Q3 2005 EnCana Corporation Earnings ConferencBODY:
OPERATOR: Good day, ladies and gentlemen, and thank you for standing by. Welcome to the EnCana Corporation's third quarter 2005 financial and operating results conference call. I would like to turn the conference over to Mr. Gwyn Morgan, President and Chief Executive Officer of EnCana. Please go ahead, Mr. Morgan.
GWYN MORGAN, PRESIDENT & CEO, ENCANA CORPORATION: Thank you, operator and hello, everyone. Today marks my 48th time in which I have over seen as a Chief Executive Officer a results report. And so I've determined that since I have been practicing 48 times, I don't need to do it any more, and the next time you hear the Chairman of the EnCana results report will be Randy Eresman who was just appointed -- has been designated as Chief Executive Officer at the end of the year. Our news release was sent out this morning and posted on www.encana.com and this conference call is also being audio webcast on our website.
First I must refer you to the advisory and future oriented information contained in the news release, and I also want to remind everyone that EnCana reports its financial results in U.S. dollars and its operating results in U.S. protocols, which means, of course, the production volumes and reserve amounts on an after-royalties basis. Accordingly, any reference to dollars, reserves or production information in the call will be in U.S. dollars and U.S. protocols, unless we say otherwise.
I'm going to start with an overview of our results and then turn the call over to John Watson, our Chief Financial Officer, who will discuss our financial performance and then Randy Eresman, Chief Operating Officer, will provide the operations reports. Our leadership team will then be available for questions. Driven by strong commodity prices in year-over-year pretax growth, EnCana's third quarter cash flow was over $1.9 billion or 220 per share an increase of 51% on a per share diluted basis compared with, of course, the third quarter of four.
Driven by strong commodity prices and year-over-year production growth, EnCana's consolidated third quarter cash flow was over 1.9 billion or 220 per share, an increase of 51% on a per share diluted basis compared with, of course, the third quarter of 2004. Total operating earnings for the quarter were 704 million, an increase of 33% on a diluted basis to $0.80 per share. Another strong quarter. Total cash flow for the nine months was over 4.9 billion or 550 per share diluted, an increase of 47%. Total nine months operating earnings per share increased 47% to 220 per share diluted or 1.97 billion compared with the same period in 2004.
In the news release, we provided details for both total and continuing operations, but we going to focus on our future, which means we will be focusing our discussion today on continuing operations, which excludes Ecuador and, of course, for 2004 also excludes the UK. All of our sales from continuing operations are located in North America, in fact on-shore North America, where our resource plays are the driver for growth and value creation for shareholders. For those of you wanting more information on our discontinued operations, you can find it in the news release. We generated third quarter cash flow from continuing operations of 1.82 billion, up 45%. Operating earnings from continuing operations, which exclude unrealized mark-to-market gains and losses, were up 32% from the third quarter of last year to 731 million. Cash flow from continuing operations for the first nine months was 4.64 billion, an increase of 46%. Operating earnings from continuing operations for the same nine month period increased 36% to 1.87 billion.
On the divestiture front, in the third quarter we announced the sale of our Ecuador assets for about 1.42 billion. We continue to work with the purchaser and the government of Ecuador and targeting to close the sale prior to year end, if possible. This sale represents an important milestone for EnCana. Once the sale is concluded, we will have completed our major international divestitures. EnCana becomes focused essentially on North American unconventional natural gas and in-situ oilsands, where we hold clear asset and core competency competitive advantages. Further, we expect to make an announcement soon regarding the sale of our mid-stream natural gas liquids processing business, targeted to close before year end, bringing total expected proceeds from our divestitures for the year to over $4 billion. Work also continues on the sale of the valuable national gas storage business, and we expect to conclude the sale early next year.
Other milestones in the quarter include a promising oil discovery offshore Brazil, the start on the Entrega natural gas pipeline out of the Piceance basin in the U.S. Rockies, and EnCana's support for the development of the proposed Rockies express pipeline to really bring the gas from the Rockies into the northeast United States. An arrangement to impor -- we also entered into an arrangement to import diluent from overseas markets to support our growing oilsands production, and a basin entry land purchase in the Maverick Basin in Texas.
I'll now call and John Watson, CFO, who's going to be followed by Randy Eresman.
JOHN WATSON, CFO, ENCANA CORPORATION: Thank you, Gwyn, and good morning. As Gwyn stated, EnCana's third quarter cash flow and operating earnings were very strong. The balance sheet is healthy and expected to further improve, upon receipt of divestiture proceeds currently estimated to be in the range of $2.5 to $3.5 billion. There were two noteworthy items new to the quarter financials that impacted both operating and net earnings, as well as a third item I specifically want to bring to your attention.
First, operating earnings from continuing operations of $731 million and net earnings from continuing operations of $266 million for the third quarter, both include the impact of a $79 million after-tax charge or $0.09 a share, to retire approximately Canadian 1.1 billion of high-cost debt. On September 21, we completed a Canadian $500 million median-term note issue, and effectively refinanced a portion of the higher cost debt at a coupon rate of 3.6% for a three-year term. For the $500 million Canadian alone there is an estimated annual interest expense saving of $13 million this new issue and, therefore, this new issue not only has a beneficial impact on our cost of borrowing, but in addition, our debt covenants have been updated.
Second, on September 13, 2005, EnCana announced that it reached an agreement to sell all of its interests in Ecuador for approximately $1.42 billion, which is approximately equivalent to net book value of the assets at July 1, 2005, the effective date of the transaction. In accordance with generally accepted accounting principles for discontinued operations, the carrying value of EnCana's investments in Ecuador cannot exceed the expected selling price. Therefore, no net earnings from these assets will be shown subsequent to July 1, 2005. If a provision related to this had not been recorded in the third quarter, net earnings for Ecuador would have been approximately $123 million or $0.14 per share diluted, which would have been reported in discontinued operations.
Looking at net earnings price volatility continues to have an impact on financial reporting for our price risk management program. On June 30, 2005, the forward price curve for the last quarter of '05 was $59.13 per barrel for WTI and $7.71 for Mcf or NYMEX gas. On September 30, 2005, the forward curve for WTI had increased by 12% to an average price of $66.40 per barrel, while NYMEX gas prices increased 83% to average $14.09 per Mcf. On a realized basis, the impact of our overall hedging position on EnCana's continuing operations in the third quarter was an after-tax loss of 135 million. This includes a $47 million net loss on oil and other hedges and an $88 million net loss on natural gas. This brings me to the third item, which I wanted to bring to your attention.
As we discussed previously, the unrealized hedging gains and losses in the quarter result from the changes to forward prices and expiry of contracts during the period. As contracts expire, losses become realized and reduce revenue and operating earnings. During the quarter this combination had resulted in a realized net after-tax loss of 135 million or $0.15 per share diluted. On an unrealized basis. these changes result in a net $631 million of unrealized after-tax loss, against net earnings from continuing operations for the quarters. So from an accounting perspective, the realized losses are recognized in our revenue line and, therefore, become part of operating earnings, whereas the unrealized are excluded from operating earnings. The after-tax foreign exchange gain on Canadian issued U.S. dollar debt for the quarter was $166 million. These noncash gains and losses, combined with our strong operating earnings from continuing operations of $731 million resulted in net earnings for the quarter of $266 million or $0.30 per share diluted.
The majority of our unrealized mark-to-mark loss results from gas swaps relating to the purchase of Tom Brown, Inc. in May of 2004. This hedging of the acquired production was done to help assure the financial return on the acquisition capital of 2.7 billion, and provide a pay back of about 4.5 years. Since that time, our risk management approach has focused primarily on instruments which provide a floor price but not a ceiling. Currently about 26% of EnCana's 2005 forecast natural gas sales are hedged at approximately $6.68 per Mcf, including the Tom Brown, Inc. acquisition-related volumes of 360 million cubic feet a day.
