Teck Resources Ltd (TECK) 2006 Q2 法說會逐字稿

Welcome to the UTS Energy second quarter conference call. (OPERATOR INSTRUCTIONS).

The Company may make forward-looking statements during this call. These statements are based on UTS' expectations and are subject to a variety of risks and uncertainties and other factors, which are inherent in a pre-development stage oil sands mining and extraction enterprise that could materially affect UTS' results. The Company assumes no obligation to update any forward-looking statements.

I would like to remind everyone that this conference is being recorded on Thursday, August 3, 2006 at 11:00 AM Eastern Time, and will be available for playback on the Company's Website. I will now turn the conference over to Mr. Dennis Sharp, Executive chairman. Please go ahead, sir.

Thank you very much, operator. Good morning, ladies and gentlemen. My name is Dennis Sharp, and welcome to the UTS Energy second-quarter conference call. I am joined today by William Roach, our President and Chief Executive Officer, and Wayne Bobye, Vice President and Chief Financial Officer. Before asking Will to provide an overview of the corporate developments from the quarter, and Wayne to update UTS' Fort Hills funding position, I'd like to say a few words.

As we move forward with the Fort Hills project, we do so in an ever-changing business environment. Costs of doing business in the robust Alberta economy are rising, and the challenges of accessing the necessary labor for major projects are ever-present. In times such as these, however, you can all appreciate it is very important to have a partnership that has the necessary experience to manage these challenges.

Petro-Canada as operator brings experienced project management with the depth to commit capital and expertise to a multiyear major project. Petro-Canada has both upstream and downstream experience, which will be of enormous benefit as we proceed with both mining and extraction in Northern Alberta and upgrading near Edmonton.

Teck Cominco is a diversified mining company, and their interest in the project represents an additional and important diversification for the world-class miner. Teck Cominco's expertise in mining will also diversify the expertise available to Fort Hills, further strengthening the partnership. Needless to say, we believe we have put in place an outstanding partnership with Petro-Canada and Teck Cominco and UTS Energy.

I will now turn the presentation over to Dr. William Roche. Will, be my guest.

Thanks, Dennis. Good morning, and thanks, everyone, for joining us today. I'm going to be referring to a presentation that is up on our website, and that can be accessed at www.UTS.ca. And I'd like to draw your attention to the first slides, which indicate the forward-looking information in this presentation, as mentioned previously.

Moving on to the next slides, what I'd like to do is summarize that we've got three main messages to cover in this presentation. [Firstly] we'll discuss the Lease 14 independent resource estimates; then we're going to talk a little bit about the Alberta business environment and extraction and upgrader technology selection that the partnership made in the beginning of this year, but we won't be able to provide any detailed cost estimates at this point. We are awaiting the completion of the Design Basis Memorandum. In the fourth quarter of 2006, that will be provided to the partnership by the operator, Petro-Canada.

However, we will provide guidance on fundamental differences on capital and operating costs for two of the prominent technologies used in the oil sands. And you should note that for those specifically interested in that matter, there's some additional information at the end of the presentation we're using on the Website.

And then finally, Wayne is going to talk a little bit about the funding position, and also the near-term milestones for both the project and some of the upcoming activities for UTS.

Moving on to Lease 14, we'd like to talk about the preliminary core drilling results. UTS owns 100% of Oil Sands Lease 14, which is on the west side of the Athabasca River. Teck Cominco has the right to participate in Lease 14, up to a maximum of 50% working interest at a fair market value, which will be determined at the time of an election to participate.

Moving on to the slide now talking about the drilling, we've conducted a 28 well drilling program. And we completed that in January of 2006 to determine the extent, quality and characteristics of the oil sands on this lease.

The program was conducted safely, on schedule and on budget. And the chart shows the well locations. And these results have been evaluated now and resource estimates have been completed by an independent consultant, Norwest Engineering.

