Duvernay Reports Pool Oil and Gas Discoveries in Alberta, British Columbia

Duvernay Oil Corp. on Thursday said that it has made significant new pool exploration discoveries and reported its financial and operational results for the second quarter ended June 30, 2006.


- Confirmation and delineation of a second, significant new pool Triassic Doig gas discovery in Northeast B.C.
- A deep, multi-zone, gas discovery at Spirit River Alberta
- A deep, extensive new pool gas discovery in the Alberta Deep Basin complex
- 17 percent quarter over quarter production growth between first and second quarters of 2006 (16% growth on a production per share basis), highlighted by a 22 percent quarter over quarter increase in natural gas production, averaging 86 mmcf/d
- Earnings per share of $0.40 (diluted), a 74% improvement from the first quarter of 2006 and 122% higher than the same quarter in 2005
- Syndication of Banking Facility including expanded credit line to $325 million from $250 million
- Commissioned 2 new gas plants in Northeast BC and completed a major expansion of a gas processing facility in Alberta

Production Outlook

Second quarter 2006 average production of 15,554 boe/d was 17% higher than first quarter 2006 production of 13,340 boe/d and 56% higher that second quarter 2005 production. Peak production of 18,200 - 18,300 boe/d was achieved during the quarter in the second half of May. The second quarter average production level was reduced by several unplanned interruptions, particularly in June. These include; a shut-in of all Duvernay Bigstone Alberta area gas volumes during the second quarter due to capacity constraints at a third party processing facility (800 boe/d), restrictions on a third party sales pipeline at Sundown BC (350 boe/d), Alberta Deep Basin gas shut-ins during the start-up of the Duvernay Cecilia plant expansion and related field facilities (200 boe/d), restrictions on the Duke sales system in BC during June (300 boe/d). In addition, the Company has had gas volumes that flow to a third party compression facility at Sundance Alberta shut-in for the past 3 weeks. The majority of these interruptions will be eliminated late in the third quarter. The Bigstone volumes will be returned to production via a new pipeline connecting Bigstone to Duvernay's Cecilia 15-4 system. Existing Sundance production (3 mmcf/d) and production from new wells (7 mmcf/d) will be brought on-stream through a new Duvernay compression and dehydration facility in late August. Restrictions in BC, primarily at Sundown, will be alleviated by a Duvernay pipeline connecting the Sundown and Brassey plants during the first quarter of 2007.

The return of the Bigstone volumes and Sundance volume additions coupled with tie-ins and start-ups elsewhere in the Deep Basin and Northeast BC are expected to bring daily production volumes to the 20,000 boe/d level late in the third quarter. The production addition delays encountered in the first half of 2006 and the unscheduled interruptions encountered in the second quarter will result in an estimated full year daily average volume of between 18,000 and 18,500 boe/d, a modest reduction from the original daily average projection of 19,600 boe/d. Duvernay expects quarter over quarter production growth to range between 5 and 20% over the next several quarters. Second quarter 2006 was at the high end of this growth range. Duvernay is currently targeting an exit production level of between 23,000 and 25,000 boe/d for 2006, and expects to finalize this estimate early in the fourth quarter.

2006 Capital Program

The original 2006 $400 million EP Capital program remains unchanged, Duvernay is ahead of schedule with the ongoing 2006 drilling and completion program. The Company will continue to closely monitor natural gas prices and the impact on the second half cash flow and adjust the capital program accordingly. Stronger natural gas prices may lead to a program expansion as the exploration successes, disclosed below, provide additional drilling and facility opportunities. The per well Development gas well deliverabilities are also ahead of expectation which may allow 2006 exit production levels to be achieved with fewer 2006 development wells, providing additional capital flexibility. Full year 2006 facility expenditures of approximately $67.5 million will be significantly less than 2005 facility expenditures of $103.0 million, which will provide more capital for EP drilling and be a benefit to 2006 finding and development costs.

Although the two main development complexes are primarily gas projects, where possible the company will pursue light oil opportunities in the overall portfolio during the balance of 2006. The oil discoveries at Dawson, the Puskwa exploration effort and several successful uphole completions in the Alberta Deep Basin will increase the Company's overall oil production volumes as well as the overall percentage of liquids production.