The remaining 74% of our 2005 forecast natural gas sales and practically all of our 2005 natural -- 2005 forecast oil sales are exposed to price upsides. For 2006, fixed price hedges averaging $5.73 per Mcf, are in place for approximately 20% of our forecast 2006 gas sales, which include the last of the Tom Brown fixed price hedges for 443 cubic feet a day. Oil price swaps are in place for only about 10% of our 2006 forecast oil sales, at an average price of $34.56 per barrel. Beyond 2006, as indicated in note 12 of the financials, fixed price contracts are in place for 240 million a day of gas sales at $7.76 per Mcf. During the quarter ,approximately 11 million shares were purchased under our normal course issue or bid at an average price of approximately $42.86 per share, for a total of approximately $452 million, while approximately four million shares issued in the quarter, as a result of the exercise of stock options. In total, we purchased approximately 84 million shares or 91% of the shares eligible on our just expiring 10% normal course issue or bid for a total of $2.7 billion.
The board has approved renewal of the normal course issue or bid for up to 10% of the public float. We plan to consider further share purchases, along with debt repayment, when we begin to receive the anticipated proceeds of our announced divestitures. We continue to believe that buying back our shares and investing in the underlying value related to our unbooked resource potential is an effective way of building long-term net asset value per share. During the third quarter, net debt increased by approximately $1.6 billion. Net debt to capitalization at the end of the quarter was 40% and net debt to EBITDA was 1.6 times on a 12-month trailing basis. The increase in net debt to capitalization from the second quarter is largely the result of the recording of unrealized losses associated with mark-to-market accounting and the associated impact on working capital.
At September 30th, the impact of mark-to-market increased our net debt to capitalization ratio by 6%, or excluding mark-to-market ,our net debt to cap ratio would have just been just 34%. It is expected that the Ecuador and NGL sales proceeds will be used to bring down debt levels and purchase common shares under the renewed normal course issue or bid. And assuming these two divestitures are closed by year-end, we expect our net debt to cap to fall to the lower half of our 30-40% target range by year end. Cash taxes from continuing operations for the third quarter were $169 million. And cash tax expense from continuing operations, excluding tax on dispositions for the nine months ended September 30th, 2005, was $446 million, and as a percentage of pretax cash flow from continuing operations was approximately 9%, which is slightly below our current guidance range for 2005 of 10 to 15%.
As we stated last quarter, much of this percentage decrease for forecast is due to the deferral of cash tax from 2005 into 2006. Stronger commodity prices have increased our 2005 cash flow, the denominator, while a corresponding -- without a corresponding increase in our 2005 cash taxes denominator -- that is, numerator. As a result, for 2006, the timing differences I just mentioned, along with continuing high commodity prices means that our 2006 cash tax guidance range has increased to between 17 and 23% of pretax cash flow from continuing operations, excluding divestitures.
Looking at foreign exchange, in the third quarter the U.S. dollar continued to weaken relative to the Canadian dollar. The exchange rate averaged $0.83 through the quarter compared with $0.80 for the second quarter and $0.77 for the third quarter of last year. This continues to have a negative impact on the translation of our Canadian dollar expenditures into reported U.S. dollars. For example, Canadian $100 of expenses in each of the three quarters I mentioned gets reported differently, i.e., as $77 in Q3 of 2004, then as $80 in Q2 of 2005, and then as $83 in Q3 of 2005. That's an 8% increase in the reported costs, when our actual Canadian dollar outlay remains unchanged.
The weakening U.S. currency increased the U.S. dollar reported costs for our Canadian operations by about $0.05 per Mcfe in operating and administrative expenses and by $0.10 per Mcfe for DD&A expense. As shown in our 2006 guidance document, a $0.01 increase in the U.S. dollar relative to the Canadian dollar exchange rate has a positive $10 million impact on net earnings and a negative $40 million impact on cash flow. Our upstream DD&A rate was $1.69 per Mcfe for the quarter and year-to-date, the DD&A expense is $1.72 per mcfe and it is expected to remain within the guidance range of $1.70 to $1.80 per Mcfe for the 2005 year.
I will now turn the call over to Randy Eresman, who will report on operations.
RANDY ERESMAN,, COO & EVP, ENCANA CORPORATION: Thank you, John. I'd like to start today with the discussion on how the challenges we faced this year have impacted our 2005 guidance, and then I'll address the operation results for the quarter. I'll talk about the highlights of our gas and oil programs, and then move into an overview on our outlook and guidance for 2006. I'll also share some brief thoughts about my succession to CEO.
Today we released our updated guidance for 2005 and forecast guidance for 2006 for total sales, core capital and operating costs. The update guidance document is now posted on our website. For 2005, we're now forecasting a 9% to 11% natural gas sales growth, and 5% to 7% total North American gas equivalent sales growth over 2004. Up-stream capital is now projected to be in the range of $5.4 to $5.6 billion, and our operating costs average in the range of $0.64 to $0.66 per Mcf equivalent. Capital increase over recent guidance was approved to capture key land positions in emerging resource place, on-shore North America. The increase in operating costs is due to inflation, a weaker U.S. dollar, higher energy costs and higher long-term compensation expenses, and that's coupled with our lower-than-forecasted sales volume. That being said, we expect to remain competitive with the rest of the industry.
2005 will be marked as one of the most challenging years on record with regards to program execution for our entire industry. Record activity levels and bad weather have combined to create a stretched service sector, high inflation and significant delays and inefficiency in execution. I stated during the second quarter conference call that, with the return to normal weather, we anticipated we could catch up on our drilling activity by year-end. The poor weather continued during the summer in some of our key area. For example, we experienced highly unusual summer road bands in some of our southern Alberta operations, due to heavy rainfall and a record 36 inches of rain this year in the west central Alberta area. And the tightness of available resources in the service sector prevented us from ramping up our activity when weather conditions permitted.
At the nine month mark we have now drilled fewer wells than planned and currently have about 225 million cubic feet per day of gas shut in behind pipe. With normal weather, we may be able to getting drilling programs completed by year-end; however, we will not be able to get all our wells completed and tied in. Although we still expect strong annualized North American gas production growth, our revised production range reflects about a two-month mid-year delay in our activity. Should weather be favorable for the remainder of the year, we now expect to exit 2005 in the range of 3.4 to 3.5 Bcf per day of gas production.
Despite the obvious concern that a production shortfall creates, we have never been more confident in our long-life production and reservoir performance of our key gas resource plays. Even after these delays, third quarter production from these legacy and emerging gas assets is up 3% from the second quarter, and up 14% from the third quarter last year. Results from the wells drilled are hitting expectations, our success rates and type curves are standing up, confirming our view that the geological risk of these key gas resource plays remains relatively low and their performance predictable. A long-life in each of these plays affords the opportunity to continually incorporate learnings in our current and future capital plans.
For the third quarter, EnCana's natural gas sales from continuing operations rose 4% to 3.22 billion cubic feet per day, compared to the third quarter of 2004. Liquid sales from continuing operations averaged 150,500 barrels per day, 11% lower than the same quarter of last year. On a gas equivalency basis, sales from Canadian operations were 4.13 billion cubic feet equivalent per day, slightly higher than third quarter last year. Daily sales have been impacted by net divestitures of 40 million cubic feet of natural gas and 14,200 barrels of oil and liquids per day. Upstream core capital spending from continuing operations was $1.39 billion in the quarter, and we drilled 1,150 wells.