The existing drilling density on Lease 14, with an average well separation of between 700 and 1100 meters, does not allow the development of meaningful mine plans for the low (indiscernible) and the best (indiscernible). (indiscernible) estimates only assume mineable ore is present within 200 meters and 400 meters, respectively, of the existing well bores. However, the high, the probably 10% estimate, assumes the (indiscernible) present within 1000 meters of the existing well bores, and effectively assumes a continuous deposit is present.

It's anticipated that further drilling will provide greater certainties for the resource estimates within the [Murray] formation on Lease 14. UTS intends to complete a more comprehensive core drilling program this upcoming winter, which will reduce the average spacing to approximately 400 meters by drilling about 100 wells at an estimated cost of 14 million Canadian dollars. Subject to, of course, receiving the appropriate (indiscernible) approvals, it is UTS' intention that the joint program will start in January '07 and be completed by March '07. And then hopefully we will be able to get that refined resource estimate in the third quarter of 2007.

Moving on now, the original guidance we gave pre-drilling was between zero and 500 million barrels on Lease 14, and that was really based on discovered resources on the lease immediately to the south of us operated by Shell. We [as] management then announced (indiscernible) and off the logs a revised estimate following drilling of between 230 million and 360 million barrels. I'm happy to say now we've got the independent engineering estimate from Norwest Corporation, (indiscernible) results of initial drilling on 14. (indiscernible) reports give us a range of results for the [in-place four], and the estimates are as follows.

Low estimate with a probability of 90% is (indiscernible) this number is 66 million barrels, best estimate with a probability of 50% is 243 million barrels, and the high estimate at probability of 10% is 594 million barrels.

Finally, under the high estimate case, it is possible to develop a meaningful mine plan, which is on a continuous ore body. This yields between 367 million barrels of mineable ore, with a [TB to debt] cutoff ratio of 12, or 417 million barrels with a TB to debt cutoff ratio of 16.

UTS management's belief (indiscernible) resources is going to be in the range of 400 million barrels, which is significant and increases UTS' current resource estimates within the Company by between 25 and 40%.

Moving now to the Alberta business environment and the technology selection for the project, which was made, as I said, in the first quarter of 2006 by the partnership. And I would add that this decision on the technology selection was made on preliminary cost estimates, looking at a project notionally of around 100,000 barrels a day of synthetic crude oil for the first phase production level.

The Alberta economy has been particularly strong of late, and the cost escalation we have seen has been and, we believe, is directly related to high oil prices, generating significant activity across the energy industry, not just restricted to the oil sands sector.

A number of project proponents have reported increased costs from original forecasts, often due to higher-than-expected labor, materials and equipment costs. The (indiscernible) project is also subject to these cost challenges, and the partnership continues to position the project to minimize these pressures. Notwithstanding that, UTS believes that we are at the upper-end of our previous guidance on the project cost estimates provided by UTS.

The partnership will be in a position to update the project estimates the fourth quarter of this year, after the partnership has completed, as I said before, the Design Basis Memorandum and, most importantly, made the key decisions on project size, pace of development, and details of that nature. This is clearly linked to the mine plan that will be reviewed and revised in the same time period. Overall we believe the likely outcome is a larger first phase project with a correspondingly larger mine plan and overall resource on the lease.

Moving on to the technology selection, the main points here really are that the selection of technologies for the mine or preparation and extraction (indiscernible) is independent of the upgrader technology. (indiscernible) treatment though must be selected to meet the pipeline specifications and feed requirements for the specific configuration of upgrader selected. Both those projects have chosen naphthenic froth treating and delayed coking upgrading technology, and this was really -- this combination was selected for several reasons.

Firstly, we believe it's less capital-intensive and has lower long-term operating costs, and we believe it's going to be more reliable than hydrocracking, and most importantly there's a greater depth of experience in delayed coking around the world.

(indiscernible) delayed coking and hydrocracking, we believe that hydrocracking has considerably higher capital intensity per flowing barrel, as shown by the next chart. However, that is offset by the [flat hydrocracking yield that is] significantly higher at 17%, higher than delayed coking.

