Duvernay Oil Corp.
TSX : DDV

Duvernay Oil Corp.

November 09, 2006 07:00 ET

Duvernay Oil Corp.: Profitable Growth Continues; On Track to Achieve Exit Volume of 23,000 boe/d

CALGARY, ALBERTA--(CCNMatthews - Nov. 9, 2006) - Duvernay Oil Corporation (TSX:DDV)

THIRD QUARTER HIGHLIGHTS

- 20,000 boe/d attained in the fourth quarter.

- Continued production growth highlighted by cash flows exceeding market consensus of $46.1 million.

- Strong cost control measures result in a unit operating net back of $32.42/boe.

- Industry leading unit operating costs of $5.28/boe and unit cash general and administrative costs of $.60/boe.

- Strong reserve additions lead to a substantial increase in bank credit facility from $325 to $400 mm in spite of gas price weakness.

- Fourth quarter non core asset sales further strengthen the Company's financial position by raising $70 million in cash without significantly impacting 2006 or 2007 production levels.

- October 2006 flow through share equity financing of 1,100,000 shares, raises $48 million to fund expanded exploration leads.

- A new sweet gas condensate discovery in the lower Doig at South Groundbirch.

PRODUCTION OUTLOOK

Third quarter 2006 production was 16,046 boe/d a 57% increase over third quarter 2005 production of 10,212 boe/d. Third quarter production growth over second quarter 2006 production was 3%, slightly below the Company's quarter over quarter growth range target of between 5 and 20%. Delays in re-establishing shut-in production at Bigstone and Sundance Alberta until late September and early October respectively were the primary reasons for the slightly reduced third quarter growth.

Current production levels are in excess of 20,000 boe/d hence fourth quarter 2006 over third quarter growth rate will meet or exceed the top end growth range of 20%. Due primarily to the aforementioned shut-ins during Q2 and Q3, the Company now expects full year 2006 average production levels between 16,500 and 17,000 boe/d.

Duvernay remains on track to achieve its previously disclosed production exit of 23,000 boe/d. The Company has over 7,000 boe/d of behind pipe volumes in completed well bores awaiting tie-in over the next three to four months.

Duvernay is estimating an average 2007 production range of between 26,000 and 29,000 boe/d for the $325.0 and $400.0 million capital budget cases respectively. The Company expects quarter over quarter growth ranges during 2007 to be similar in magnitude and timing to 2006. The 2007 average estimates include a larger provision for unpredicted production down-time and shut-ins.

Duvernay reached the 20,000 boe/d level in exactly five years, the Company has the drilling inventory and basic infrastructure in its two core operated areas to add an additional 20,000 boe/d in a significantly shorter time frame. This potential doubling of current production levels would require less than half of the existing development drilling inventory. The exact pace of these additions will be controlled primarily by the natural gas price.

FINANCIAL OUTLOOK

The Company has undertaken a series of initiatives to ensure a strong balance sheet during this period of volatile, relatively low gas prices. Several incremental opportunities have developed within Duvernay's two major core areas during this weaker gas price environment, the company has ensured that it has the financial flexibility to pursue these opportunities. These financial initiatives include;

1. The $48.125 million flow through financing which closed on October 12.

2. The Company has successfully increased the operating line of credit to $400 million from $325 million, based on substantial reserve growth and value creation during the first half of 2006. This pace of reserve growth has continued in the second half of 2006 as well.

3. Continued sale of non-core assets outside the two main core areas generated by the ongoing exploration program. During the third quarter the Company disposed of a non-core Peace River High asset, producing approximately 100 boe/d net for proceeds of $10.0 million. Duvernay has entered into an agreement to sell non-core select assets on the Peace River High for cash proceeds of $70.0 million. This transaction is expected to close in mid-December.

4. A modest reduction in drilling activity levels from 12 to 9 rigs and completion activity levels from 13 to 10 rigs. The Company expects to run an eight to nine rig program through the balance of 2006 and throughout 2007. This level of activity will lead to quarterly EP capital spending levels of $80.00 - 90.00 million. An increase of the natural gas price in 2007 above current levels will lead to an associated increase in drilling and rig activity levels.

5. An active realized gas price protection program primarily in the fourth quarter of 2006. The Company has 80.0 million cubic feet per day sold at an average price of $7.60/mcf in November and 60.0 million cubic feet per day sold at an average price of $8.40/mcf in December. Duvernay has 23 million cubic feet per day sold forward in the January-March period at a price of $9.40/mcf.

With the completion of these initiatives, the Company expects that the 2006 exit net debt to annualized fourth quarter 2006 cash flow ratio will be approximately 1.3 and the 2006 exit net debt to anticipated 2007 cash flow ratio will be approximately 1.1 times. Duvernay is currently forecasting cash flow of $312 million ($5.73/share) for the base case 2007 $325 million capital budget and cash flow of $391 million ($7.17/share) for the $400 million capital budget case.

OPERATING COSTS AND PERFORMANCE

Third quarter operating costs were $ 5.28/boe, an 8% reduction from second quarter 2006 operating costs. With the 20,000 boe/d milestone attained early in the fourth quarter, the Company expects fourth quarter operating costs to average below $5.00/boe, the Company's 2006 operating cost performance target. Third quarter operating netback was $ 32.42/boe, amongst the best in industry. G and A per boe was $ 0.60/boe, ahead of the Company's 2006 target of $ 0.65/boe.