During the second quarter, the Company's banking facility was syndicated and expanded to $325.0 million from $250.0 million. The Company estimates that it has increased proved producing reserves by approximately 50% thus far in 2006, the majority of which was not utilized in determining the expanded credit facility in April.

Duvernay also plans to continue disposing of smaller non-core properties and re-invest the resultant capital in the two large gas project areas. This inventory of smaller properties is generated by a portion of the exploration program; the more significant new pool discoveries will be retained and developed. This on-going sale of non-core Exploration initiated properties resulted in the sale of Pembina (250 boe/d) during the second quarter for approximately $12.5 million.

In the third quarter, the company has sold a non-core, Peace River High property (80 boe/d net) for $10.0 million.

Operating Costs

Operating costs in the first half were $5.52/boe as the Company continued its top decile cost performance. The Company expects to reduce operating costs below the $5.00/boe level in the second half of the year, primarily through the impact of increasing production volumes spread over a relatively fixed cost base. The major 2006 cost reduction effort is the re-routing of production volumes from third party facilities in the Alberta Deep Basin to the expanded Duvernay Cecilia plant. The majority of these projects were completed during the second quarter, the full impact of these cost reductions will be realized in the second half of 2006. Ongoing dispositions of higher cost, non-core assets in the property inventory will also continue to reduce costs.


Duvernay currently has four drilling rigs and four service rigs active in the Sunset-Groundbirch-Sundown operated area. The Company has drilled 22 wells thus far in the complex in 2006 and has a total of 12 gas wells awaiting tie-in.

During the second quarter, new Duvernay owned and operated gas plants were commissioned at Brassey and Sundown, bringing total Northeast BC production to the 6000 boe/d level from the 4 plants. Production from Sundown was restricted by approximately 3.5 mmcf/d due to ongoing restrictions in the outside operated sales gas line connecting Sundown with the Alberta gas delivery system.

The major highlight from the BC complex thus far in 2006 is the discovery of at least one additional expansive Triassic Doig gas pool complementing the original discovery made by the Company in 2003. During the second quarter, the Company further assessed the new pool Doig discoveries made in March and consolidated land on these pools. The 16-33-79-18W6 discovery well tested at stabilized gas rates of 5.1 mmcf/d with approximately 300 boe/d of associated condensate and liquids. The pool, currently defined by 3 wells, appears to extend over a minimum of 12 miles and with further extension drilling could prove to be significantly larger. Duvernay expects to drill four additional wells delineating this new pool prior to year end. The Company has also made new pool Doig discoveries at Sundown and East Sunset that are currently being assessed. At Sundown the a-10-A 93-P10 well tested at rates of 3.5 mmcf/d and the step-out at a-23-B 93-P-10 is currently being production tested. This pool also appears to be of significant areal extent.

Fully developed, the Company estimates that the original Groundbirch gas pool could yield up to 500 bcf of gas reserves. At year end 2005, approximately 100 bcf was already recognized by independent engineering with over 250 locations remaining to be drilled into this pool. The ongoing delineation drilling of the new discoveries will ascertain whether these pools are of comparable reserve size.

The Company is pursuing three facility projects with first half 2007 target completion dates to significantly expand BC production volumes. The first is a tie-in between the Duvernay Sundown and Brassey gas plants to alleviate the sales line restriction issue at Sundown. The second is an expansion of the Brassey plant to double the existing capacity. The third is a tie-in to the Duke raw gathering system at the north end of the Duvernay complex to allow for processing of additional shut-in volumes and for processing of more sour gas that the deeper exploration program is targeting.

Alberta Deep Basin

Duvernay is currently operating six drilling rigs and 8 service rigs in the Alberta Deep Basin complex. Thus far in 2006, the Company has drilled a total of 47 new gas wells. The 100% owned and operated Cecilia 15-4 gas plant expansion to 100 mmcf/d capacity was completed in late May. Duvernay expects the plant to be full during the fourth quarter of 2006 as the aggressive gas well tie-in program continues. The Company has 55 wells either drilled and/or completed awaiting tie-in in the Deep Basin complex. Duvernay now has working interests in 345 sections in the Deep Basin complex, a 15% increase thus far in 2006.