Bitumen production from the hydrocracking is more expensive than coking at 20 to 30%; upgrading for the hydrocracking is more expensive than coking, again, about 25 to 35% more; therefore, the overall hydrocracking is between 20 and 30% more expensive in terms of the capital intensity per flowing barrel of synthetic crude oil and coking. And that's even accounting for the $0.17 high yield the total process for hydrocracking.

With respect to operating costs, hydrocracking uses more natural gas, between 45 and 55% more than a barrel -- per barrel of synthetic recoil. So therefore, this translates into significantly higher operating costs per barrel. And we also believe that the hydrocracker onstream is typically less -- 5% less than a delayed coker. Overall, they're the main reasons that drove us to decide to go for a delayed coking and naphthenic extraction process.

Now I'd like to just move on to the schedule, and where we would like to just share with you that we are in pretty good shape for first production in the third quarter of 2011. And we'll recall that we have all the major approvals in place for the mine and extraction facilities. Our focus is now on the upgrader. Fort Hills has submitted a preliminary public disclosure document to regulatory authorities, announcing the partnership's intent to build an upgrader in Sturgeon County 40 kilometers northeast of Edmonton. This is the start of the regulatory application process for the upgrader, and by the fourth quarter of 2006, first quarter 2007, we will be in a position to file the application and the Environmental Impact Assessment for the upgrader. Following the completions of the regulatory process, we hope to receive approvals for the upgrader by the end of 2007 or in early 2008.

Notwithstanding this schedule, the partnership may well need to order (indiscernible) as early as in the first quarter 2007, which is well before project sanction. By the end of '07 and early '08, the project will be submitted to the respected Board of Directors of the partners for sanction. With the appropriate corporate approvals, we will then move into a detailed engineering and procurement phase.

Note the project sanctions currently scheduled to occur before both Petro-Canada and Teck Cominco (indiscernible) is incomplete. Wayne will show you the slides of that shortly. Major construction started in 2008 with commissioning in early 2011, the start=up just after midyear in 2011. Note all partners have rights to proportionate upgrader expansions over and beyond the Fort Hills project for processing of bitumen. That's, we feel, a very important point as we now have a resource in Lease 14 that we think is a good candidate for that.

At this stage I'd like to hand over to Wayne, and ask him to talk a little bit about the funding, and then close up with some of the near-term milestones.

Thank you, Will. My name is Wayne Bobye, Chief Financial Officer. I'm going to talk about the Fort Hills funding position. Main points I want to make is that the partners are committed to spend 2.5 billion in order to earn their respective partnership interests. At the present time there remains to be spent 2.2 billion of earn-in capital expenditures to be spent by the partnership before UTS commences funding from 4% to 30%. UTS will have its funding for this 2.5 billion until the first quarter of 2009, based on our current spend rate. Even with a larger capital spend, we should be able to still have enough funding until the first quarter of 2009.

The funding of this structure puts UTS in a very good financial position for present and future funding. Project sanction occurs in the fourth quarter of 2007 or the first quarter of 2008, before completion of the partnership earn-in. This puts UTS in a very strong financial position. We provided some guidance in earlier presentations that -- in a higher CapEx sensitivity case, and UTS can finance the project even with a higher capital spend.

In the broader context, UTS is looking at various options for funding exploration activities outside of the Fort Hills project. We'll continue to look at those and make a decision later on in the year. UTS will have sufficient funding for long leadtime items, which could occur in early 2007. We have to order those items. We'll have enough funding in place within the framework of the $2.5 billion.

UTS has given a lot of -- has been given a lot of financial flexibility with the successful drilling of Lease 14. It provides operational flexibility for future nominations, for the incremental upgrader expansions, beyond the Fort Hills project. Also this lease will provide flexibility and funding and could provide collateral for future funding of the project.

Moving on to the near-term milestones, just turn your attention to the Fort Hills project near-term milestones. First one will be concept selection for the Fort Hills project, which will occur Q4 2006, and Teck Cominco will provide our revised mine plan in the fourth quarter of 2006. Petro-Canada, the operator, will provide revised capital and operating costs by the fourth quarter of 2006, and I understand they're going to have an investor day on October 4, 2006, and perhaps at that time they'll announce those CapEx and operating cost numbers.