Up-stream unit operating costs averaged $0.69 per Mcfe, up 30 cents -- sorry, up 30%, compared to the third quarter of 2004. This large increase in operating costs over 2004 is due to several factors, including: The weaker U.S. dollar, that accounted for $0.04; Higher long-term compensation expenses, that accounted for $0.05 and that was directly related to EnCana's rising share price; And a combination of increased industry activity, higher energy input costs, and delayed production. Overall capital and operating costs has increased, as a result of higher service sector pricing, higher energy input costs and the weaker U.S. dollar.
Now, on to our natural gas highlights. In our USA region, which is comprised almost entirely of natural gas resource plays, continues to deliver strong growth and value creation for EnCana. Gas sales in the averaged just shy of 1.1 billion cubic feet per day. That's up 15% over the same quarter last year. Sales up 4% from the second quarter, despite experiencing some delays, due to pipeline access, regulatory approvals, and rig availability. Jonah and Piceance key resource plays continue to be the primary growth drivers in the U.S. , with gas sales averaging 440 million cubic feet per day and 302 cubic feet per day respectively in the quarter. On a combined basis, this is an increase of about 13% from the same quarter in 2004.
We continue to expect the decision on our development plans from the Bureau of Land management later this year, or early into 2006. As well, we've got compression constraints, which are who holding back some of the Jonah production and these new facilities expected to come on-stream in the next few months and will help alleviate the backup supply. In the Piceance Basin, we shifted the focus of our drilling program this year further to the north, closer to our Eureka and Parachute holdings, to balance activity levels in this important region to us. In these new area, the emphasis is now on pad drilling, with some locations having --- containing as many as 16 wells per site, and the lack of developed infrastructure in the area is having impact in our ability to bring on production as quickly as we have in the past. Production's currently 30 million cubic feet per day behind our 2004 annual forecast; however, we expect to see a boost in production during the fourth quarter, as our field development progresses.
During the second quarter, we told you about a new rig deal in support of our foothills region resource plays. We've also recently completed a similar arrangement in the U.S. to support our Piceance development plans. U.S. agreements involving four service providers will see the addition of 15 new fit-for-purpose rigs, using the latest drilling technology. The first of these rigs is expected to be available for our use starting in November of this year, with additional ones coming on throughout all of 2006. The arrangements will be in place for a period of one to three years, giving more certainty with costs and availability of rigs built specifically for use in our Piceance operations. Rising dayrates for rigs and increased lack of rig availability has slowed our pace of development in the past in Piceance, and we expect that these new deals will assist us in managing both the costs and drilling activity levels, going forward.
In Canada, gas sales in the third quarter averaged over 2.1 billion cubic feet per day, down just under 1% from the same period in 2004, principally as a result of net core dispositions of 61 million cubic feet per day or 3% of Canadian natural gas. Our gas production and drilling activity in Canada during the third quarter was adversely impacted by the wet weather we experienced throughout the summer, particularly in Alberta. At Cutbank Ridge in northeast British Columbia, third quarter of 2005 production averaged 105 million cubic feet per day, up 31% from the second quarter of 2005, and 133% higher than the third quarter of 2004. We continue to see strong production growth in well performance, especially from the renewed application of dual-leg horizontal wells.
Our Greater Sierra production in the quarter averaged 225 million cubic feet per day, essentially flat from the second quarter of 2005 and down 8% from the third quarter in 2004.
As we -- as we indicated in the second quarter, this is due to our load leveling strategy that was implemented in 2005. This strategy balances the drilling throughout the year, removing the stress of drilling the majority of our wells in the first quarter, resulting in incremental production spread throughout the year. Our matt drilling techniques are key to allowing low-leveling activity to occur, which we believe has tremendous benefits to all stakeholders. The consequence, however, of implementing this cost-saving strategy is that growth is impaired during the year of implementation.
On the exploration front, we recently made a natural gas discovery in British Columbia below our Cutbank Ridge Condomin resource play, which contains an estimated 350 to 550 billion cubic feet of original gas in place, net to EnCana. Production commenced from Doig formation in April of this year and production ramped up over the quarter to a current level of 25 million cubic feet per day from five wells. This production is included as part of the cut bank results. This is a great example of the exploration upside potential over our extensive resource play lands.
Coal bed methane production for the quarter averaged 62 million cubic feet per day, up 22% from the second quarter of 2005 and 226% compared to the third quarter of 2004. We continue to see strong coal bed methane production growth from our legacy Palliser block in Alberta and expect to exit the year approaching 90 million cubic feet per day. The Canadian plains region has negotiated new stimulation service contracts. Expect to benefit from a lower, more-stabilized pricing structure, improved availability of crews and equipment, and greater flexibility through coordination of crews between businesses.
Now, on to our oil programs. For the quarter, Foster Creek SAGD production averaged 27,000 barrels per day, an increase of 11% from the second quarter of 2005, due to the completion of our scheduled maintenance and prework required for the anticipated 30,000 barrel per day facility expansion. The first phase of that expansion is expected at 10,000 barrels per day and should be all online by year end. We're currently producing 32,000 barrels per day at Foster Creek. in line with our target to exit this year at approximately 40,000 barrels per day. We also recently sanctioned the commercialization of our Christina Lake oilsands project. This project currently producing 7,000 barrels per day is expected to undergo an expansion to bring its capacity to 18,000 barrels per day over the next two years. Christina Lake and Foster Creek represent two of the highest quality in-situ oilsands projects in the industry.
As one of the many oilsands integration initiatives we're pursuing, we recently announced our deal with Methanex, which enables us to bring in diluent from offshore. The current plan for up to up to 25,000 barrels per day of offshore supply of diluent, along with our current internal supply of approximately 8,000 barrels per day and a small additional spot purchases, will support our total oilsands production through the end of 2006. In Brazil, we successfully drilled and tested an appraisal well in Block BMC7 at 1,800 barrels today of 14-degree API crude oil. We will be providing a much more complete review of all of our key resource plays at our investor day in Calgary, which we are hosting on November 7th, and in New York and November 9th.
Over the next couple of months I'll be preparing for my new assignment as CEO and work with EnCana's leadership team on an effective execution of our North American resource play stage. What I can tell you today is that EnCana's primary goal remains unchanged. We will continue our pursuit, growing net asset value per share. We will remain focused on creating long-term value from our portfolio of unconventional resources. And EnCana will continue its pursuit of industry leadership in all aspects of resource play capture and development. There will be clear continuity in our strategic direction and a strong commitment to long-term value creation.
Now, moving forward to next year's budget. One of the attributes of our resource play production growth that I've stated in the past is that we can just dial it in. Meaning that the well performance and the underlying decline are so predictable that we can have a great deal of comfort in our forecast. The fundmental assumption, however, is that we get the job done and we get it done on schedule. Based on the unprecedented conditions we faced in 2005, we were unable to fully execute in accordance with our plans. So for 2006, we're going to adjust the dial to a level that reflects the learnings from 2005, along with the execution constraints we see going forward.
For 2006, we're now forecasting a 7% to 11% gas production growth and a 5% to 9% percent overall North American gas equivalent growth over our 2005 forecast mid-point. Our upstream core capital forecast of $6.2 to $6.5 billion includes about $3 billion to keep our North American production flat, approximately $2.1 billion is slated to deliver our forecasted growth, and we have allocated about $500 million for oilsands production, and just over $100 million have been allocated to international activities. all related to longer-term growth. Other long lead-time growth capital of $600 million includes additional exploration investments across the North American regions. The capital forecast was built assuming a 12% cost inflation and a continued tightness of supply for goods and services. Operating costs are expected to increase by 12 to 18% over the 2005 forecast mid-point, primarily due to foreign exchange, higher service and fuel costs. Again all of these increases are a direct reflection of the robust commodity price we're experiencing.