The assets disposed by the Company in 2006 are of higher operating cost than those in the two principal producing complexes, Sunset-Groundbirch and the Alberta Deep Basin. This should result in continually improving cost performance in subsequent quarters.

SUNSET-GROUNDBIRCH COMPLEX

Duvernay continues to operate three drilling and three service rigs in the Sunset-Groundbirch complex of British Columbia. Very strong performance and EP program results continue from the area. The four Company-owned and operated gas plants are at capacity leading to overall net production levels of approximately 40.0 mmcf/d. Duvernay has approximately 20.0 mmcf/d of tested production capacity awaiting tie-in during the next several months. The original Triassic Doig pool now contains 67 drilled and tested wells, all of which will be connected to Duvernay's gathering and sales system. Duvernay is planning three projects that will significantly increase overall complex production levels during the next 12 months. These include; a modification to the Sunset 5-3 gas plant that is expected to yield 7.0 - 10.0 mmcf/d of additional processing capacity, a twinning of the existing Brassey gas plant is expected to add an additional 10.0 mmcf/d of capacity and participation in a proposed gathering line to the McMahon gas plant yielding an expected 10.0 - 20.0 mmcf/d of additional take away capacity for the Company.

The Exploration program for new Doig pools continued during the third quarter with successful step-outs drilled into the new pools at East Sunset and Sundown. In addition a fourth new Doig pool has been discovered at South Groundbirch, penetrated by two wells thus far. It is a sweet gas condensate discovery, seismically mappable, with several potential follow-up wells. Duvernay also has several separate geophysically defined targets along this new trend.

The Company has also closed the acquisition of the Imperial Oil assets in the Greater Sunset Groundbirch complex in October. These assets, producing approximately 500 boe/d, include the joint interests in the producing Sunset and Groundbirch oil units, joint interests in a portion of the original Groundbirch Doig pool, joint interests in one of the new Doig pools recently discovered, and undeveloped interests at West Groundbirch. The Company has plans for numerous oil unit optimization projects at Sunset, uphole recompletions at Sunset, infill gas wells at Groundbirch and development of the West Groundbirch property. Duvernay now has a 100% working interest in virtually the entire Sunset-Groundbirch-Brassey complex.

ALBERTA DEEP BASIN COMPLEX

The large Alberta Deep Basin program is continuing with five operated and one outside operated drilling rig along with seven service rigs currently active. Net production from the Deep Basin is expected to reach 16,000 boe/d by year-end.

Production disruptions at Bigstone and Sundance reduced third quarter average volumes in the Deep Basin by approximately 1,250 boe/d, these shut-ins were alleviated in late September and early October respectively. Significant, additional Deep Basin production additions are expected from Obed, Oldman and Wild River-Wroe Creek prior to year-end as the Company completed significant ongoing tie-in and facility programs. Duvernay currently has 19 wells drilled and/or completed, awaiting tie-in.

Continued utilization of multi-zone, co-mingled completion technologies in the Alberta Deep Basin is yielding wells with significantly increased initial and stabilized gas production rates. Initial downspacing (second well per section) and utilization of 3D seismic is also contributing to the steadily improving well results. The Wild River 1-26 well tested at commingled rates of 7.0 mmcf/d, the Obed 12-22 well tested at commingled rates of 5.6 mmcf/d and the Wild River 5-30 well tested at rates of 6.5 mmcf/d. Duvernay has in excess of 1,100 remaining development locations in its current Alberta Deep Basin inventory and over 375 sections of land.

EXPLORATION PROGRAM

The Exploration new pool wildcat program will follow four main thrusts during the balance of 2006 and throughout 2007. Each of these four exploration programs has the potential, if successful, to increase the estimated 2006 reserve base of the Company by 50% or more.

1. Dawson-Puskwa: The Company plans two additional delineation wells into the Slave Point light oil pool discovered at Dawson in 2006. A further three wells are planned during the winter when all areas on the prospect are accessible. The two initial wells into the pool produce at steady rates of 250 bbls/d production is interrupted occasionally during wet periods that restrict access.

At Puskwa, the Company is currently drilling a Precambrian test at 8-6-72-1W6 and plans at least one additional well prior to year end.

2. Alberta Deep Basin Devonian: Duvernay continues to seek a license for the large volume Devonian sour gas prospect at Edson with a late Q1 2007 target and spud date.

The Company plans to test at least two other Devonian prospects on its Deep Basin holdings during 2007.

3. Sunset-Groundbirch Paleozoic: A large 3D seismic survey is planned for first quarter 2007 with the initial deep test well scheduled to spud late in the second quarter of 2007.

4. NEBC Triassic Exploration Program: As mentioned earlier, the Company now has four new pool Doig discoveries in NEBC to complement the original Groundbirch discovery. Duvernay also has four new pool discoveries in other Triassic formations during 2006 that will be further delineated in 2007.