The upgrader project -- the submission of the upgrader cost and capital will be done by the fourth quarter of 2006 or first quarter of 2007. I've already talked about long leadtime items, which will occur probably in the first quarter of 2007. These would be items like drums that are critical items that are required to keep the project on schedule.

Project sanction -- we already have approval for the mine plan up to 190,000 barrels a day, so project sanction with the upgrader should occur fourth quarter 2007, first quarter 2008.

And finally we've got -- as I've mentioned already, we have our funding in place for the first 2.5 billion. But during that period, probably in the third quarter of 2007, between that or the third quarter of 2008, we will do some project financing wherein we raise enough money to secure our position in the project through the capital markets.

I'd like now to turn over the -- let's -- I'll turn now to the Lease 14 near-term milestones. We've talked about the preliminary drilling resource estimate that Will has already outlined. We're going to do [a] Lease 14 infill drilling program in the first quarter of 2007, and then have a resource estimate later on in 2007 in the third quarter or fourth quarter. And we'll continue, as I've mentioned previously, to analyze various financing options for funding our exploration activities outside of the Fort Hills project.

That concludes our presentation. I'd like now to turn it over to Dennis Sharp for questions.

Thank you very much, Wayne. I'd just emphasize Wayne's last point is an important one, that in addition to our activities related to the Fort Hills project, we are continuing to analyze the options available to fund the exploration activities which are outside those lands related to Fort Hills.

I would like to turn it over to the operator.

(OPERATOR INSTRUCTIONS). Ken Rowan, First Energy Capital Corporation.

Will, on the call you made some reference to comparing hydrocracking and delayed coking. And I'm wondering if you could add a little bit more clarity in that, because I think the market reacted quite negatively to the Shell Western announcement a few weeks ago, suggesting that ultimately costs could range as high as 120,000 a pulling barrel with future expansions. Could you just go into that a little bit more, and give us a thought about what the UTS Fort Hills project may cost, and compare and contrast the methodology a little bit more?

The first thing is, as we said, we've gone for delayed coking, and also -- a combination of delayed coking and naphthenic production. That gives you two advantages. We've tried to show that in the additional information at the back of the presentation, where we show the cost differences in each of those elements and the overall cost difference.

When we did the analysis at the beginning of the year, as I said, we looked at a notional 100,000 barrel a day development of synthetic product, and we compared both coking and hydrocracking. And we came out with cost differences in the order of 20 to 30%, with hydrocracking being significantly more expensive.

In addition to that, we saw a lower overall reliability in the hydrocracking track record, and also we saw a significantly higher operating cost with the cost of natural gas and the usage of natural gas being there. And really, those factors led to the partnership. And I'll emphasize this is a partnership, which is led of course by Petro-Canada as operator, that concludes unanimously that we should go towards hydrocracking. So we felt that offered us both operational flexibility, and also some cost advantage.

I can't, obviously, speculate or comment on the Shell announcement. I will comment that, yes, we appear to be being held out there as having probably the same cost structure. And I think the whole point -- and you've picked it up, Ken, I'm pleased to say -- is that we feel we have a very different cost structure than potentially associated with hydrocracking.

And while we have to wait, unfortunately, until the year end, to get the actual results out of the DBM, we tried to give a sneak preview of that in our corporate presentation, where we look at a bigger first phase of the project, (inaudible) sensitivity case of 140,000 barrels a day, and the second phase of the 100. And we think the total cost of that would be in the order of $15 billion. And so far, that would indicate the cost estimates being significantly lower than that of hydrocracking.

We are really just going to have to wait until the fourth quarter, and I know that's frustrating, but I think that Petro-Canada as the operator are being very prudent and sensible, and doing all the engineering work that we need to to get a very good handle on those costs, and then come to the market and explain them.

Steven Calderwood, Raymond James.