We will be revisiting our estimate of our unbooked resource potential early in 2006. In view of the rising cost trends, I expect that our cost estimate to fully develop our unbooked resource potential to increase. That being said our current estimate of 24 trillion cubic feet equivalent of unbooked resource potential was estimated to be economically recoverable, using long-term prices of $5 NYMEX and $30 WTI, which are well, well below current commodity prices. In summary with high commodity prices and correspondingly high inflation and overall industry activity, we're confident that we're taking the right steps to manage the inflationary cost structures and adjusting our pace of development for successful execution. Our commodity prices have -- higher commodity prices have also resulted in expansion of our net backs and our overall returns. Our capital program is as strong, or stronger than ever. Longer term, we expect that our large inventory will sustain our business strategy and provide us with flexibility on how we execute in a given year.
Before passing the call back to Gwyn -- Gwyn Morgan, I'd like to acknowledge and thank Gwyn for strong leadership and mentorship. He's built a strong EnCana team, ready to continue delivering on a resource play strategy.
GWYN MORGAN: Well, Randy, thank you very much. I'm going go through with some closing remarks here, starting with a commodity outlook. The past few months have been, as you know, have seen tremendous volatility in commodity prices and the energy sector as a whole. And, of course, the hurricanes in the Gulf of Mexico has further strained an already tight North American supply market, only demonstrating further the point I've made before, that there's little room in the world oil markets and the North American natural gas market , in particular, to deal with normal demand variations and unforeseen political and natural events. This situation has fostered higher and more volatile energy prices, and these circumstances are expected to continue for the foreseeable future. We expect both oil and gas prices to continue to be volatile and strong.
While world oil prices impact natural gas prices to an extent, natural gas prices are primarily driven by North American supply and demand, with weather being the key determinant in the short-term. North American conventional gas supply has peaked over the past two years, and we believe that unconventional resource plays will be the only source capable of offsetting conventional gas declines. As the leading player in North American unconventional gas, EnCana's competitive position has never looked stronger. The industry's ability to respond to the gas supply constrain situation in North America remains challenged by land access and regulatory issues. With improvements to the access approval process and a smooth and more consistent regulatory environment, it would make it easier for industry to respond to needed demand. The down spacing approval process through the Bureau of Land Management regarding our Jonah project, and inconsistencies between the federal and provencial regulators, which impact our plans for Deep Panuke are just a couple of examples of how our own project plans are hampered or slowed in one form or another by unnecessary bureaucracy. Governments and regulators throughout North America need to realize the industry needs timely processes, if we are to provide badly needed supply.
In closing with the completed sale of our Ecuador asset, EnCana will have 100% of its production from on-shore North America. At a time be access to offshore resources becomes more and more difficult and risky, we are here at home in North America. EnCana has played a key role in helping investors understand North America is not running out of oil and gas, but it is running out of conventional oil and gas. The future is unconventional when it comes to North America, and EnCana is well positioned to continue to strong growth in shareholder value for a long time into the future. This team has built an asset base and a group of people which are second to none in unconventional gas and in-situ oilsands.
And speaking of this team I am reminded of a pearl of wisdom that an old friend once told me. Gwyn, it is not just what you build, it is what you leave. And I'm proud to say that I'm leaving EnCana in the hands of a young, energetic and very disciplined leadership team, who have built EnCana into what it is today, and whose ethical values are of the highest standards. Their leader, Randy Eresman, has been a key architect of EnCana and our North American resource play strategy. So EnCana, as a famous first officer from the universe once said, is well positioned to live long and prosper. We thank you for joining us. Our team is now ready to take questions from the investment community first, followed by the media.
OPERATOR: [OPERATOR INSTRUCTIONS] We'll take the first question from Greg Pardy with Scotia Capital.
GREG PARDY, ANALYST, SCOTIA CAPITAL: A couple of questions. Just on the joint venture of the proposed deal you had talked about before with Premcor, could you give us update on that? And secondly, with respect to the hedging program, given the proceeds that you've got coming in from Ecuador and the mid-stream and so forth, is there a need to hedge, given the strength of your balance sheet? Thanks.
GWYN MORGAN: I'm going to ask Bill Oliver to answer the first question, and I think I'll turn the second over to Randy Eresman.
BILL OLIVER, EVP & PRESIDENT, ENCANA MIDSTREAM & MARKETING, ENCANA CORPORATION: Greg, in terms of our discussions with Bolero, as you know the deal was just concluded. We've had initial discussions. We are spending time with them, educating them on the upstream business, so they've got a sense what it requires in some type of a commercial arrangement. They have also spent time looking at the technical and engineering merits of the project, and are in agreement with the studies that we finalized. I would say that we have to spend much more time with them to determine if there is a different commercial arrangement that might make sense for both of us to go forward. But, as you'd expect, they have been occupied with some other operating issues with their refineries in the Gulf Coast, so it is going to take us some time to determine if and what would make sense for EnCana and Bolero.
GREG PARDY: Thanks.
RANDY ERESMAN,: Okay. Greg, regarding whether or not we need to do hedging. On our balance sheet, we forecast it to be very strong considering the number of divestitures that we are undertaking this year, and the fact that we expect to have significant free cash flow generated in next year's -- in next year's program. We are -- our capital's far less than the cash flow. So, I would expect that there will be -- there's no need for us to do hedging and we would see this really as -- as we've expressed our program before, it is more of a downside protection, that we're more interested in this point. Commodity prices have certainly swung wildly in the positive direction and we know that they could swing the other way, as well. So, having some level of downside protection, we believe is prudent.
GWYN MORGAN: So, Greg, just to add to that, I might also mention that the vast majority of -- at least the majority current mark-to-market hedging losses are associated with the Tom Brown acquisition. It's interesting to think back only about a year and a half or a little more when we bought that company and everybody thought that, you know, we were paying quite a bit for it, and we actually justified it on the basis of the hedges at something like 580 or something like that. Next year -- at the end of next year, the Tom Brown -- so those -- those larger -- a large component of our hedged mark-to-market losses on our books will be completed by the end of next year, as the Tom Brown hedges expire. But the production from Tom Brown will continue to build and grow for a long, long time to come. We made that decision at the time, based upon a different balance sheet, and that's important to remember.
GREG PARDY: Okay. Thanks, Gwyn. Just in terms of the hedging program going forward then, is there more of a bias towards, you know, put offs and strategies as opposed to entering into swaps or even callers?
GWYN MORGAN: I think that is what Randy just said. The swaps will be -- I think you've swaps entered into when only -- when the price seems to be in the, what we might call, extreme situation, but most of what we put in place, the vast majority, has been swaps and we -- there's been put options and we have also a policy of not doing oil at al,l because we just put downside protection, in other words. No swaps on oil at all because, frankly, we can't match WTI and the nature of our production.
GREG PARDY: Okay. Thanks very much.
OPERATOR: The next question from Brian Dutton with UBS.
BRIAN DUTTON, ANALYST, UBS: In your guidance, and you certainly indicated across the board you're experiencing a higher cost environment, but also know that your guidance for DD&A expenses on a per unit charge for this year's relatively unchanged, or it's not changed at all. Are -- can we draw anything from that in terms of expectations for F&D costs for this year?
GWYN MORGAN: Randy?