EXSHAW OIL

A new Alberta based private company, Exshaw Oil Corp., has been created and will acquire Duvernay's Alberta Peace River High assets. These assets are currently producing approximately 700 boe/d and are expected to grow beyond the 1,000 boe/d production level early in 2007. They include Duvernay's interests in Spirit River, Elmworth, Pouce Coupe, Sexsmith and Worsley. There is considerable development upside in the property inventory, particularly at Spirit River. Duvernay will receive $70.0 million in cash and 5.0 million shares of Exshaw Oil Corp.

Exshaw management will include Joanna Wright, formerly VP Land at Anadarko Canada, Brian Dewer, formerly VP Finance at Anadarko Canada and Kevin Keenan, former COO at Berkley Petroleum and at Duvernay during the Company's private phase. Mr. Keenan is currently a director of Duvernay Oil Corp. Mike Rose, President and CEO of Duvernay will be on the Board of Exshaw Oil. Exshaw is planning a $102.0 million private financing at $3.00 per share with the financing marketed by Peters & Co. Limited of Calgary. Duvernay management, staff and Board will not participate in any founder's shares, stock options or performance warrants of Exshaw Oil Corp. It is expected that Duvernay management, staff and Board will participate in the planned $3.00 per share financing.

MANAGEMENT'S DISCUSSION AND ANALYSIS

NINE MONTHS ENDING SEPTEMBER 30, 2006. ALL DOLLAR AMOUNTS ARE IN THOUSANDS OF CANADIAN DOLLARS, UNLESS OTHERWISE STATED.

Certain information set forth in this management discussion and analysis contains forward-looking statements. By their nature, 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.

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. For these purposes, Duvernay defines funds from operations as cash provided by operations before changes in non-cash operating working capital and abandonment costs incurred. Operating netback is defined as revenue less royalties and operating expenses.

Per barrel of oil equivalent ("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 financial statements for the period ended June 30, 2006, the audited financial statements and notes for the year ended December 31, 2005 and comparative information included therein.

This management's discussion and analysis is dated November 9, 2006.

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, 2006 compared to the Quarter ending September 30, 2005

PRODUCTION

The Corporation's quarter over quarter production growth for the three months ended September 30, 2006 continued, averaging 16,046 boe/d compared with 10,212 boe/d for the same period in 2005, an increase of 57%.

Average production grew 3% when compared to the second quarter of 2006. Production for the first nine months of 2006 averaged 14,990 boe/d, an increase of 59 percent from the 9,414 boe/d produced in the first nine months of 2005. This growth in production is entirely the result of successful internally generated drilling projects. The Corporation did not participate in any property or corporate acquisitions and disposed of a non-core property in the third quarter. The Corporation's average production rate for the third quarter of 2006 of 16,046 boe/d continued to be significantly below overall production capability due to unplanned shut-ins at Bigstone and Sundance Alberta of approximately 1,250 boe/d as well as 350 boe/d at Sundown BC. By the end of the third quarter the majority of these restrictions had been resolved.



Three Months Ended September 30
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2006 2005 Change
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Crude oil and liquids (bbls/d) 1,848 2,147 (14)%
Natural gas (mcf/d) 85,184 48,395 76%
Oil equivalent - boe 1,476,203 939,547 57%
Oil equivalent - boe/d 16,046 10,212 57%
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Area (boe/d) Third Quarter Second Quarter Third Quarter
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2006 2006 2005
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Northeast B.C. 5,467 4,816 2,997
Deep Basin 9,464 9,434 5,988
Other Areas 1,115 1,304 1,227
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16,046 15,554 10,212
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Production increases occurred as a result of growth primarily from Northeast BC where the tie-in of 10 new wells occurred. There were also 17 new Deep Basin wells tied in during this period. Deep Basin production for the quarter averaged 9,464 boe/d for an increase of 58% compared to the third quarter of 2005. In a like manner Groundbirch/Sunset production improved to 5,467 boe/d or an increase of 82% from the same quarter in 2005 and 14% from the second quarter in 2006. A decrease in production from other areas is due to the impact of the third quarter property sale.

REVENUE AND ROYALTIES

Revenue from petroleum and natural gas sales for the three months ended September 30, 2006 was $67.1 million representing a 29% increase over revenue of $52.1 million for the same period in 2005. The revenue increase attributed to volume growth was $30.2 million less a revenue decrease of $15.2 million attributed to product price decline during the quarter. Revenue includes all petroleum and natural gas sales and income from third party natural gas processing, reduced for field transportation costs and adjusted for the effects of commodity hedging. Wellhead oil and liquids prices for the third quarter of 2006 averaged $73.07 per barrel (including realized hedging losses of $0.29 per barrel) compared with $59.85 per barrel for the same period in 2005 (including realized hedging losses of $3.84 per barrel). When comparing Duvernay's third quarter 2006 oil and liquids price to the third quarter 2005, wellhead prices improved 22%. World oil price benchmarks improved by $7.29 U.S. in the third quarter of 2006 when compared to the same time period in 2005, or 12%.