My question has two parts, one of clarification on funding in 2007, I think you said; the second part, a more strategic question in view of the long leadtimes and the potential for cost overruns. I'll ask the first question -- the first part of the question perhaps for Wayne Bobye. You said in your dissertation, the third quarter '07 to possibly the third quarter '08, there's a window in there in which you may need to raise some money. Could you clarify just how much you were contemplating there, just a ballpark figure?

That would be the overall funding for the project, just to go back on that. We have -- to reemphasize, we have our funding in place for the first 2.5 billion, and we would be looking at putting funding in the debt market and equity markets.

And as I mentioned, we have flexibility with Lease 14. And depending on where -- I'm not going to try and put a value on that, but that's a substantial asset, and it would certainly factor into the equation of how we do that funding. We take the number that Will has just mentioned, the 15 billion; we've indicated in previous presentations that we could fund that. And we'd go to the debt market and for the first phase have about 1.6 of debt. And we've shown the ability to pay that off over a period of time by -- quite quickly at a $40 oil price, and at a 50, it pays off rather rapidly.

And on the equity side, the amount of equity that we would have to raise would be really dependent on what happens with Lease 14, in terms of Teck Cominco or perhaps some other company would want an interest in that. So I can't really give you a specific number on equity at this time, but there would be some equity in there, but it would be a function of what we do with Lease 14.

Will, do you want to offer any further comment on Wayne's dissertation?

I think Wayne is being specific about something that we haven't yet decided internally. There are two big variables. One is what is the first phase going to actually cost? And that 15 billion is for two phases, so let's not [get] that out of perspective. So that's the first point.

And I think that what we're trying to get over is that we've got a pretty significant asset in Lease 14, and it's really strategically placed. And if we are right, and it's mineable resource in the order of 400 million barrels, there's lots of precedence out there for the valuation of that. So that really could offer us a way of financing or providing for the financing.

However, it offers us a lot of financial upside as an oil resource to be developed. So, I think what Wayne is saying is we've got a lot of options. And in any case, we believe we can finance this rather large capital [intensity] project (inaudible) that stage. Dennis?

And possibly you could move on and answer the second part of that question, Will.

Could you remind me what it is? Sorry.

It wasn't -- I wasn't fair; I didn't realize that you were talking about funding the whole project within that window. Let me take a step back.

Because of the date that you gave on the call, Q1 '09, I was thinking, yes, you would have a chance to see what kind of cost overruns could be the current two-year estimates by that time. But 3Q '07 might be a little early. So let me tell you, in our model we conservatively carry a cost overrun of 100% capital for Phase I. We understand that this -- a cost overrun like that would go way beyond the capital cost carry agreement you have with your partners. Just (multiple speakers).

If such a large cost overrun were to occur, the question is how would you fund it? And I might ask it in a two-part way. What if the cost overrun were like 10%, or a fairly small cost overrun? And then, what would the cost overrun funding source be if it was 100%?

Let me try that first, Wayne, and I'll hand it to you. Is that okay, Dennis?

That's fine.

The first thing I would suggest is we shouldn't confuse when cost overruns occur with where our financing goes to. Most of these projects that have had problems with cost estimates have been floored in two ways -- one, the quality of the cost estimate in the first instance; and then secondly, the actual execution of the final year and a half of the project. So you don't really get in to get a real feel for the final outturn cost, I would argue, until you're probably six months away from commissioning. And that would be in the second half of 2010.

I think what Wayne was trying to get over was we've got a lot of financing in place, and on our current spend profile, which even if you saw some cost escalation wouldn't change very much in the first instance, we're pretty well funded to the first quarter 2009. What Wayne was saying is we will put in place financing for the first phase and the costs for the second phase to first oil. And at that stage I'm sure there will be some contingent funding in place -- put in place. And in addition to that, we'd probably have an option to look at funding with, for example, Lease 14 or any other asset we have at that stage, should that be necessary.

Wayne, do you want to add anything?

I was just going to say, Lease 14 could play pretty significantly in that. We could use that as collateral for funding. And typically we would -- in funding a project like this, you would have set up contingent amounts, where we would have set aside debt and equity to fund that. But that's difficult to say what those are until you know what the capital costs are.