RANDY ERESMAN,: No, I don't think you can draw anything except for -- the one thing we did say is that we will be sanctioning Christina Lake and you are pretty aware that Christina Lake has fairly large volumes of reserves associated, once we are able to start booking them, and they are fairly low cost. So that would have an overall decreasing impact on our overall F&D. Otherwise I would expect that our F&D would generally be going up in proportion to the inflationary inefficiency effects that we saw in the marketplace this last year and forecast into next year.
BRIAN DUTTON: Okay. Thank you.
OPERATOR: Bob Lions, CI Mutual Funds.
BOB LYONS, ANALYST, CI MUTUAL FUNDS: Hi, good afternoon. Two questions. One just on the Cutbank Doig discovery, can you talk to us a little bit. Looks like your production is still relatively low compared to the size of the resource. Can you talk a little bit more about the development plan's there?
OPERATOR: Mike Graham.
MIKE GRAHAM, PRESIDENT - CANADIAN FOOTHILLS & FRONTIER REGION, ENCANA CORPORATION: Yes, Mike Graham here with the Canadian Foothills, Bob. Like Randy said, we have five wells currently on production, doing about 25 million cubic feet per day. And we think we've got a discovery in the order of about 350 to 550 Bcf. We think it is very similar to the Sinclair Doig pool which EnCana operates and it's produced about 260 Bcf so far. It's still currently producing 50 million cubic feet per day after that, so it's probably in the order of some where in the size of the Sinclair Doig pool, so we think production should continue to ramp out. We have five wells on production. Eight wells drilled and more coming on throughout the year.
BOB LYONS: And with respect to future potential, I mean you have a pretty massive land position in that whole area. Can you talk a little bit about what you see is potential over the years, you know, additional discoveries perhaps, or what is your general feeling as to the likelihood of similar discoveries in a similar zone?
GWYN MORGAN: When we went to the sale in September of 2003, we bought all rights available, which included surface to basement for the most part. We continue to shoot a big 3D program out there. It is exploration but, you know, with, you know, the new 3D that we shoot, not only for the Condomin resource play, but for the Doig, you know if they are there we will find them.
BOB LYONS: And one other question, if I may, on a separate topic with regards to Brazil and activities there, it's one of the few area, really, outside of the onshore resource plays that you're spending money. Can you talk about how much is in the '06 budget for further activity in Brazil and what your longer term plans might be for that property?
GWYN MORGAN: John Brannan
JOHN BRANNAN, MANAGING DIRECTOR, FRONTIER AND INTERNATIONAL NEW VENTURES, ENCANA CORPORATION: Yes, for our 2006 budget in Brazil is about $20 million and that is primarily to drill a follow-up to the appraisals that we have had at BMC7 and also some deep water exploration in conjunction with Petrobras or McGee, and Evan.
BOB LYONS: Thanks. And longer term as that develops into potentially an operating property, is that something you guys would be inclined to hang on to or general thoughts on that?
JOHN BRANNAN: We are currently working in conjunction with our partner, Kerr McGee, on the BMC7 appraisals and discoveries we've had there. We are putting together a joint team to work on development plans and we'll see where that goes from here.
GWYN MORGAN: Generally, though, we have looked at all of our international exploration as option value exploration, so we are looking only at going into areas where we think we can take our unique competencies or we have specific strategic advantage and looking at creating value. It was not a longer term intent to be an operator of production.
BOB LYONS: Great. Thanks very much.
OPERATOR: Our next question comes from Ben Del with Sanford Bernstein.
BEN DELL, ANALYST, SANFORD BERNSTEIN: Hi. Thank you very much. I have a couple of questions. The first is on your capital budget. It implies that next year you'll sort of need around $7.75, $8.00 gas to be able to fund it from operating cash flow, ex-divestments]. Is that the sort of number you come to when you're looking at ways to pull back capital spending next year?
And my second question's really around return on capital employed. You highlighted that that should be improving given your investment on unconventional play, but I was wondering if you could talk through your capital employed, which seems to be growing about 13% and topline, as far as I can see, is growing about 5 to 9%.
RANDY ERESMAN,: Your first question was -- just trying to get a hold of the -- Ben, could you just come again at your first question? I just --
BEN DELL: Yes. I guess my first question is, through the first nine months of the year, we've had around a $7 natural gas price and, as far as I can see, your operating cash flow just about covers your capital expenditures, ex-divestments and acquisitions. And looking forward to next year with your Cap Ex on the upper end of the range, possibly hitting $7 billion, it appears you will need a $7.75, $8 gas price to be able to fund that Cap Ex out of operating cash flow. Is that about right or -- And if so, would you look at cutting back Cap Ex?
GWYN MORGAN: One of the things where I was a little bit cautious about is we don't give cash flow estimates, but I guess I'm going to ask Randy to fill further in on this. But one of the things that I can say is that, you know, based upon consensus right now, with this budget EnCana would generate an extra billion dollars of free cash flow above our capital budget, so we have a fair bit of room there. But, Randy, I don't know if you want to any more than that?
RANDY ERESMAN,: Yes. The math that he mentioned may go around. I -- we specifically haven't made that calculation and -- it sounds about right, but --
BEN DELL: Okay. And I guess my second question was just around the return on capital employed. When we should expect to see that picking up and sort of the unconv -- the investment in the unconventional play sort of playing out?
JOHN WATSON: It's John Watson here,Ben. I think that, as you can see, the ROCE is improving, as we see continued increase in prices. Whether our topline is going up at the five to nine or some other percentage, the future will predict that. And with the buyback stock with the excess cash that we do have and reduce our capital base, we think that the numbers now in that mid to high-teens number and should continue to grow going forward.
BEN DELL: Okay. And maybe if I could just clarify one point I think Gwyn made just on the F&D. You indicated that it would be up. Judging by my estimates, I admit, for reserve replacement rate this year of around 108%, that would imply, sort of , to [indiscernible] F&D number. Is that the right ballpark or do you have a feeling so far, given that you're nine months into the year?
GWYN MORGAN: We do our, you know, our reserve calculations at year-end, and we have external evaluators work completely through the process. You know, things that are going to impact EnCana specifically, are the inflation that we've been exposed to. The degree that we've been able to bring on our production this year is going to be factored into how our external evaluators look at and have enough information to assess the activity that we've conducted this year.
If all things were equal, and they're not, but if they were equal, we would expect that our resource play strategy -- we're finding reserves pool or pools of reserves that are not necessarily larger nor necessary any smaller than we have historically. So it really is just the price inflation and over the coarse of the last year, we've talked about some were in the 15% range on average and our costs have gone up from '04 to '05, and we have also seen some inefficiencies in the business, which will drive it up maybe another five or so points, so it could be, easily, 20% higher.
We would expect that if you compared that to what's happening in the rest of the industry and if they were in the resource play business, they would be exposed to, likely, in the 30% range, simply because we're able to contain costs a lot better than others. Now, if they're conventional exploration world, they're likely finding pools that are smaller on a decreasing scale, so you would expect that the rate of growth of F&D costs for them will be higher.
Having said all that I think the last year was $1.40 -- about $1.40 was last year ,so you can apply some of the factors Randy's talked about to that and I think you'll find that you'll come out a little less than what you have estimated.
BEN DELL: Okay. Great. Thank you very much for your time.
OPERATOR: Our next question from Brian Singer with Goldman Sachs.
BRIAN SINGER, ANALYST, GOLDMAN SACHS: Up a little bit on the last question. Are there any regional drivers of the extent of cost inflation we are seeing more in Canada versus the U.S. in coal bed methane versus the Piceance basin, et cetera? And within a context of your capital budget going up, how much do you expect to spend on rigs next year versus this year?