Duvernay's oil and liquids price improvement was driven primarily by the commencement of the previously mentioned Dawson light oil discovery partly offset by the strengthening of the Canadian dollar relative to the US dollar by 7%. Duvernay's realized corporate gas price for the third quarter of 2006 continued to outperform the AECO spot price ($6.62 - net of transportation versus $5.73) . AECO natural gas prices decreased by 39% in the third quarter of 2006 compared to the third quarter of 2005. Duvernay's realized natural gas price decreased by 25% when comparing these quarters due to weakening AECO index prices partially offset by Duvernay entering into forward natural gas price contracts yielding better netbacks than daily indices. Gas Prices were also stronger than indices due to the sale of liquids rich gas in the Alberta Deep Basin. Transportation costs for the third quarter of 2006 were 3% of gross revenue or $1.32/boe, compared to 2% of gross revenue or $1.11/boe in the third quarter of 2005, this increase is mainly due to inflationary pressures in oil trucking. Third party processing income of $2.7 million increased primarily due to the recent completion of the Cecilia 15-4 expansion to 100 mmcf/d, attracting approximately 13 mmcf/d of third party natural gas.

For the nine months ended September 30, 2006, revenues increased to $195.3 million or 52% from the comparable period in 2005. This increase is primarily due to the increase in production volumes in 2006 as compared to 2005.




DUVERNAY WELLHEAD PRICES
Three Months Ended September 30
-----------------------------------
2006 2005 Change
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Crude oil and liquids ($/bbl) $ 73.07 $ 59.85 22%
Natural gas ($/mcf) $ 6.62 $ 8.84 (25)%
Oil equivalent ($/boe) $ 43.58 $ 54.47 (20)%
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BENCHMARK OIL & GAS PRICES

Three Months Ended September 30
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2006 2005 Change
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Oil
NYMEX U.S. $ 70.60 $ 63.31 12%
Edmonton Par Cdn. $ 80.25 $ 77.75 3%
Natural Gas
NYMEX Henry Hub U.S. $ 6.18 $ 9.69 (36)%
AECO $ 5.73 $ 9.39 (39)%
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Three Months Ended September 30
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Currency - Exchange Rates 2006 2005 Change
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Cdn/U.S.$ $ 0.8918 $ 0.8319 7%
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Revenue is analyzed as follows:

Three Months Ended September 30
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Revenue 2006 2005 Change
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Oil revenue $ 12,425 $ 11,821 5%
Natural gas 51,911 39,361 32%
Processing and other income 2,754 869 217%
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Revenue, net of transportation $ 67,090 $ 52,051 29%
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Duvernay's royalties are summarized as follows:

Three Months Ended September 30
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Royalties 2006 2005 Change
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Oil and liquids $ 1,691 $ 2,255 (25)%
Natural gas 6,995 7,023 (1)%
ARTC - (125) -
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Total royalties $ 8,686 $ 9,153 (5)%
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For the three months ended September 30, 2006, the average effective royalty rate was 13%, compared to 17% for the same period in 2005. Total oil and liquids royalties fell due to the sale of non-core oil properties during the second quarter of 2006. Weaker natural gas prices in combination with the effects of royalty holidays on new deep gas wells in Alberta have reduced Duvernay's royalty rates. 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. 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. Operating expenses of $5.28/boe for the third quarter of 2006 are slightly lower than the third quarter of 2005 operating expenses of $5.49/boe. These savings were offset by continued inflationary pressures in many field services including labour costs, equipment rental rates and subsurface repair and maintenance. For the nine months ending September 30, 2006, unit lease operating costs were $5.44/boe, slightly down from the same period in 2005 when they averaged $5.53/boe. Total operating expenses for the quarter were $7.8 million compared to $5.2 million in the third quarter of 2005. The Corporation's third quarter operating expenses include third party processing, gathering and compression fees of $2.0 million or 25% of total operating costs, down from the second quarter of 2006 when such costs were $2.6 million or 32% of total operating costs.



GENERAL & ADMINISTRATIVE EXPENSES

General and administrative expenses ("G&A") are summarized on the table
below as follows:

Three Months Ended September 30
-----------------------------------
2006 2005 Change
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G&A expenses $ 3,496 $ 2,634 33%
Administrative and operating recovery (456) (288) 58%
Capital recovery (1,717) (1,324) 30%
Capitalized G&A (442) (350) 26%
Stock based compensation 2,362 853 177%
Capitalized stock based compensation (1,024) - -
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Total G&A $ 2,219 $ 1,525 46%
Oil equivalent ($/boe) $ 1.50 $ 1.62 (7)%
Oil equivalent cash costs ($/boe) $ 0.60 $ 0.72 (17)%
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G&A expenses for the three months ending September 30, 2006 increased to $2.2 million from $1.5 million for the same period in 2005. G&A for the third quarter of 2006 dropped to $1.50/boe from $1.62/boe in 2005 as fixed costs are spread over a larger production volume and a larger operated capital program has resulted in higher capital recoveries. When stock based compensation of $0.90/boe is removed, the Corporation's cash general and administrative costs improved to $0.60/boe from $0.72/boe for the same period in 2005. This improvement is due to production volume growth of 57% exceeding the growth in general and administrative expenses combined with a larger capital spending leading to higher recoveries. The increase in Stock based compensation is due to a large option issuance in the fourth quarter of 2005, most of the impact of which is being recognized in 2006. The percentage of head office expenses capitalized as attributable to exploration activities was 35%, consistent with the third quarter of 2005.