The company has approximately 5.0 mmcf/d of gas production shut-in at Bigstone due to capacity restraints at a third party gas processing facility. This shut-in, which commenced April 1, is expected to be alleviated in mid-September with the re-routing of this gas to Duvernay's Cecilia plant via a new pipeline currently under construction.

At Sundance Alberta, where the company has approximately 3.0 mmcf/d of existing production intermittently shut-in, a new Duvernay facility is planned for a late August start-up. Duvernay expects production levels of 10 mmcf/d at Sundance (70% average working interest) from the existing shut-in production and two new high rate gas wells drilled during the first half.

In the Marsh-Pedley area of Alberta, the Company has experienced recent strong drilling and completion results. The Duvernay Marsh 10-26-54-25 W5 well tested at a final production rate of 2.05 mmcf/d and is now on-stream. The 8-35-54-25 W5 well production tested at rates between 2.0 and 3.3 mmcf/d. The 14-25-53-24 W5 well was drilled in July and is expected to be tested prior to the end of the third quarter.

At Pine Creek, Duvernay has made a significant new Jurassic pool discovery extending over several square miles. The Company has three wells into the pool thus far, one of which is on-stream. Stabilized production rates of between 750 mcf/d and 1.0 mmcf/d have been realized, Duvernay controls 14 sections on the pool and expects to develop the pool ultimately with 2 wells per section. The Company estimates ultimate fully developed reserves of 50 to 75 bcf including associated uphole Cretaceous gas zones at Pine Creek.

Exploration Program

In addition to the exploration successes outlined at Sunset-Groundbirch, B.C. and Pine Creek Alberta, the company has also made significant new pool discoveries at Spirit River and Dawson Alberta.

At Spirit River, the company has cased a Devonian new pool wildcat, drilled in July, to total depth. The 12-29-71-7 W6 well has wireline log gas pay in six formations including the Devonian Wabamun, Mississippian Banff, Mississippian Kiskatinaw, Triassic Montney, Triassic Charlie Lake and Cretaceous Gething formations. Production testing will commence this week, the company is expecting to drill a twin well late in the third quarter to more efficiently access and drain the shallow pay zones. A second deep new pool wildcat has been cased at 6-10-77-7 W6 and will also be tested during the third quarter. One or more of the deeper Paleozoic gas accumulations has the potential for significant areal extent, to be confirmed through additional drilling. Duvernay has a working interest in the Sexsmith gas plant as well as firm capacity at a third party sour facility in the area, providing access and flexibility for processing new, sour gas reserves.

At Dawson Alberta, Duvernay has now drilled three successful Devonian Slave Point oil wells thus far in 2006. The 2-13-81-15 W5 production tested 38 degrees API oil at rates of 625 boe/d. The well has been on production at restricted rates of 300 boe/d for the past three weeks. The 5-1-81-16W5 well production tested 38 degrees API oil at rates in excess of 500 boe/d and is expected to commence production this week. The 14-12-81-15 W5 is drilled and cased as a Slave Point oil well with production testing anticipated to be completed within the next week. Several additional Slave Point locations are planned at Dawson during the half, surface access permitting.

At Puskwa Alberta, the Company's 3-D seismic survey was acquired and processed during the past two months. Second half 2006 Devonian wildcats on Duvernay's extensive land holdings are planned based upon the final seismic interpretation.

At Edson Alberta, the 8-13-54-19 W5 Devonian exploration well has been submitted for licensing; Duvernay is waiting for final approval by the EUB, and expects a response imminently.


The Corporation achieved strong quarter over quarter production growth for the three months ended June 30, 2006 averaging 15,554 boe/d compared with 9,986 boe/d for the same period in 2005, an increase of 56%. In a similar manner, average production grew 17% when compared to the first quarter of 2006. Production for the first six months of 2006 averaged 14,453 boe/d, an increase of 60 percent from the 9,007 boe/d produced in the first six 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 early in the second quarter. The Corporation's average production rate for the second quarter of 2006 of 15,554 boe/d was significantly below overall production capability due to unplanned shut-ins at Bigstone, Alberta of 800 boe/d and Sundown, B.C. of 350 boe/d due to third party plant restrictions as well as production interruptions related to the commencement of the plant expansion at Cecilia Alberta of 200 boe/d.