GWYN MORGAN: Okay, I'll answer the last part first because we've -- our contemplation on rig dayrates is about 13%, year-over-year. Regionally, we were fairly stressed in 2005 in the general Rockies area with Piceance Basin, and that's specifically why we've gone after getting built-for-purpose rigs. And it's also -- getting the built-for-purpose rigs also gets us the latest technology and allows us to generally save a lot of time on the drilling side of it. In Rockies or our the U.S. operations, in general, in 2005 we saw cost inflation of between 15 and 20% versus our 12 to 15% range that we saw in Canada. I think a lot of that was really just U.S -- a lot of industries in the U.S. really being caught up with the impact of the decrease in U.S. dollar and its purchasing power. As far as competition for services in western Canada right now, we had a really wet summer in southern Alberta, so that's made it very challenging to be able to get the activity whenever the weather permitted for us to get in. So, that's been a challenging area for us, and that's southern Alberta generally, and includes our coal bed methane program.
BRIAN SINGER: On the rig side, how much do you plan to spend on rig purchase next year versus this year?
GWYN MORGAN: We haven't purchased any rigs. We are simply entering into contracts. In Canada, they range from three to five-years and in the U.S., they're typically one to three-year contracts.
BRIAN SINGER: Lastly, operationally, could you talk about five-acre spacing at Jonah, any rates that you could share, and do you plan to proof reserves there?
GWYN MORGAN: I'm sorry, could you rephrase the question?
BRIAN SINGER: On the five acre pilot to Jonah, could you talk about any success you are seeing and whether or not you plan to increase proof reserves, as a result?
GWYN MORGAN: Oh, no, there won't be a significant move on changing reserves based on the five-acre spacing. We have had good success, though, on them, where we see a lot of virgin sands and a lot of virgin pressure and good production rates, so it'd be good incremental reserve recovery associated with them. But we'er going to have to wait until the actual approval is in place to go for the downspacing and, you know, that could quite easily slip beyond year-end.
BRIAN SINGER: Great, thank you.
OPERATOR: [OPERATOR INSTRUCTIONS] We will go to Bob Morris with Banc of America Securities.
BOB MORRIS, ANALYST, BANC OF AMERICA SERCURITIES: Good afternoon. I had a question on the economics of the Cutbank Doig. What sort of well costs are you looking at completion wise and, ultimately, what sort of funding development costs you're looking at in that play, given that discovery?
MIKE GRAHAM: Hi, Bob. Mike Graham here again.
BOB MORRIS: Hi, Mike.
MIKE GRAHAM: The Cutbank Doig is actually a little bit deeper than the Condomin, so well costs are obviously a little bit higher. We are about 3,500 meters in the Doig, compared to about 2,500 in the Condomin. Needless to say, our F&D and economics there will be very, very robust. If you compared to the Sinclair Doig, on average you recovered about 5bcf per well, is what Sinclair Doig has done. And we expect to see all that or probably a little bit more out of that so -- out of the Cutbank Doig, so needless to say, our economics are very, very robust there.
BOB MORRIS: What is the well cost on these?
MIKE GRAHAM: Well cost is going be a little bit higher than, like I said, the Condomin were both 3500-meters. I'd have to hazard a guess probably, in the order both, $4 million. Some where in that order and probably recover 5bcf ,plus per well.
BOB MORRIS: Okay. And any update on the drilling? I think you had six wells you were going to drill in Culverson County in Texas, in a shale play there?
RANDY ERESMAN,: No, we don't have -- we're not providing an update on that today.
BOB MORRIS: That's fine. Thanks.
OPERATOR: Our next question comes from John Herrlin with Merrill Lynch.
JOHN HERRLIN, ANALYST, MERRILL LYNCH: Thank you. A couple of quick ones here. Last quarter you said you would contract for 27 rigs, and this quarter you are saying now 46. Randy, you mentioned 15 incremental in the U.S. Are the rest in Canada? And following on that, how long do you think it will take to get the crews efficient and how much will these contracted rig crews represent for your average rig crews that you have planned to use next year?
RANDY ERESMAN,: Okay. I'm still hung up on the math here is. We have the 27 rig deals we did in Canada. We've got 15 in the U.S. That's all the long-term contracts we have in place so far. We have been working on additional rig deals in the U.S.
JOHN HERRLIN: Okay.
RANDY ERESMAN,: And I just put the numbers in front of me.
JOHN HERRLIN: That is 42. You're missing 4.
RANDY ERESMAN,: Okay, there's 19 in the U.S.
JOHN HERRLIN: Okay. That explains that. How many rigs were you planning to run then next year, Randy?
RANDY ERESMAN,: I believe on average we run, during the year, about 100 rigs. We peak at 140 or so in the winter, and about 80 or so, 80-90 during the summer months. So our thinking on this is we likely wouldn't want to get more than about half of our rigs under long-term contracts. Being that if there were to be a turndown, we would always be running at at least at 50%.
JOHN HERRLIN: Okay. You highlighted in Cutbank the volume growth. How much was this new discovery in terms of the change over the second quarter versus other Cutbank activity?
MIKE GRAHAM: Yes, John. Mike Graham here again. Out at the Cutbank Doig we had about 11 million cubic feet a day, out of the Doig, and the rest is, essentially, all coming the Condomin or above the Doig, if you will.
RANDY ERESMAN,: And the change in the quarter, Bill? Probably about half of that.
BILL OLIVER: Pardon me?
RANDY ERESMAN,: The change --
JOHN HERRLIN: Yes, that's fine.
RANDY ERESMAN,: Good enough? Okay.
JOHN HERRLIN: And then the last one for me, what about frack jobs?. Having any trouble lining up that side of the business.
GWYN MORGAN: I'll actually have Jeff Wojahn answer that. He fracks more wells than anybody else in the world. [LAUGHTER]
JEFF WOJAHN, EVP & PRESIDENT, CANADIAN PLAINS REGION, ENCANA CORPORATION: Hi, John, it's Jeff Wojahn calling. One of the challenges this year, obviously, in southern Alberta in our coalbed methane program has been timely availability of weather crews. We had a tremendous amount of rain, as Randy's talked about, and so having the capability of running when it is dry has been a challenge. We have been working on completion deals, primarily, in regards to new fit-for-technology around nitrogen pumping required for [indiscernible] coalbed methane. And we made great strides in that regards. We have level-loaded our program, based on average weather, not P5 weather like what I call it this year, but by and large, we are doing well on procurement on completions.
JOHN HERRLIN: Okay. Randy, are you going stay on as COO or is there going to be somebody else anointed?
RANDY ERESMAN,: We haven't made any of those decisions yet. I'll wait until a new year.
JOHN HERRLIN: Okay. Thank you.
OPERATOR: Our next question comes from Ted Isaac with Bear Stearns.
TED ISAAC, ANALYST, BEAR STEARNS: Hi, good afternoon, everybody. Congratulations, Gwyn, on a great run there.
GWYN MORGAN: Thank you very much.
TED ISAAC: My question really is more strategickic in nature. Going forward, do you see yourselves doing any strategic actions? You've said you're are not going to get bought by Shell, but might you buy somebody, I guess, or what is your M&A strategy going to be like?
And then, second is in terms of your credit metrics, you know, they've deteriorated a little bit here. What are sort of your guidelines, you know, what are your targets in terms of debt to EBITDA, coverage ratios, debt to capital, things like that going forward? And answer that in light of your stock buyback program, and how much you might do and not do and how rapidly?