For the nine months ended September 30, 2006, total G&A expenses including stock-based compensation increased to $6.5 million ($1.60/boe) from $4.6 million ($1.80/boe) for the same period in 2005. On a cash basis, G&A per unit of production improved to $0.63/boe from $0.86/boe in the first nine months of 2005, an improvement of 27%.

DEPLETION, DEPRECIATION AND ACCRETION

Depletion, depreciation and accretion expense ("DD&A") increased to $25.8 million during the third quarter of 2006 from $13.2 million during the same period in 2005. On a dollars per boe basis, DD&A increased to $17.48 from $14.00 in the third quarter of 2005. The percentage of the property, plant and equipment investment excluded from the Corporation's costs subject to depletion (7% in 2006; 8% in 2005) decreased slightly when comparing the third quarter of 2006 with 2005. Depletion rates in 2006 increased primarily as a result of inordinately large 2005 capital expenditures in land and facilities. The third quarter of 2006 depletion rate of $17.48/boe has decreased slightly from the $17.87/boe recorded in the second quarter of 2006. During the first nine months of 2006, the depletion rate was $18.10/boe compared to $13.73/boe for the first nine months of 2005.

INCOME TAXES

The Corporation did not pay any cash taxes in the third quarter of 2006. The Corporation does not expect to pay any cash income taxes in 2006 based on existing tax pools, planned capital expenditures and the most recent forecast of 2006 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 one to two years. Federal tax rate reductions introduced during the second quarter have lowered the effective rate of the Corporation's future income tax, lowering the nine month future income tax expense.

FUNDS FROM OPERATIONS AND EARNINGS

Funds from operations increased to $46.1 million ($0.85 per diluted equity share) for the three months ending September 30 from $35.8 million ($0.71 per diluted equity share) for the comparable period in 2005. On a per share basis, funds from operations increased by 20% due to stronger operating results partially offset by weaker gas prices. After tax earnings decreased by 21% for the third quarter of 2006 when compared to the same period in 2005 to $12.3 million from $15.5 million. On a per share basis, diluted earnings decreased to $0.24 from $0.31, a 23% decline. Both absolute and per share earnings weakened slightly, primarily due to higher DD&A and interest charges. On a pretax basis, third quarter 2006 earnings of $18.9 million were down slightly from the same quarter in 2005 ($22.1 million).



Three Months Ended Nine Months Ended
September 30 September 30
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2006 2005 Change 2006 2005 Change
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Funds from operations per
equity share (1) $ 0.85 $ 0.71 20% $ 1.53 $ 1.73 (12)%
Earnings per equity share
(1) $ 0.24 $ 0.31 (23)% $ 0.86 $ 0.66 30%
Operating netback per boe $ 32.42 $ 39.24 (17)% $ 32.80 $ 34.00 (4)%
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note: (1) diluted


LIQUIDITY AND CAPITAL RESOURCES

The Corporation invested $153.9 million in the third quarter of 2006 compared to $117.9 million in the third quarter of 2005, as set out in the following table.



Three Months Ended September 30
($ thousands) 2006 2005 Change
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Land and seismic $ 10,252 $ 5,077 102%
Drilling and completions 127,490 91,166 40%
Facilities 25,496 23,275 10%
Property Acquisition /(Disposition) (9,960) (2,032) 390%
Other 588 420 40%
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Total 153,866 $ 117,906 30%
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The Corporation drilled 40 gross wells (33.9 net) of which 23 are Deep Basin, 8 are Sunset/Groundbirch and 9 are in other areas. Forty six gross wells (39.3 net) were completed during the third quarter. Approximately $6.8 million was invested at crown land sales in Northeast B.C. and the Alberta Deep Basin to purchase 13,280 net undeveloped acres.

For the nine months ending September 30, 2006, the Corporation has invested $408.3 million compared to $291.2 million for the comparable period in 2005. The first nine months of 2006 is characterized by higher levels of drilling and facility construction activities.

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

During October 2006, the following significant transactions closed:

(a) The Corporation completed an equity financing issuing 1,100,000 common shares at $43.75 per share for gross proceeds of $48.125 million. The proceeds of the financing will be dedicated to previously planned exploration drilling projects,

(b) A $37 million asset purchase in the Corporations North East B.C. core area adds 500 bbls/day of new production,

(C) Duvernay completed a new syndicated bank facility with a group of Canadian banks. The new facility has borrowing capacity of $375 million, up from $300 million in place at September 30, 2006. In addition the Corporation has a $25 million operating line. The new facility has been established on terms similar to those previously in place.

Duvernay has also entered into an agreement with a private company related to Duvernay to sell non-core Peace River Arch assets contributing approximately 700 bbls/day for total consideration of $85 million. This transaction is expected to close in December 2006.

At September 30, 2006 the Corporation estimates that it has fully spent the $82.45 million in 2005 flow-through offerings and has a $44 million remaining obligation for the May 2006 flow-through offerings which must be completed by December 31, 2007.

As at September 30, 2006, the Corporation had 52,604,607 shares outstanding and 4,094,985 stock options outstanding. As at November 9, 2006, the Corporation has 53,722,940 shares outstanding and 4,076,985 stock options outstanding. During the period from September 30, 2006 until November 9, 2006, 18,333 common shares were issued on the conversion of employee stock options and no new stock options were issued.