Jenny Mikhareva, Orion Securities.

I have two questions. First of all, the (indiscernible) took quite a bit of a hit here in the past four weeks since the Athabasca Oil Sands project announcement of higher capital costs. What steps have you guys taken to try to reverse that drop? I understand you're trying to talk about the differences between two projects. What else are you doing?

Let me just start off by saying, as I've repeatedly discussed with Will, from the perspective of management, we are in better shape today than we've been ever before in the corporate history of UTS. And it's a little bit like the baby and the bath water, but that's how the market is treating oil sands right now. And our option is really to convey to the marketplace, through sessions such as this, where we are at, what we're doing to create value. And we believe we have a lot of the components in place to do that.

I'm going to turn it over to Will and let him give a more detailed discussion on where we're moving on this issue. But Jenny, it is of concern to us because no one likes to see their share price moved as far down as ours has been in the last few months. Will?

Thanks, Dennis. The first thing is you're right; what we've -- today we've tried to do, and we've done with some of our shareholders when they've called us, is we've talked really -- well, let's explain the difference between the Fort Hills project configuration, i.e. naphthenic extraction and delayed coking, versus hydrocracking. So we're trying to get a good understanding out there that these projects are different, and you can't say because there's a capital [tendency] of this much.

I think the other thing is that you're seeing people be very conservative with cost estimating now. I think the pendulum, having swung from being everyone being very optimistic when we were at the beginning of learning how these very large projects should be done -- that people are saying right, now here are cost estimates that we will not reach. I can't comment on the comment of cost estimates from -- provided by Shell, and you really should ask them that. But I suspect you're going to see very robust cost estimates, because we also have a very robust commodity environment. I think those are two things.

I think the other thing we're trying to do is really get over to the market that we are more than just Fort Hills. In Fort Hills, based on a 3.5 billion mine plan, recoverable mine plan, our share today is just over 1 billion barrels. We expect that number to go up. We think there's oil upside left in that mine plan, and we're going to be doing the final sizing of that mine plan, hopefully, in the fourth quarter of this year.

So even at the 1 billion barrels, Lease 14 represents probably around 30% to 40% of our current resource. That, we believe, has not been factored into our share price today. And we see that, as we've tried to emphasize, as pretty significant. We've also got Lease 311 to the north, and we'll be delineating that in the upcoming first quarter. So I think what we're doing is we're trying to do good business, focus on making the right decisions in the partnership, and get the message out that we've got other assets in addition to the very good funding position we're in, and also Lease 14.

Also, just on top of the capital cost pressures, there have also been other pressures recently put on the oil sands companies, everything pretty much from increasing royalties potentially, to even a moratorium on oil sands. Now, what impact does that have on you guys? I just want to initiate a bit of a philosophical discussion here.

I'll answer one question very quickly. You should remember that this project has government approval, and there are a number of projects out there that have not been approved by the government. So if there was going to be any interruption, I'd feel quite comfortable that it would be on other projects, not Fort Hills, that has received government approval. Turn it over to you, Will.

The first thing, obviously, we're approved, and that's a great position to be in; i.e., we're in the queue and the upgrader is in the system. The upgrader is being proposed in an area which is designated for heavy vessel use, so that's consistent with the government objectives there. And also, I believe, it's fairly consistent in terms of its desire to retain as much of the added value activity within the province. So I think we're pretty well aligned with the government in the project.

If you take a broader look at the calls for the moratorium because of the environmental impact, I think that they're significant challenges and pressures being brought to bear, which, appropriately, all of the oil sands companies have to really manage pretty carefully the [mix]. And those revolve around mainly water usage, air quality, and the use of natural gas. And I'm happy to say they're all pretty high agenda items on the project [hit list] (technical difficulty).

