.21 $ 5.72
Transportation (0.16) (0.20)
Heat/Quality Differential 0.68 0.57
Hedge 0.50 0.53
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Duvernay realized natural gas price $ 6.23 $ 6.62
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CURRENCY - EXCHANGE RATES

Three Months Ended
September 30
---------------------------
2007 2006 Change
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Cdn/U.S. $ $ 0.9559 $ 0.8918 7%
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Revenue is analyzed as follows:

Three Months Ended Nine Months Ended
September 30 September 30
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Revenue 2007 2006 Change 2007 2006 Change
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Natural gas $ 60,871 $ 53,447 14% $ 216,875 $ 164,770 32%
Oil and liquids
revenue 15,429 12,840 20% 47,308 30,435 55%
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Total Revenue from
oil and gas sales $ 76,300 $ 66,287 15% $ 264,183 $ 195,205 35%
Processing and Other
Income 1,627 2,754 (41)% 4,685 4,825 1%
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Total Revenue $ 77,927 $ 69,041 13% $ 268,868 $ 200,030 34%
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Duvernay's royalties are summarized as follows:

Three Months Ended Nine Months Ended
September 30 September 30
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Royalties 2007 2006 Change 2007 2006 Change
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Natural gas $ 10,587 $ 6,995 51% $ 35,127 $ 28,019 25%
Oil and liquids 3,809 1,691 125% 10,354 5,942 74%
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Total royalties $ 14,396 $ 8,686 66% $ 45,481 $ 33,961 34%
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For the three months ended September 30, 2007, the average effective royalty rate was 19%, compared to 17% for the same period in 2006. Duvernay continued to benefit from the royalty relief programs put into place by the Ministry of Energy and Mines for British Columbia in May 2003, allowing explorers to access reduced royalty rates for low-productivity natural gas wells, royalty credits for deep gas wells and royalty credits for wells drilled in the summer months. For the first nine months of 2007 total royalties grew by 34% when compared to 2006. Royalties as a percent of total revenue stayed consistent with the same period in 2006.

OPERATING EXPENSES

Operating expenses include all periodic lease and field level expenses and include no income recoveries for processing third party volumes. Operating expenses of $5.96/boe for the third quarter of 2007 increased when compared to the third quarter 2006 operating expenses of $5.28/boe. This increase is due to continued inflationary pressures in many field services including labour costs, equipment rates and subsurface repair and maintenance combined with slightly weaker third quarter production volumes than had been forecast. Total operating expenses for the quarter were $11.0 million compared to $7.8 million in the third quarter of 2006. The Corporation's third quarter operating expenses include third party processing, gathering and compression fees of $2.4 million or 22% of total operating costs compared to $2.0 million or 25% of total operating costs for the third quarter of 2006.



GENERAL & ADMINISTRATIVE EXPENSES

General and administrative expenses ("G&A") are summarized on the table
below as follows:
Three Months Ended Nine Months Ended
September 30 September 30
---------------------------------------------------------
2007 2006 Change 2007 2006 Change
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G&A expenses $ 4,328 $ 3,496 24% $ 12,055 $ 9,918 22%
Administrative and
operating recovery (438) (456) (4)% (1,306) (1,157) 13%
Capital recovery (1,302) (1,717) (24)% (3,862) (4,919) (21)%
Capitalized G&A (900) (442) 104% (2,394) (1,260) 90%
Stock based
compensation 3,826 2,362 62% 11,310 7,001 62%
Capitalized stock
based compensation (1,652) (1,024) 61% (4,898) (3,036) 61%
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Total G&A $ 3,862 $ 2,219 74% $ 10,905 $ 6,547 67%
Oil equivalent
($/boe) $ 2.09 $ 1.50 39% $ 1.94 $ 1.60 21%
Oil equivalent
cash costs($/boe) $ 0.92 $ 0.60 53% $ 0.80 $ 0.63 27%
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Net G&A expenses for the three months ending September 30, 2007 increased to $3.9 million from $2.2 million for the same period in 2006. G&A for the third quarter of 2007 increased to $2.09/boe from $1.50/boe in 2006 due mainly to the increase in stock based compensation expense. Stock based compensation expense increased over the same period of 2006 as the impact of two stock option issues (one in November of 2006 and the other in June of 2007) are being recognized in income. When stock based compensation of $1.17/boe is removed, the Corporation's cash general and administrative costs increased to $0.92/boe from $0.60/boe for the same period in 2006. This increase in cash G&A is due to administrative growth necessitated by increased regulatory requirements as well as operational growth. The percentage of expenses capitalized as attributable to exploration activities was 35%, consistent with the third quarter of 2006. Cash G&A per BOE for the nine months ended September 30, 2007 increased by 27% to $0.80/boe as capital recoveries dropped as a result of lower capital spending year to date 2007 compared to 2006.