Production increases occurred as a result of growth primarily from the deep basin where 19 new wells have been tied in during the second quarter and in Northeast BC where two new gas plants were brought on-stream along with the tie-in of 13 new wells. Duvernay's Deep Basin production for the quarter averaged 9,434boe/d for an increase of 81% compared to the second quarter of 2005 and 22% compared to the first quarter of 2006. In a like manner Groundbirch/Sunset production improved to 4,816 boe/d or an increase of 65% from the same quarter in 2005 and 16% from the first quarter in 2006. The modest decline in production from other areas is entirely due to property dispositions in non-core areas during the past six months.

Revenue and Royalties

Revenue from petroleum and natural gas sales for the three months ended June 30, 2006, was $60.9 million representing a 43% increase over revenue of $42.7 million for the same period in 2005. The revenue increase attributed to volume growth was $22.5 million less a revenue decrease of $5.4 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 second quarter of 2006 averaged $75.49 per barrel (including realized hedging losses of $0.71 per barrel) compared with $51.48 per barrel for the same period in 2005 (including realized hedging losses of $2.90 per barrel). When comparing Duvernay's second quarter 2006 oil and liquids price to the second quarter 2005, wellhead prices improved 47%. World oil price benchmarks improved by $17.50 U.S. in the second quarter of 2006 when compared to the same time period in 2005, or 33%.

Duvernay's oil and liquids price improvement was muted primarily by the strengthening of the Canadian dollar relative to the U.S. dollar by 11%. Duvernay's realized corporate gas price for the second quarter of 2006 continued to outperform the AECO spot price ($6.55 versus $6.02). AECO natural gas prices decreased by 18% in the second quarter of 2006 compared to the second quarter of 2005. Duvernay's realized natural gas price decreased by 14% 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 second quarter of 2006 were 2.3% of gross revenue or $1.03/boe, compared to 2.6% of gross revenue or $1.27/boe in the second quarter of 2005.

For the six months ended June 30, 2006, revenues increased to $128.2 million or 68% from the comparable period in 2005. This increase is primarily due to the increase in production volumes in 2006 as compared to 2005.

For the three months ended June 30, 2006, the average effective royalty rate was 17%, compared to 22% for the same period in 2005. 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 new 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.

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 $5.72/boe for the second quarter of 2006 are slightly higher than the second quarter of 2005 operating expenses of $5.44/boe. As significant existing Alberta gas production was re-routed during the second quarter into company operated facilities, lower processing fees were being observed late in the quarter. 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 six months ending June 30, 2006, unit lease operating costs were $5.52/boe, slightly down from the same period in 2005 when they averaged $5.55/boe. Total operating expenses for the quarter were $8.1 million compared to $4.9 million in the second quarter of 2005. The corporation's operating expenses include third party processing, gathering and compression fees of $2.6 million or 32% of total operating costs.

G&A expenses for the three months ending June 30, 2006 increased to $2.5 million from $1.8 million for the same period in 2005. G&A for the second quarter of 2006 dropped to $1.79/boe from $1.99/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 $0.95/boe is removed the Corporation's cash general and administrative costs improved to $0.84/boe from $0.88/boe for the same period in 2005. This improvement is due to production volume growth of 56% exceeding the growth in general and administrative expenses combined with a larger capital spending leading to higher recoveries. The percentage of head office expenses capitalized as attributable to exploration activities was 35%, consistent with the second quarter of 2005.

For the six months ended June 30, 2006, total G&A expenses increased to $4.3 million ($1.65/boe) from $3.1 million ($1.90/boe) for the same period in 2005. On a cash basis, G&A per unit of production improved to $0.65/boe from $0.95/boe in the first six months of 2005.

Depletion, Depreciation and Accretion

Depletion, depreciation and accretion expense ("DD&A") increased to $25.3 million during the second quarter of 2006 from $12.0 million during the same period in 2005. On a dollars per boe basis, DD&A increased to $17.87 from $13.22 in the second quarter of 2005. The percentage of the property, plant and equipment investment excluded from the Corporation's costs subject to depletion (9% in 2006; 10% in 2005) decreased slightly when comparing the second 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 second quarter of 2006 depletion rate of $17.87/boe has decreased from the $19.15/boe recorded in the first quarter of 2006. During the first six months of 2006, the depletion rate was $18.45/boe compared to $13.57/boe for the first six months of 2005.