But I think the other issue is people are saying, well, they're going to be constrained on workforce, etcetera. I've worked pretty well most of the -- quite a large number of environments and places in the world, and I would have to say the Alberta business environment is probably one of the best I've ever worked in. It's very pro-business and also very good on stakeholder support. So, I think actually Alberta and Canada has got a lot right there, and I don't personally see a moratorium coming anytime soon on the developments of the oil sands. I think there will be some surprises, and some projects will get delayed. I think that is correct. I'm pretty confident UTS (technical difficulty) Fort Hills project won't (indiscernible) put in place a pretty strong partnership, and that's one of the reasons why we wanted to go with a very strong downstream player like Petro-Canada and a very strong miner, is to bring that certainty to the project. And I think we've done that quite successfully.

In terms of your comments on the fiscal regime, I believe that fiscal regimes can all possibly change. But again, they're pro-business, and I believe the government announced they weren't in the short-term looking at changing any of those royalty rates, which I think is (technical difficulty). So I think we're in -- we're in pretty good shape. And I certainly, with the commodity price environment we're in, don't see the practical delay of large projects like this occurring.

[Jesse Sholdus], Goldman Sachs.

I had two quick questions for you this morning. I guess the first question was I was hoping if you could confirm again your production expectations from Fort Hills going forward for me.

This is not finally decided yet, and that's one of the things that will be decided in the Design Basis Memorandum at the year-end. My expectation is it will be a larger project than a smaller project. The current range, I believe, we're looking at is between 100 and $140,000 a day in the first phase of synthetic production, followed by subsequent phases taking it up to 240,000 and maybe 300, depending on whether we go for some gasification -- [asseting] gasification, which effectively debottlenecks the structure.

You'll note that the upgrader approval has gotten it up to 300 to 400,000 barrels a day, so that's a pretty substantial project, and may well involve taking fluids from other projects as well. Sorry to be a bit vague, but we really have to wait until the end result of the design basis we have being done by the operator, Petro-Canada.

That's great. Thank you. My second would be, I'm just curious -- what would happen if Petro-Canada for some reason decides not to sanction the project in late 2007?

(multiple speakers) get into that one. If you can answer that one, please.

The first thing is I absolutely will not conjecture about Petro-Canada not going forward with the project, or what the consequences of that would be. I think you really have to ask Petro-Canada about that.

Now, it's my complete and full understanding -- and I will ask Dennis to follow-on here (technical difficulty) that Petro-Canada entered into the relationship with UTS and Teck Cominco on good faith. And the whole premise of the earn-in agreement is the project goes ahead on a prescribed date with the use of an upgrader at the prescribed time. So I can't believe, from both the ranges we have in place in our partnership arrangements, and also the discussions with the government, that that is (indiscernible). But again, you must ask Petro-Canada that question, not us. Dennis?

Certainly from our perspective, the reason Petro-Canada was selected as our partner was their need for an oil sands project of this magnitude. So if you look at their corporate objectives, oil sands is a strong component of that. And we feel, of course, that the mechanics of the earn-in are such that it just isn't feasible for Petro-Canada not to proceed.

Jason (indiscernible), RBC Capital Markets.

Three questions for you. First was just on the pace of development in Sturgeon County. I was wondering -- obviously, there's a lot of projects being announced, and I was wondering if you could just comment on whether that brings up any issues or risks with the pace of development in the area. That was question one.

The second was just to get a little more definition on the earn-in commitment -- sorry -- the commitment from Petro-Canada, 1.55 billion. If I understand this correctly, if they spend something less than that, 7 or 800 million, and then decide for whatever reason not to go forth, is the commitment so firm that they have to put the rest of the 1.55 billion into the partnership? Just if you can comment on those mechanics.

And the last one was just confirmation on the capital costs. You had mentioned that, prior to you guys getting the cost estimate in Q4, that you would use the high-end of your previous guidance. And I just wanted to confirm that that was somewhere around the 60,000 per flowing barrel value.

Will, I'd appreciate it if you'd handle that.

Pace of development in Sturgeon County -- obviously, an issue. I believe there is a project by (indiscernible). There is a project by NorthWest Upgrading that has [been announced], and also an expansion by Shell, which has been announced, and also the Fort Hills project.