DEPLETION, DEPRECIATION AND ACCRETION

Depletion, depreciation and accretion expense ("DD&A") increased to $34.9 million during the third quarter of 2007 from $25.8 million during the same period in 2006. On a dollars per boe basis, DD&A increased to $18.78 from $17.78 in the third quarter of 2006. The percentage of the property, plant and equipment investment excluded from the Corporation's costs subject to depletion (4% in 2007; 7% in 2006) decreased when comparing the third quarter of 2007 with 2006. Depletion rates in 2007 increased primarily as a result of the growth in the Company's proved undeveloped reserves and the related larger future development costs being included in the depletable base. The third quarter of 2007 depletion rate of $18.78/boe has decreased from the $20.12/boe recorded in the second quarter of 2007 as recent independent reserve engineering estimates of proved reserves for certain properties have now been incorporated.

INCOME TAXES

The Corporation did not pay any cash income taxes in the third quarter of 2007. The Corporation does not expect to pay any cash income taxes in 2007 based on existing tax pools, planned capital expenditures and the most recent forecast of 2007 taxable income. Although current income tax horizons depend on product prices, production levels, and the nature, magnitude and timing of capital spending, the Corporation currently believes that no cash income tax will be payable for two to three years.

FUNDS FROM OPERATIONS AND EARNINGS

Funds from operations decreased to $45.1 million ($0.79 per diluted equity share) for the three months ending September 30 from $46.1 million ($0.85 per diluted equity share) for the comparable period in 2006. On a per share basis, funds from operations decreased by 7% due to weaker gas prices. After tax earnings decreased by 71% for the third quarter of 2007 when compared to the same period in 2006 to $3.5 million from $12.3 million. The lower after tax net income realized in the third quarter of 2007 is due to a combination of weaker natural gas prices, slightly higher operating expenses, higher general and administrative expenses, and higher interest costs. On a per share basis, diluted earnings decreased to $0.06 from $0.23, a 74% decrease. On a pre-tax basis, third quarter 2007 earnings of $5.9 million were down from the same quarter in 2006 ($18.9 million), for the reasons stated above.



Three Months Ended Nine Months Ended
-------------------------------------------------
2007 2006 Change 2007 2006 Change
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Funds from operations per
equity share (1) $ 0.79 $ 0.85 (7)% $ 2.99 $ 2.39 25%
Earnings per equity share
(1) $ 0.06 $ 0.23 (74)% $ 0.58 $ 0.86 (33)%
Operating netback per boe $ 27.51 $ 32.42 (15)% $ 32.63 $ 32.80 (1)%
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note: (1) diluted


LIQUIDITY AND CAPITAL RESOURCES

The Corporation invested $124.6 million in the third quarter of 2007
compared to $153.9 million in the third quarter of 2006, as set out in the
following table.