COMMODITY PRICE RISK MANAGEMENT

The Corporation makes use of specific commodity hedging instruments that serve two primary business objectives. The first objective is to reduce the variability in cash flows from fluctuations in product prices to ensure a source of funding for the 2006 and 2007 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.

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.

During the third quarter of 2006, the Corporation's Petroleum and Natural gas sales of $66.3 million included realized hedging gains of $7.5 million. At September 30, 2006 Duvernay assessed the prevailing market value of similar contracts to those that were unsettled at September and has estimated net proceeds from settling these instruments to be approximately $10.5 million. Financial Statement note 6 "Commodity Price Risk Management" provides further details.



2006
-------------------------------
Q3 Q2 Q1
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PRODUCTION
Crude oil and liquids (bbls) 170,051 111,557 143,926
Gas (mcf) 7,836,912 7,823,061 6,339,802
Oil equivalent (boe) 1,476,203 1,415,401 1,200,560
Crude oil and liquids (bbls/d) 1,848 1,226 1,599
Gas (mcf/d) 85,184 85,968 70,442
Oil equivalent (boe/d) 16,046 15,554 13,340
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FINANCIAL
($ thousands, unless noted)
Revenue, net of royalties and transportation 58,404 49,550 52,171
Funds from operations 46,081 39,009 43,244
Per share basic 0.88 0.75 0.86
Net earnings 12,309 21,677 12,133
Per share basic 0.24 0.42 0.24
Per share diluted 0.23 0.40 0.23
Total assets 1,173,784 1,022,445 971,616
Bank debt 296,703 271,692 221,760
Cash and working capital (deficiency) (87,959) (6,154) (53,148)
Basic outstanding Shares 52,605 52,307 51,205
---------------------------------------------------------------------------

PER UNIT
Gas, net of transportation ($/mcf) 6.62 6.55 9.12
Crude oil and liquids, net of
transportation ($/bbl) 73.07 75.49 59.61
Revenue, net of transportation ($/boe) 43.58 42.18 55.31
Operating netback ($/boe) 32.42 29.28 37.42
---------------------------------------------------------------------------


2005 2004
---------------------------------------------------
Q4 Q3 Q2 Q1 Q4
---------------------------------------------------------------------------
PRODUCTION
Crude oil and liquids
(bbls) 262,755 197,497 205,527 147,723 120,282
Gas (mcf) 5,931,351 4,452,299 4,218,977 3,443,570 3,293,899
Oil equivalent (boe) 1,251,314 939,547 908,690 721,651 669,265
Crude oil and liquids
(bbls/d) 2,856 2,147 2,259 1,641 1,307
Gas (mcf/d) 64,471 48,395 46,362 38,262 35,803
Oil equivalent (boe/d) 13,601 10,212 9,986 8,018 7,275
---------------------------------------------------------------------------

FINANCIAL
($ thousands, unless noted)
Revenue, net of
royalties and
transportation 64,170 42,898 33,217 26,906 24,904
Funds from operations 53,828 35,758 26,495 21,372 19,064
Per share basic 1.10 0.75 0.58 0.48 0.44
Net earnings 18,287 15,532 8,537 7,719 6,213
Per share basic 0.37 0.32 0.19 0.17 0.14
Per share diluted 0.35 0.31 0.18 0.16 0.14
Total assets 827,263 672,868 548,268 474,245 393,440
Bank debt 175,481 141,792 79,190 68,859 40,724
Cash and working capital
(deficiency) (40,180) (28,005) (8,602) (52,366) (13,439)
Basic outstanding Shares 49,345 47,856 45,844 44,436 42,857
---------------------------------------------------------------------------

PER UNIT
Gas, net of
transportation ($/mcf) 10.72 8.84 7.58 7.59 7.12
Crude oil and liquids,
net of transportation
($/bbl) 59.86 59.85 51.48 48.76 42.81
Revenue, net of
transportation ($/boe) 63.40 54.47 47.16 46.22 42.74
Operating netback ($/boe) 44.90 39.24 31.19 31.02 30.89
---------------------------------------------------------------------------


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




INTERIM BALANCE SHEETS
(Unaudited) (Thousands of dollars) September 30, December 31,
2006 2005
---------------------------------------------------------------------------
ASSETS
Current assets:
Accounts receivable $ 65,169 $ 58,215
Prepaid expenses and deposits 1,802 530
---------------------------------------------------------------------------
66,971 58,745

Property, plant and equipment (note 2) 1,106,813 768,518
---------------------------------------------------------------------------
$ 1,173,784 $ 827,263
---------------------------------------------------------------------------

LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Bank indebtedness $ 10,132 $ -
Accounts payable and accrued liabilities 144,798 98,925
---------------------------------------------------------------------------
154,930 98,925

Long-term debt (note 3) 296,703 175,481
Asset retirement obligation (note 4) 10,098 9,491
Future income taxes 92,392 61,054

Shareholders' equity:
Share capital (note 5) 482,422 396,450
Contributed surplus (note 5) 10,172 4,915
Retained earnings 127,067 80,947
---------------------------------------------------------------------------
619,661 482,312
---------------------------------------------------------------------------
Subsequent Events (Note 8) $ 1,173,784 $ 827,263
---------------------------------------------------------------------------

See accompanying notes to interim financial statements.