Income Taxes

The Corporation did not pay any cash taxes in the second quarter of 2006. The Corporation does not expect to pay any cash taxes in 2006 based on existing tax pools, planned capital expenditures and the most recent forecast of 2006 taxable income. Although current tax horizons depend on product prices, production levels, and the nature, magnitude and timing of capital spending, the Corporation currently believes that no cash income tax will be payable for two to three years. Reductions in federal income tax rates have reduced the effective rate of the Corporation's future income tax rate resulting in a favourable adjustment to future income taxes of approximately $11.8 million.

Funds From Operations and Earnings

Funds from operations increased to $39.0 million ($0.72 per diluted equity share) for the three months ending June 30 from $26.5 million ($0.55 per diluted equity share) for the comparable period in 2005. On a per share basis, funds from operations increased by 31% due to stronger operating results partially offset by weaker gas prices. After tax earnings improved by 154% for the second quarter of 2006 when compared to the same period in 2005 to $21.7 million from $8.5 million. On a per share basis, diluted earnings increased to $0.40 from $0.18, an 122% improvement. On a pretax basis, second quarter 2006 earnings of $12 million was down slightly from the same quarter in 2005 ($13.7 million) primarily due to weaker natural gas prices and higher depletion rates partially offset by stronger production volumes.

Liquidity and Capital Resources

The Corporation invested $96.0 million in the second quarter of 2006 compared to $84.5 million in the second quarter of 2005.

The Corporation drilled 13 gross wells (9.44 net) of which 6 are Deep Basin, 3 are Sunset/Groundbirch and 4 are in other areas. In excess of 20 wells drilled the first quarter were completed during the second quarter. Approximately $16.3 million was invested at crown land sales in N.E-B.C. and the Alberta Deep Basin to purchase 32,000 net undeveloped acres.

For the six months ending June 30, 2006, the Corporation has invested $254.6 million compared to $173.2 million for the comparable period in 2005. The first half of 2006 is characterized by higher levels of drilling and facility construction activities.

On May 13, 2006, the Corporation completed an equity financing issuing 1,000,000 common shares at $56 per share for gross proceeds of $56 million. The proceeds of the financing were dedicated to previously planned exploration drilling delineated within Duvernay's $400 million capital budget.

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 mm were derived from a non-core Peace River High producing asset (80 boe/d).

In May 2006, Duvernay completed a new syndicated bank facility with a group of Canadian banks. The new facility has borrowing capacity of $300 million, up from $250 million in place at March 31, 2006. In addition the Corporation has established a $25 million operating line. The new facility has been established on terms similar to those previously in place.

As at June, 2006, the Corporation had 52,307,274 shares outstanding and 4,312,318 stock options outstanding. As at August 8, 2006, the Corporation has 52,517,607 shares outstanding and 4,221,985 stock options outstanding. During the period from June 30, 2006 until August 8, 2006, 210,333 common shares were issued on the conversion of employee stock options and 120,000 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 production.

Duvernay has entered into all hedging transactions with the same party that the commodity is physically sold to, avoiding the need to provide credit in the event that the hedges are at prices below prevailing prices. The most significant risk with the commodity hedges is that the prevailing product prices are higher than those committed to in the hedging contract. The Corporation partially mitigates this risk by including collars in its hedging portfolio. A less significant risk relates to the Corporation's ability to supply the production at future dates. This risk is managed by keeping the percentage of total budgeted production below 25% and by entering into the hedging contracts at multiple delivery points.

During the second quarter or 2006, the Corporation's Petroleum and Natural gas sales of $61.2 million included realized hedging gains of $4.1 million. At June 30, 2006 Duvernay assessed the prevailing market value of similar contracts to those that were unsettled at June and has estimated net proceeds from settling these instruments to be approximately $5.6 million. Financial Statement note 6 "Commodity Price Risk Management" provides further details.