Three Months Ended
-----------------------------------------------
($ thousands) September 2007 September 2006 June 2007
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Land and seismic $ 2,677 $ 10,252 $ 1,999
Drilling and completions 102,757 127,490 55,926
Facilities 17,494 25,496 24,819
Property
Acquisition/(Disposition) 755 (9,960) 348
Other 946 587 882
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Cash investments in Capital
Resources 124,629 153,865 83,974
Non-Cash additions to PP&E 2,353 1,120 2,111
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Total $ 126,982 $ 154,985 $ 86,085
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The Corporation drilled 26 gross wells (20.85 net) of which 16 are Deep Basin, 7 are Sunset/Groundbirch and 3 are in other areas. 19 gross wells were completed during the third quarter, 30 wells were tied in and significant facilities expenditures were made at Sundance.

For the nine months ending September 30, 2007 Duvernay invested $346.1 million, down by 14% from the same period in 2006, reflecting a longer 2007 spring break up which modestly reduced activity levels, as well as lower land and facility expenditures.

Duvernay has participated in the following equity financings in the year to date, 2007:



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


On October 4, 2007 Duvernay completed a private placement equity financing issuing 1,000,000 common shares on a flow-through basis at an issue price of $43.10 per share for gross proceeds of $43.1 million. The proceeds of the financing are dedicated to previously planned exploration and development drilling projects. At September 30, 2007 the Corporation's net debt was $488 million, which is in excess of borrowing capacity of $465 million. The October 4 financing remedies this shortfall.

The Company also entered into a new syndicated bank facility with a group of Canadian banks during the first quarter. The new facility has borrowing capacity of $440 million, up from $375 million. In addition the Corporation has a $25 million operating line. The current facility has been established on terms similar to those previously in place, and has a renewal date of May 2008.

At September 30, 2007 the Corporation estimates that it has fully spent the $48.125 million of the October 2006 flow-through offering and has a $4.0 million remaining of the obligation for the February 2007 flow-through offering, which must be completed by December 31, 2008.

As at September 30, 2007, the Corporation had 57,445,274 shares outstanding and 5,496,318 stock options outstanding. As at November 8, 2007, the Corporation has 58,981,774 shares outstanding and 5,559,818 stock options outstanding. During the period from September 30, 2007 until November 8, 2007, 36,500 common shares were issued on the conversion of employee stock options, and 100,000 new stock options were issued.

COMMODITY PRICE RISK MANAGEMENT/DERIVATIVE CONTRACTS

The Corporation enters into commodity-based derivative financial instruments such as forwards, futures, swaps, and costless collars to serve two primary business objectives. The first objective is to reduce the variability in cash flows from fluctuations in product prices to ensure a source of funding for the 2007 and 2008 capital program. The second objective is to fix the rate of return on capital invested in the gas prone resource projects. The Board of Directors has approved a policy permitting management to hedge up to a fixed percentage of budgeted corporate annual production. See below for a discussion of changes to the accounting for Financial Instruments effective January 1, 2007, and the related impact on the opening balance sheet for the nine months ended September 30, 2007. Gains or losses resulting from changes in the fair value of derivative contracts are recognized in earnings and cash flows when those changes occur. None of the Corporations derivative commodity contracts qualify for hedge accounting.

Duvernay enters into most hedging transactions with the same party that the commodity is physically sold to, avoiding the need to provide credit in the event that the hedges are at prices below prevailing prices. The most significant risk with the commodity hedges is that the prevailing product prices are higher than those committed to in the hedging contract. The Corporation partially mitigates this risk by including collars in its hedging portfolio. A less significant risk relates to the Corporation's ability to supply the production at future dates. This risk is managed by entering into the hedging contracts at multiple delivery points.

At September 30, 2007 Duvernay has calculated the market value of those contracts that were unsettled at September 30 and has estimated net gain from settling these instruments to be approximately $4.6 million. Financial Statement note 1 "Significant Accounting Policies" and note 5 "Financial Instruments" provide further details.