GWYN MORGAN: I'll have John Watson have the second part, and I'll take the first question. Randy may want to add to it. If you look at how EnCana's -- how EnCana has evolved. As you know, we've done some acquisitions, most notably in North America recently, Tom Brown and some other tuck-ins, and we've certainly sold a lot of the assets. And as we move into 200,6 our international, you know, assuming we're able to close Ecuador, we will have completed that international disposition program and we don't expect to see very many other dispositions next year in the upstream. Continue to have some mid-stream, especially our gas storage dispositions, in 2006. That'll be by far the most significant.
Beyond that I would think that, you know, the team will be seeing what is called the small tuck-in resource play type opportunities, like Maverick Basin, but we have not, you know -- we don't have any plans for any sort of major acquisitions in EnCana. We have always -- we have said and emphasized the fact that we built a resource base here and a land position that is -- we can exploit for a long, long time to come, and you're going to hear a lot more about that at investor days, so don't expect any big moves in terms of acquisitions. John, do you want to talk about --
JOHN WATSON: Sure.
GWYN MORGAN: Unless Randy changes his mind.
RANDY ERESMAN,: No, I would echo that. [LAUGHTER]
JOHN WATSON: Good morning, Ted.
TED ISAAC: Hi, hey, John, how are you doing?
JOHN WATSON: Doing well, thank you.
TED ISAAC: Good.
JOHN WATSON: On the net debt to cap, as you know, we have a target range of 30 to 40% and at September 30th I said we're 40. And if you look on a pro forma basis the proceeds we expect to get in from the announced dispositions, that would get us down into the low 30 range. And then, of course, as I mentioned as well on the -- if you take out the mark-to-market, that would get us into the high 20s. We feel very comfortable in that scenario. On the net debt to EBITDA basis, our target range is one to two times, and at end of the quarter 1.6 times in pro forma, and we'd be closer to one times and, again, I comfortable level to be at.
Fixed charge we like to be in the 12 to eight times coverage. We're currently at 11, and that'll go down, as well, as our interest costs and things go down. And the last metric that we steer towards would be net debt per Mtmb, improve develop reserves, and there we'd like to target in the $0.50 to $0.83 level. Currently, we're at about a dollar, which is a little high, but on a pro forma basis would be right down in the middle of that range at about $0.75. So we feel comfortable, and looking forward into 2006, we think will be a very good year for us and so that is the short of it.
TED ISAAC: Does that fac -- does that factor in the full stock buyback or part of it or --
JOHN WATSON: No, that's a -- well, it doesn't factor in any because it's just pro forma of where we are at September 30th.
TED ISAAC: Okay.
JOHN WATSON: But we feel comfortable that,depending on where prices go, we're monitor this, that we can handsomely handle debt or share buyback and still be well within the metrics.
TED ISAAC: Okay. Thanks.
OPERATOR: [OPERATOR INSTRUCTIONS] And we will go now to van Levy with Dahlman Rhodes and Company.
VAN LEVY, ANALYST, DAHLMAN RHODES, & CO: Good afternoon, gentlemen, how are you? Question kind of following up on the acquisition standpoint and your focus on unconventional resource plays. Your Jonah field is close to the Pinedale Anticline and if you listen to the management of UPL, they are talking 7 to 10TCF. Seems to be a look alike. It seems to be something that would lay in very well, very concentrated. Why wouldn't this fit with your -- with your -- with your Company? Or does the fact that you haven't tried to go after this asset indicate that maybe you don't think that the reserve potential is as significant as the Jonah field?
GWYN MORGAN: I think largely it is because the value we can create by investing in our own asset base, and the returns we are getting are so strong, that to compete if in this market for assets we really don't need to grow the Company wouldn't be a very good use of shareholders capital.
VAN LEVY: But again, if the stated reserves at that range I've talked about was there, you're talking about buying reserves at a buck an M. Again with your asset sales and your balance sheet, you could certainly -- it certainly would be a hugely accretive acquisition for you, not to mention the economics of scale in that area.
GWYN MORGAN: I think I just have to stand on what I said before because it is pretty sensitive talking about acquisitions in any case, but we don't have any intent to make any large ones at this -- at least in the foreseeable future.
VAN LEVY: Okay. Other question regarding the Fort Worth Basin. I think this quarter you drilled about 18 wells in that area. Is that low level of activity, does it indicate that you are not as sanguine about that Basin as some of -- compared to the other area?
RANDY ERESMAN,: I'll have Erik Marsh answer, that if he can.
ERIK MARSH, ENCANA CORPORATION: Yes, I can Randy. Thank you. Knowing the Fort Worth, at Fort Worth, we have nine rigs running in the third quarter. And our expectations have been well met. Everything is going the way we had expected.
VAN LEVY: And would you consider accelerating this play or -- how does this rank, say, compared to the Pinedale or Palace or -- in terms of economic returns, upside, et cetera?
RANDY ERESMAN,: It is a very solid play. Ranks quite high. It's really a question of being able to have access to rigs and services, and it is pretty tide in that area right now. So and it's the same issue we have in a lot of the other areas as well.
ERIK MARSH: The economics are very good.
VAN LEVY: Would you consider, as other companies have done, acquiring our own rigs and running your own crews?
RANDY ERESMAN,: No, we wouldn't. We have -- I think we're best suited to do the thing that we are best at and others are more efficient in the long-run doing what they are best at.
VAN LEVY: Last question. 24tcf of unlooked reserves. How long do you think, say over the next two or three or four years, a rough percentage of that do you think you can convert to a proved developed status? Is it 10%? Is it 30%? Is it 50%?
RANDY ERESMAN,: One of the ways we kind of look at our inventory is we've got about 35,000 wells in our inventory of -- a combination of our proved undeveloped locations and our unbooked resource potential locations, and at a run rate of about 5,000 wells per year that means we would effectively burn through that in seven years on a constant basis. That's some where in the order of about 15% per year.
VAN LEVY: And the 35,000 reflects the -- or relates to the 24?
RANDY ERESMAN,: It relates directly to the 24tcfe.
VAN LEVY: Super. Thank you very much.
OPERATOR: Our next question will come from Erik [Mithall], [indiscernible] Asset Management.
ERIK MITHAL (ph), ANALYST: Good afternoon. Could you please provide an update on the drilling status in the Columbia River Basin and would you also be willing to comment on a Roth Smith report that recently estimates that the total potential recoverables in the Columbia River Basin could exceed 200tcf?
RANDY ERESMAN,: I think we will -- we'll only answer the first part of that one. Actually I'll answer the second part, the Roth Smith. A lot of resource potential -- sort of the gas in place and potential resource, you know, a lot of the unconventional areas can get up to some fairly enormous numbers but, you know, requiring technology, advances and that we may or not have today. So the potential in the long, long, long-term those kind of numbers may be able to be achieved if there is enough pore space in the rock. With respect to the status of the well, I turn it over to Erik Marsh.
ERIK MARSH: Yes, Erik. We are -- we've had a lull in the drilling operation out there where we swapped out rigs and just in the first part of September, we started to get back into the drilling operation and the drilling operation's going fine right now. We do expect to TD the well if December.
ERIK MITHAL (ph): Great. Thank you very much.
ERIK MARSH: Thank you.
OPERATOR: David Tameron with Jefferies.
DAVID TAMERON, ANALYST, JEFFERIES: Good afternoon. Quick question. In the Piceance Basis, just from a 50,000 foot level, where are you guys at as far as delineating the play. I know you talked about the Eureka, et cetera but talk -- where you're at in the learning curve and move more you think you have to go there?
RANDY ERESMAN,: We're producing between two -- 200 and 300 bc -- sorry, million cubic feet per day in the play. We've delineated a couple key area and think the play area has a tremendous amount of growth potential. You know, possibly we are only in the 10-15% of development of that particular play. In terms of the acreage position and the -- and the rock that we will eventually access, very, very early days.