On behalf of the Board:

Robert W. Blakely Michael L. Rose
Director Director


INTERIM STATEMENTS OF EARNINGS AND RETAINED EARNINGS


(Unaudited) Three Months Ended Nine Months Ended
September 30 September 30
(Thousands of dollars ------------------------------------------
except per share amounts) 2006 2005 2006 2005
---------------------------------------------------------------------------
Revenue:
Petroleum and natural gas sales $ 66,287 $ 52,226 $ 195,205 $ 130,102
Royalties (8,686) (9,153) (33,961) (25,485)
Processing and other income 2,754 869 4,825 1,431
---------------------------------------------------------------------------
60,355 43,942 166,069 106,048
Expenses:
Operating 7,794 5,160 22,244 14,208
Transportation 1,951 1,044 4,773 3,027
General and administrative 881 672 2,582 2,222
Stock-based compensation 1,338 853 3,965 2,404
Interest 3,648 987 8,136 2,241
Depletion, depreciation and
accretion 25,801 13,158 74,078 35,289
---------------------------------------------------------------------------
41,413 21,874 115,778 59,391
---------------------------------------------------------------------------
Earnings before taxes 18,942 22,068 50,291 46,657
Taxes:
Capital - 321 - 724
Future (note 7) 6,633 6,215 4,171 14,145
---------------------------------------------------------------------------
6,633 6,536 4,171 14,869
---------------------------------------------------------------------------
Net earnings 12,309 15,532 46,120 31,788
Retained earnings, beginning of
period 114,758 47,128 80,947 30,872
---------------------------------------------------------------------------
Retained earnings, end of
period $ 127,067 $ 62,660 $ 127,067 $ 62,660
---------------------------------------------------------------------------
Net earnings per share: (Note 5)
Basic $ 0.24 $ 0.32 $ 0.89 $ 0.69
Diluted 0.23 0.31 0.86 0.66
---------------------------------------------------------------------------
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) 2006 2005 2006 2005
---------------------------------------------------------------------------
Cash provided by (used in):
Operations:
Net earnings $ 12,309 $ 15,532 $ 46,120 $ 31,788
Items not involving cash:
Depletion, depreciation, and
accretion 25,801 13,158 74,078 35,289
Stock-based compensation 1,338 853 3,965 2,404
Future income taxes 6,633 6,215 4,171 14,145
Abandonment expenditures (294) - (380) -
Change in non-cash operating
working capital (12,847) (11,652) (6,060) (12,134)
---------------------------------------------------------------------------
32,940 24,106 121,894 71,492
Financing:
Issue of common shares, net of
issue costs 1,263 143 111,396 87,801
Increase in long-term debt 25,010 62,602 121,221 101,068
---------------------------------------------------------------------------
26,273 62,745 232,617 188,869
Investments:
Additions to property, plant,
and equipment (163,825) (119,938) (435,352) (288,129)
Property dispositions 9,960 2,032 27,002 1,068
Change in non-cash working
capital 84,520 30,910 43,707 26,557
---------------------------------------------------------------------------
(69,345) (86,996) (364,643) (260,504)
Increase (decrease) in cash (10,132) (145) (10,132) (143)
Cash, beginning of period - 145 - 143
---------------------------------------------------------------------------
Cash, end of period (10,132) - (10,132) -
---------------------------------------------------------------------------
Cash tax $ - $ - $ 1,279 $ 613
Cash interest $ 3,842 $ 1,107 $ 9,645 $ 2,292
---------------------------------------------------------------------------
See accompanying notes to interim financial statements.


NOTES TO FINANCIAL STATEMENTS

Information as at September 30, 2006 and for the nine 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, 2005 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, 2005.

2. PROPERTY, PLANT AND EQUIPMENT:

The cost of unproven lands and seismic costs at September 30, 2006 of $84.8 million (December 31, 2005 -$114 million) has been excluded from the depletion calculation.

General and administrative expenditures of $4.3 million, including $2.1 million of stock based compensation and a corresponding future tax liability of $0.9 million, for the nine months ended September 30, 2006 (2005 - $1.1 million) have been capitalized and included as costs of petroleum and natural gas properties.

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 $375 million in addition to a $25 million operating line. The financial terms of this agreement are unchanged from the previous credit agreement. As at September 30, 2006, $297 million of this term loan was drawn.

4. ASSET RETIREMENT OBLIGATIONS:

The Corporation's asset retirement obligations result from net ownership interests in petroleum and natural gas assets including well sites, gathering systems and processing facilities. The Corporation estimates the total undiscounted amount of cash flows required to settle its asset retirement obligations to be approximately $24.5 million (December 31, 2005 - $17.8 million) which will be incurred between 2014 and 2022. A credit-adjusted risk-free rate of 7% and an inflation rate of 3% were used to calculate the fair value of the asset retirement obligations.