COMMITMENTS AND CONTRACTUAL OBLIGATIONS

During the second quarter of 2007 Duvernay made a commitment to process 10 mmcf/d of natural gas through third party facilities commencing in 2008 for 3 years, at competitive terms.

Other than as described above and with respect to flow-through share obligations and long-term debt commitments, there have been no other significant changes in the Company's commitments or contractual obligations from those disclosed in the December 31, 2006 Annual Management's Discussion and Analysis.

CHANGES IN DISCLOSURE CONTROLS AND PROCEDURES/INTERNAL CONTROLS OVER FINANCIAL REPORTING

There have been no material changes in the Company's disclosure controls and procedures, nor were there changes in the internal controls over financial reporting during the quarter ending September 30, 2007 from the previously reported period.

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.

CHANGES IN ACCOUNTING POLICIES

FINANCIAL INSTRUMENTS/OTHER COMPREHENSIVEINCOME/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(b) 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.

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.



SELECT QUARTERLY INFORMATION

2007
----------------------------------
Q3 Q2 Q1
----------------------------------------------------------------------------
PRODUCTION
Crude oil and liquids (bbls) 205,034 247,865 202,719
Gas (mcf) 9,834,454 9,930,573 10,060,881
Oil equivalent (boe) 1,844,110 1,902,961 1,879,533
Crude oil and liquids (bbls/d) 2,229 2,724 2,252
Gas (mcf/d) 106,896 109,127 111,788
Oil equivalent (boe/d) 20,045 20,912 20,884
----------------------------------------------------------------------------
FINANCIAL
($ thousands, unless noted)
Revenue, net of royalties 63,531 84,880 74,976
Funds from operations 45,107 59,757 63,696
Per share basic 0.79 1.06 1.16
Net earnings 3,529 18,643 10,688
Per share basic 0.06 0.33 0.19
Per share diluted 0.06 0.33 0.19
Total assets 1,506,322 1,408,797 1,376,671
Bank debt 399,452 399,452 374,585
Cash and working capital (deficiency) (88,556) (7,213) (72,948)
Basic outstanding Shares 57,445 57,357 55,608
----------------------------------------------------------------------------
PER UNIT
Gas, net of transportation ($/mcf) 6.23 7.54 8.05
Crude oil and liquids, net of
transportation ($/bbl) 71.76 62.11 62.00
Revenue, net of transportation ($/boe) 41.27 47.46 50.68(1)
Operating netback ($/boe) 27.51 34.30 35.97(1)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

2006 2005
--------------------------------------------------------
Q4 Q3 Q2 Q1 Q4
----------------------------------------------------------------------------
PRODUCTION
Crude oil and
liquids (bbls) 196,225 170,051 111,557 143,926 262,755
Gas (mcf) 8,885,624 7,836,912 7,823,061 6,339,802 5,931,351
Oil equivalent
(boe) 1,677,162 1,476,203 1,415,401 1,200,560 1,251,314
Crude oil and
liquids (bbls/d) 2,133 1,848 1,226 1,599 2,856
Gas (mcf/d) 96,583 85,184 85,968 70,442 64,471
Oil equivalent
(boe/d) 18,230 16,046 15,554 13,340 13,601
----------------------------------------------------------------------------
FINANCIAL
($ thousands, unless
noted)
Revenue, net of
royalties 72,472 60,355 52,183 53,531 65,472
Funds from
operations 55,845 46,081 39,009 43,244 53,828
Per share basic 1.05 0.88 0.75 0.86 1.10
Net earnings 12,242 12,309 21,677 12,133 18,287
Per share basic 0.23 0.24 0.42 0.24 0.37
Per share diluted 0.23 0.23 0.40 0.23 0.35
Total assets 1,272,571 1,173,784 1,022,445 971,616 827,263
Bank debt 324,590 296,703 271,692 221,760 175,481
Cash and working
capital
(deficiency) (93,537) (87,959) (6,154) (53,148) (40,180)
Basic outstanding
Shares 53,962 52,605 52,307 51,205 49,345
----------------------------------------------------------------------------
PER UNIT
Gas, net of
transportation
($/mcf) 7.25 6.62 6.55 9.12 10.72
Crude oil and
liquids, net of
transportation
($/bbl) 56.17 73.07 75.49 59.61 59.86
Revenue, net of
transportation
($/boe) 45.00 43.58 42.18 55.31 63.40
Operating netback
($/boe) 34.92 32.42 29.28 37.42 44.90
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Duvernay's quarterly growth in production volumes, gross revenue and per
share funds from operations is primarily attributed to an active and
successful exploration and development drilling program. Third quarter 2007
growth in revenue and volumes was muted by facility restrictions, shut-ins
and decreases in market prices.