DAVID TAMERON: And where would you move next? What would be your next target following kind of your lead and where we could go from there.
RANDY ERESMAN,: Erik Marsh, actually, directly looks after that area so I will let him answer the questions.
ERIK MARSH: No, Randy's right on as far is the deliniation of the asset, you know, we would say that asset has been ten, to as much as 15% of acreage position has been delineated. We continue to look as we move for -- north into the Eureka area if you're familiar with that, figure four area. Continue to be very pleased with the way we've been able to confirm our Ogit maps and so I think you will see us continue to step out, you know, section by section and to confirm the resource that we believe is there.
DAVID TAMERON: Any guess as to what -- I know this is a -- this is a loaded question but any questions as to what the oil in place, what the recovery factor ultimately will be in the basin?
RANDY ERESMAN,: In the gas in place?
DAVID TAMERON: Gas in place, yes. I know you have an oil are I'm sorry gas in place number of 300 you know a huge number, what percentage of that do you think you will recover ultimately.
ERIK MARSH: We have talked publicly that the Williams forecast in excess of 200tcf in the basin. The aisle itself has between 50 and a hundred tcf so it is in excess of 300tcf. Our work that we are done down [Mamprek] would indicate that if you were to develop the asset properly, you probably could get between 50 and 70% of gas in place, and depending on the spacing that you are looking at and it is going to vary from place to place depending on how much gas in place you have in each area.
DAVID TAMERON: All right. Thanks.
ERIK MARSH: Thank you.
OPERATOR: And if we have no further questions from the analysts, we'll now move to the media for questions. We'll go now to Dave Edness, Globe and Mail Newspaper.
DAVE EDNESS, ANALYST, GLOBE AND MAIL NEWSPAPER: Hello. I was just wondering about per share growth in 2006. I Estimate 15% given the production guidance and an estimate on buyback.
GWYN MORGAN: I guess it depends, Dave, on that buyback number. We -- if we -- natural gas is -- what was the range for natural gas, 9 to 11% or something like that? But the average including the liquids, which is growing more slowly, is 7%. And if we buyback 3% of our shares plus dilution, it just doesn't exactly work out on an annualized basis in terms of how you calculate the per share number, but if I just sort of ignore that to keep it simple, if we bought back 3% plus dilution, we would end up with a 10% per share. If we buyback more then, of course, that would be above that number. But that's about all we can say about it at this stage.
RANDY ERESMAN,: And that is on a continuing operations basis, -- [MULTIPLE SPEAKERS] Very important to mention that we are talking continuing operations, because almost 10% of our production's being sold in Ecuador at year-end.
DAVE EDNESS: Yes, I was figuring that. And then on the general share buyback, it costs roughly 40 bucks a share to buyback all the shares you bought back in the last year and now the share price is 50% higher. I'm wondering about the wisdom of buying back the shares when they're so much more expensive?
GWYN MORGAN: Well, Dave, it's something we continue to evaluate and we do discuss it with our board regularly as we buyback the shares. We were pleased we were able to get the shares tucked away earlier in the year. That was a good thing for us. But I think that the -- what we always keep looking at, of course, is a couple -- is a number of factors. One of which is the overall value of our resources goes up as we get more and more confidence that we are in a whole new era of resource pricing.
The second thing that is a big, big factor and biggest factor of all perhaps is what Randy was talking about earlier, and that is the unbooked resource potential. And in order to do the evaluation for EnCana we have to add the resource potential -- unbooked potential to the booked reserves and then look at the value of that and at least, notionally, try to figure out whether or not we seem to be making good tee decisions, and we keep on evaluating that as we move forward. So far, we've reached the conclusion that we are creating a lot of value by buying back shares.
DAVE EDNESS: Okay. Thank you.
OPERATOR: And we'll take our next question from Ian McKinnon with Bloomberg News.
IAN MCKINNON, ANALYST, BLOOMBERG NEWS: Hi, there. Just a quick question on what is happening with the study with [Valero] on the Ohio refinery and can give a date on when the study will be concluded and whether there has been any escalation in prices for conversion, given what you are talking about on the drilling side?
GWYN MORGAN: Bill?
BILL OLIVER: The preliminary engineering study that we had completed has been confirmed and in the range that we originally estimated with Premcor. As I mentioned before, before we proceed on the detailed engineering we have to determine if there is a commercial arrangement that we want to move forward with. That will require more discussion between us and so we have to have that and until we finalize that, there is nothing more that I can say.
IAN MCKINNON: Are the discussions ongoing.
BILL OLIVER: Yes, they.
IAN MCKINNON: Any time line.
BILL OLIVER: And we understand that value for each of us. It's a question of them understanding the upstream business a little bit more than -- they certainly haven't had that exposure in this type of arrangement, so they're anxious to have the discussions and they were committed to it. Just getting enough time to work out more details.
IAN MCKINNON: Any time line for the discussions?
BILL OLIVER: No, I don't think we want to set a time line. I think what we want to do is give each of us time to appreciate the go-forward position and establish the best deal that might be available or not.
IAN MCKINNON: Saying you're still around $1.5 billion U.S. is that, correct?
BILL OLIVER: I think that is a good range.
IAN MCKINNON: Thank you.
OPERATOR: Kevin Cox, allNovaScotia.com.
KEVIN COX, ANALYST, ALLNOVASCOTIA.COM: Mr. Morgan, what regulatory issues still confront you on the deep [indiscernible] front, what were you referring to there?
GWYN MORGAN: Well, I'll turn it over to our guru on these sort is of things, Gerry Protti, who will tell you some challenges he thinks we still have.
KEVIN COX: Thank you.
GERRY PROTTI, EXECUTIVE VICE-PRESIDENT, CORPORATE RELATIONS, ENCANA CORPORATION: Hi, Kevin, we continue to work on the revised [ indiscernible ] plan application. In that work that includes the discussions with all stakeholders which is the government. And just putting context in the comments Gwyn made in the call, if this project were located in other offshore jurisdiction, like the Gulf of Mexico or North Sea, we could expect with confidence that we would get through the regulatory process in six to nine months. And this is no surprise to, I think, all of the stakeholders. There's been consulting work done on it. There's been numerous discussions between government sand industry and individual companies, and I think governments at the political level made a commitment, and signed an MOU several months ago to try and streamline. And we're the next one cut into the process and we haven't seen much evidence yet that in fact we could achieve those types of time lines. The challenge for the government is to actually deliver on that and get through some type of expedited process to that the development could begin to commence again off the Nova Scotia coast.
KEVIN COX: Thank you.
OPERATOR: And at this time we have no further questions standing by. I would like to turn the conference back to our speakers for any additional or closing comment.
GWYN MORGAN: Thank you, operator and thanks everyone for spending all this time with us today. Know we put a lot of material out in the release, not only on the third quarter but on our plans for 2006.
And speaking of our plans for 2006, I want to remind you that we're going to have an investor day in Calgary on November 7th and an investor day in New York on November 9th and I hope you can attend one or the other or both, if you really want to get all the information possible. I think the bottom line is that you will see more and hear more about the strength of the North American natural gas resource plays and, of course, even the progress we made over the past year in our plans.
One thing that you are going to hear more about than in the past is also our leading position in in-situ oilsands. There is some exciting things we're going to be talking about on the oilsands front and all I can do is encourage you to be there to here it. We look forward to continuing to have your confidence and to deliver for shareholders ,and I know that this team will do just that. Thank you for being with us.
OPERATOR: Thank you for your participation in today's conference call. You may disconnect at this time.