A reconciliation of the asset retirement obligations is provided below:

September 30, December 31,
2006 2005
---------------------------------------------------------------------------
Balance, beginning of period $ 9,491 $ 5,849
Accretion expense 489 640
Change in estimate (1,402) -
Liabilities incurred 1,900 3,302
Liabilities settled (380) (300)
---------------------------------------------------------------------------
Balance, end of period $ 10,098 $ 9,491
---------------------------------------------------------------------------


5. SHARE CAPITAL:

(a) Authorized:

Unlimited number of common shares and Class A common shares

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

(b) Common shares issued:



Number of
Shares Amount
---------------------------------------------------------------------------
Balance, December 31, 2005 49,345,308 $ 396,450
For cash on public share issue 1,250,000 55,625
For cash on private placement of flow-through 1,000,000 56,000
shares
For cash on exercise of stock options 1,009,299 5,123
Contributed surplus on exercise of stock options - 843
Share issue costs - (5,352)
Tax effect on share issue costs - 1,589
Tax effect on flow-through renunciation - (27,856)
---------------------------------------------------------------------------
Balance, September 30, 2006 52,604,607 $ 482,422
---------------------------------------------------------------------------


(c) Flow-through shares:

At September 30, 2006 the Corporation estimates that it has fully spent the $82.45 million in 2005 flow-through offerings and has a $44 million remaining obligation for the May 2006 flow-through offerings which must be completed by December 31, 2007.




(d) Contributed surplus:
---------------------------------------------------------------------------
Contributed surplus, December 31, 2005 $ 4,915
Stock-based compensation 6,100
Exercise of stock options (843)
---------------------------------------------------------------------------
Contributed surplus, September 30, 2006 $ 10,172
---------------------------------------------------------------------------



(e) Stock options:

The Corporation has a rolling stock option plan. Under the employee stock option plan, the Corporation may grant options to its employees for up to 5,260,461 shares of common stock. The exercise price of each option equals the market price of the Corporation's stock on the date of grant and an option's maximum term is five years. Options are granted throughout the year and vest 1/3 on each of the first, second and third anniversaries from the date of grant.

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




Number of Weighted
Options average
exercise
price
---------------------------------------------------------------------------
Stock options outstanding, beginning of period 4,653,284 $ 14.44
Granted 451,000 38.76
Exercised (1,009,299) 5.08
---------------------------------------------------------------------------
Stock options outstanding, end of period 4,094,985 $ 19.42
---------------------------------------------------------------------------


(f) Stock-based compensation:

The weighted average fair value of the stock options granted during the period was $11.48 (2005 - 8.48) 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:



Risk-free interest rate (%) 4.5
Expected life (in years) 3.5
Expected volatility (%) 33
Expected dividend -
Expected forfeitures (%) 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, 2006 was 52,091,297 (51,874,894 nine months).

In computing diluted earnings per share for the quarter ended September 30, 2006, 1,644,950 (1,752,509 nine months) shares were added to the weighted average number of common shares outstanding for the dilution from the stock options.

6. COMMODITY PRICE RISK MANAGEMENT:

As at September 30, 2006, the Corporation had fixed the price applicable to future production as follows:




Time period Type of Quantity Contract price
contract control
---------------------------------------------------------------------------
2006 October - December Physical 100 bbls/day $75.48 U.S. W.T.I.
(swap) average
2007 January - June Physical 200 bbls/day $72.90 U.S. W.T.I.
(swap) average
2007 January - December Physical 100 bbls/day $79.55 U.S. W.T.I.
(swap)
2007 October - December Physical 200 bbls/day $72.59 U.S. W.T.I.
(swap)
2006 October Physical 5,000 gj's/day $ 9.32 Cdn/gj
(swap) average
2006 October - December Physical 3,000 gj's/day $ 7.61 Cdn/gj
(swap) average
2006 November - 2007 Physical 13,000 gj's/day $ 9.60 Cdn/gj
March (swap) average
2007 January - March Physical 3,000 gj's/day $ 9.00 Cdn/gj
(swap)
2006 October Call 7,000 gj's/day $10.45 Cdn/gj
(ceiling)
2006 November - December Call 5,000 gj's/day $10.00 Cdn/gj
(ceiling)
2006 October Collar 2,000 gj's/day $ 6.86 Cdn/gj Floor
$ 9.66 Cdn/gj
Ceiling
2006 October Collar 3,000 gj's/day $10.00 Cdn/gj
Floor
$11.00 Cdn/gj
Ceiling
---------------------------------------------------------------------------


The estimated aggregate fair value of the fixed price contracts based on the amounts the Corporation would receive if the contracts were terminated as at September 30, 2006 is approximately $10.5 million.

7. TAXES

During the second quarter of 2006, the federal government substantively enacted legislation reducing federal tax rates. This legislation reduced the Corporations income tax liability and provision for future taxes by $11.8 million, this impact was recognized in the second quarter.

8. SUBSEQUENT EVENTS:

(a) Flow-through shares

On October 12, 2006 Duvernay completed an equity financing issuing 1,100,000 common shares on a flow-through basis at an issue price of $43.75 per share for gross proceeds of $48.125 million.

(b) Asset Purchase

On October 31, 2006 the Corporation completed a transaction to purchase a producing property for $37.0 million.

(c) Asset Sale

The Company has entered into a transaction to sell a non-core producing asset to a private corporation related to Duvernay for consideration of approximately $85 million. The transaction is expected to close on December 15, 2006.

FORWARD LOOKING STATEMENTS

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

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

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

Contact Information

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