(1) restated to include realized hedging gains


BALANCE SHEET

September 30, September 30,
(Unaudited)(Thousands of dollars) 2007 2006
----------------------------------------------------------------------------
ASSETS (restated)
Current assets:
Accounts receivable $ 50,022 $ 62,446
Prepaid expenses and deposits 1,464 1,230
Fair value of financial instruments (note 5) 4,714 -
----------------------------------------------------------------------------
56,200 63,676
Investment 15,000 15,000
Property, plant and equipment (note 2) 1,435,122 1,193,895
----------------------------------------------------------------------------
$ 1,506,322 $ 1,272,571
----------------------------------------------------------------------------

LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued liabilities $ 144,635 $ 157,213
Fair value of financial instruments (note 5) 121 -
----------------------------------------------------------------------------
144,756 157,213

Long-term debt (note 3) 399,452 324,590
Asset retirement obligations 14,296 11,686
Future income taxes 141,390 95,799

Shareholders' equity:
Share capital (note 4) 608,176 531,651
Contributed surplus (note 4) 19,607 12,323
Retained earnings, restated (note 1) 178,645 139,309
----------------------------------------------------------------------------
806,428 683,283
----------------------------------------------------------------------------
Subsequent Event (Note 6)
$ 1,506,322 $ 1,272,571
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying notes to interim financial statements


INTERIM STATEMENTS OF EARNINGS, COMPREHENSIVE INCOME AND RETAINED

Three Months Ended Nine Months Ended
September 30 September 30
-------------------------------------------
(Unaudited)(Thousands of dollars
except per share amounts) 2007 2006 2007 2006
----------------------------------------------------------------------------
Revenue:
Petroleum and natural gas sales $ 69,351 66,287 $ 251,566 195,205
Realized gain on financial
instruments 9,052 - 17,624 -
Unrealized gain (loss) on
financial instruments
(note 5) (2,103) - (5,007) -
----------------------------------------------------------------------------
76,300 66,287 264,183 195,205
Royalties (14,396) (8,686) (45,481) (33,961)
Processing and other income 1,627 2,754 4,685 4,825
----------------------------------------------------------------------------
63,531 60,355 223,387 166,069
Expenses:
Operating 10,994 7,794 32,598 22,244
Transportation 2,288 1,951 7,506 4,773
General and administrative 1,688 881 4,493 2,582
Stock-based compensation 2,174 1,338 6,412 3,965
Interest 5,557 3,648 15,237 8,136
Depletion, depreciation and
accretion 34,892 25,801 112,349 74,078
----------------------------------------------------------------------------
57,593 41,413 178,595 115,778
----------------------------------------------------------------------------
Earnings before taxes 5,938 18,942 44,792 50,291
Taxes:
Future 2,409 6,633 11,932 4,171
----------------------------------------------------------------------------
2,409 6,633 11,932 4,171
----------------------------------------------------------------------------
Net earnings and comprehensive
income 3,529 12,309 32,860 46,120
Retained earnings, beginning of
period 175,116 114,758 139,309 80,947
Change in accounting policy
(Note 1) - - 6,476 -
----------------------------------------------------------------------------
Retained earnings, end of period $ 178,645 127,067 $ 178,645 127,067
----------------------------------------------------------------------------
Net earnings per share:
(Note 4g)
Basic $ 0.06 0.24 $ 0.59 0.89
Diluted 0.06 0.23 0.58 0.86
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying notes to interim financial statements.


INTERIM STATEMENTS OF CASH FLOWS

Three Months Ended Nine Months Ended
September 30 September 30
-------------------------------------------
(Unaudited)(Thousands of dollars) 2007 2006 2007 2006
----------------------------------------------------------------------------
Cash provided by (used in):
Operations:
Net earnings $ 3,529 12,309 $ 32,860 46,120
Items not involving cash:
Depletion, depreciation, and
accretion 34,892 25,801 112,349 74,078
Stock-based compensation 2,174 1,338 6,412 3,965
Future income taxes 2,409 6,633 11,932 4,171
Unrealized loss (gain) on
financial instruments 2,103 - 5,007 -
Abandonment expenditures - (294) - (380)
Change in non-cash operating
working capital 10,687 (12,847) 20,862 (6,060)
----------------------------------------------------------------------------
55,794 32,940 189,422 121,894
Financing:
Issue of common shares, net of
issue costs 282 1,263 103,034 111,396
Increase in long-term debt - 25,010 74,862 121,221
----------------------------------------------------------------------------
282 26,273 177,896 232,617
Investments:
Additions to property, plant,
and equipment (123,886) (163,825) (344,301) (435,352)
Property
(acquisitions)/dispositions (743) 9,960 (1,767) 27,002
Change in non-cash working
capital 68,553 84, 520 (21,250) 43,707
----------------------------------------------------------------------------
(56,076) (69,345) (367,318) (364,643)
Increase (Decrease) in cash - (10,132) - (10,132)
Cash, beginning of period - - - -
----------------------------------------------------------------------------
Cash, end of period - (10,132) - (10,132)
----------------------------------------------------------------------------
Cash tax $ - - $ - 1,279
Cash interest $ 6,548 3,842 $ 16,515 9,645
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying notes to interim financial statements.


Information as at September 30 and for the three months ended is unaudited

(Tabular Amounts in Thousands of Dollars)

1. SIGNIFICANT ACCOUNTING POLICIES:

The financial statements of the Corporation have been prepared by management in accordance with Canadian generally accepted accounting principles for Interim Financial Statements. These interim financial statements follow the same accounting policies and methods as the financial statements for the year ended December 31, 2006, except as noted below, and include all adjustments necessary to present fairly the results for the interim period. Certain information and footnote disclosure normally included in the annual financial statements has been omitted. These interim financial statements should be read in conjunction with the financial statements and notes for the year ended December 31, 2006.

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


(A) 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-speculative, 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.

(B) DERIVATIVES

The Company continues to utilize financial 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 to the Company's 2006 annual financial statements 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.

(C) 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 material embedded derivatives which required separate recognition and measurement.

(D) 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 recognized over the life of the resulting financial instrument. 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.

2. PROPERTY, PLANT & EQUIPMENT:

The cost of unproven lands and seismic costs at September 30, 2007 of $70.2 million (December 31, 2006 - $87.2 million) has been excluded from the depletion calculation.

General and administrative expenditures of $7.3 million (2006 - $2.2 million) have been capitalized and included as costs of petroleum and natural gas properties. Included in this amount is the year to date non-cash related stock-based compensation of $4.9 million, which includes the associated future tax liability of $1.4 million.

3. LONG-TERM DEBT:

The Corporation has a syndicated financing arrangement with a group of Canadian Chartered banks for an extendible revolving loan in the amount of $440 million in addition to a $25 million operating line. The terms of this agreement are unchanged from the previous credit agreement. The facility has a renewal date of May 2008. As at September 30, 2007, $400 million of this term loan was drawn.

4. 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, 2006 53,961,607 $ 531,651
For cash on private placement of
flow-through shares 1,000,000 41,500
For cash on public share issue 1,500,000 60,525
For cash on exercise of stock options 983,667 6,042
Contributed surplus on exercise of stock options 2,580
Share issue costs (5,033)
Tax effect on share issue costs 1,551
Tax effect on flow-through renunciation (30,640)
---------------------------------------------------------------------------
Balance, September 30, 2007 57,445,274 $ 608,176
---------------------------------------------------------------------------
---------------------------------------------------------------------------


(C) FLOW-THROUGH SHARES:

At September 30, 2007 the Corporation estimates that it has fully spent the $48.1 million of the October 2006 flow-through offering and has a $4.0 million remaining of the obligation for the February 2007 flow-through offering, which must be completed by December 31, 2008.



(D) CONTRIBUTED SURPLUS:

---------------------------------------------------------------------------
Contributed surplus, December 31, 2006 $ 12,323
Stock-based compensation 9,864
Exercise of stock options (2,580)
---------------------------------------------------------------------------
Contributed surplus, September 30, 2007 $ 19,607
---------------------------------------------------------------------------
---------------------------------------------------------------------------


(E) STOCK OPTIONS:

The Corporation has a stock option plan. Under the employee stock option plan, the Corporation 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 Corporation's stock on the date of grant and an option's maximum term is five years. Options are granted throughout the year and vest 1/3 on each of the first, second and third anniversaries from the date of grant.

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



Weighted
average
Number of exercise
Options price
---------------------------------------------------------------------------
Stock options outstanding, beginning of period 5,119,985 $ 23.51
Granted 1,400,000 37.54
Exercised (983,667) 6.14
Forfeited (40,000) 30.59
---------------------------------------------------------------------------
Stock options outstanding, end of period 5,496,318 $ 30.14
---------------------------------------------------------------------------
---------------------------------------------------------------------------


(F) STOCK-BASED COMPENSATION:

The weighted average fair value of the stock options granted during the period was $11.89 (2006 - $11.07) per option and is estimated on the date of grant using the Black-Scholes option-pricing model with weighted average assumptions for grants as follows:



Three Months Ended September 30
---------------------------------------------------------------------------
2007 2006
---------------------------------------------------------------------------
Risk-free interest rate (%) 4.5 4.5
Expected life (in years) 3.5 3.5
Expected volatility (%) 35 30
Expected forfeitures (%) 10 10
---------------------------------------------------------------------------
---------------------------------------------------------------------------


(G) PER SHARE AMOUNTS:

Per share amounts have been calculated on the weighted average number of shares outstanding. The weighted average shares outstanding for the quarter ended September 30, 2007 was 57,394,095 (56,126,867 nine months).

In computing diluted earnings per share for the quarter ended September 30, 2007, 28,869 (175,816 nine months) shares were added to the weighted average number of common shares outstanding for the dilution from the stock options. For the three and nine months ended September 2007 there were 2,528,500 options excluded from the diluted earnings per share calculation on the basis that they were anti-dilutive.

5. FINANCIAL INSTRUMENTS:

Changes in the fair value of all outstanding non-financial commodity contracts are reflected on the balance sheet with a corresponding unrealized gain or loss in income.

The following table reconciles the changes in the fair value of financial instruments outstanding on September 30, 2007:



Fair value of Financial Instruments September 30, 2007
---------------------------------------------------------------------------
Balance, January 1, 2007 $ 9,600
Unrealized loss on financial instruments (5,007)
---------------------------------------------------------------------------
Fair value of financial instrument asset, September 30, 2007 4,714
Fair value of financial instrument liability, September 30, 2007 (121)
---------------------------------------------------------------------------


As at September 30, 2007, the Corporation had fixed the price applicable to future production as follows:


Fair
Volume Remaining Term Pricing Value
---------------------------------------------------------------------------
AECO Fixed October -
Price 3,000 gj's/day December 2007 $7.76 Cdn/gj $ 589

AECO Fixed
Price 5,000 gj's/day October 2007 $7.30 Cdn/gj 367

AECO Fixed November -
Price 5,000 gj's/day December 2007 $7.04 Cdn/gj 331

AECO Fixed
Price 3,000 gj's/day December 2007 $7.47 Cdn/gj 103

AECO Fixed
Price 3,000 gj's/day October 2007 $6.01 Cdn/gj 97

AECO Fixed November 2007 -
Price 3,000 gj's/day March 2008 $6.61 Cdn/gj 163

AECO Fixed November 2007 -
Price 3,000 gj's/day March 2008 $6.66 Cdn/gj 186

AECO Fixed November 2007 -
Price 5,000 gj's/day March 2008 $6.63 Cdn/gj 260

AECO Fixed November 2007 -
Price 3,000 gj's/day March 2008 $6.51 Cdn/gj 117

AECO Fixed November 2007 -
Price 3,000 gj's/day March 2008 $6.50 Cdn/gj 113

W.T.I. Fixed October -
Price Swap 200 bbls/day December 2007 $71.75 U.S/bbl (107)

W.T.I. Fixed October -
Price Swap 100 bbls/day December 2007 $76.53 U.S/bbl (10)

AECO Index $7.00 Cdn/gj
Costless floor / $8.57
Collar 10,000 gj's/day October 2007 Cdn/gj ceiling 631

AECO Index $6.02 Cdn/gj
Costless floor / $7.05
Collar 6,000 gj's/day October 2007 Cdn/gj ceiling 466

AECO Index $6.25 Cdn/gj
Costless floor / $7.37
Collar 4,000 gj's/day October 2007 Cdn/gj ceiling 429

AECO Index $7.00 Cdn/gj
Costless floor / $7.80
Collar 5,000 gj's/day October 2007 Cdn/gj ceiling 316

AECO Index $7.00 Cdn/gj
Costless floor / $8.91
Collar 5,000 gj's/day October 2007 Cdn/gj ceiling 316

AECO Index $7.65 Cdn/gj
Costless floor / $8.17
Collar 3,000 gj's/day October 2007 Cdn/gj ceiling 229

AECO/Nymex
Differential Nymex less
swap 5,000 MMbtu/day October 2007 $0.83/mmbtu (3)
---------------------------------------------------------------------------
$4,593
---------------------------------------------------------------------------
---------------------------------------------------------------------------


6. SUBSEQUENT EVENTS:

On October 4, 2007 Duvernay completed an equity financing issuing 1,000,000 common shares on a flow-through basis at an issue price of $43.10 per share for gross proceeds of $43.1 million.




ABBREVIATIONS

AEUB Alberta Energy Utilities Board
ARTC Alberta Royalty Tax Credit
Bbls barrels
bcf billion cubic feet of gas
boe barrel of oil equivalent using 6 mcf/boe for gas and 1 bbl/boe
for crude oil and liquids
bbls/d barrels per day
boe/d barrels of oil equivalent per day
EP Exploration and Production
gj gigajoule
mbbl thousand barrels
mboe thousand boe
mcf thousand cubic feet
mmbbl million barrels
mmboe million boe
mmcf million cubic feet
mmcf/d million cubic feet per day
mstb thousand stock tank barrels
ngl's natural gas liquids
NPW new pool wildcat
TSX Toronto Stock Exchange


NOTICES:

CONFERENCE CALL

On Friday, November 9, 2007 Duvernay will hold a conference call at 10:00 AM Mountain Standard Time (12:00 Eastern) discussing Duvernay's third quarter financial and operating results. To access this conference please call 416.644.3424 in Toronto or 866.249.2165 toll free. The conference number is 21250310#.

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