So, clearly, a busy area. Do we see any constraints being presented to us in terms of the regulatory approval of that? It is a designated area for that sort of development. I think the main issue is can you get access and also workforce that you require in that area at the same time. Not all of those projects have the same first oil date. And in fact, one would expect that they are clustered, as I understand it, at the earliest around 2010 and latest around 2012.

So I think that's not too bad, and I think that the issue really is if you're adjacent to a center with a population of around 1 million people, it's sure easier to get a workforce and also have a workforce move in and stay there and integrate. I think the good thing is that there's obviously going to be a lot of long-term work as these projects are going to be going on for the next 50 to 100 years. So that's actually a lot easier to attract long-term good quality employment into. I'm actually quite an optimist over the labor issue.

Okay. Your question, I think, was what happens if Petro-Canada stops the project halfway through the earn-in. Correct?

Yes. I just want to understand how hard their commitment is.

My understanding is that the details of that agreement suggest that they would have to default the license if they do that. That would be a very unpleasant outcome, because of course in the worst-case, the partnership would lose the license. And one of the cardinal principles of the agreement, as I said, is to do everything in their power to get into a production (indiscernible) and also to retain that license.

So, that's about as far as I can go with that, Jason. I'm just trying to give you a hint; not hint, but a -- it's a difficult question in that it's not something that we've contemplated particularly, because we believe there is a good intent on all parties to proceed with the project.

And the last one was just on capital costs.

What we've given as guidance in our corporate presentation is a sensitivity case; it's not really a guidance. What we try to show is for a project with 240,000 barrels a day. We thought that may be around 15 billion. That's not a number that's come out of the partnership; that's just some scaling numbers we put together on internal work. So Petro-Canada will say, if you ask them, wait till the fourth quarter, first quarter (inaudible) capital intensity, I believe.

So, we see that splitting out two-thirds, one-third; two-thirds one first second, second one-third second space. So we think the capital intensity in the first phase will be significantly higher and a bit bigger a phase. So if you assume that 15 billion with 10 million for the first phase at 140,000 barrels a day, that's about 75 I think, and you should range those numbers, and then the second phase would be around 50, which gives you an average of 62.5 for the whole project. But those are pretty tentative numbers right now, and I'm hesitant to say that those are the right ones, and that's what we've been spending all this money in the partnership to go and get. And we haven't defined the exact scale of the first phase and the second phase, and the exact content of what's in the project and what's not in the project. But I think that's a reasonable model to think of. And what we've tried to do is demonstrate -- really the point we're getting off that is we can fund a project that big. I wouldn't take that as de facto numbers; I would take it as an indication that we've looked at the bigger end of things and we can finance it.

[Moses Osiac], private investor.

Listening to your technology selection, I see that you selected delayed coking, which basically is at the lower end of technology. Bitumen basically has 15% oil, 65% resins, and 35% -- 30% (indiscernible). And the problem with bitumen, it's highly aromatic. So basically you are short of hydrogen. So delayed coking is not going to do anything to improve the quality of your oil, and you will never be able to get world prices for your product. So hydrogenation is a big issue.

So, the fact that you stayed away from (indiscernible) related hydrocracking, it's really a problem, because you have 102% year recovery on that one, whereas delayed coking is at best 75, 76% of a product that is still very aromatic, which means too many carbons, not enough hydrogen. So I'd like to see your answer on this. Thank you.

Dennis, I guess you're going to hand that to me.

Go ahead, Will.

The first point is, there is some hydrogenation in the process to finish off the product, and our yield will be around 85%. And the other point is it's very clear that you can have a very large natural gas position (technical difficulty) putting your source of hydrogen as natural gas into the process and getting a high yield, as we've said. That's a very extensive process, and you're taking a very clean fuel and making a synthetic crude oil.

The synthetic crude oil, of course, that we're going to be making -- we haven't decided yet on the exact configuration of that; that's part of the Design Basis Memorandum. But I can assure you it will be in all likelihood 30, 34 API, pretty high-quality sweet product. So there is quite a bit of hydrogenation that goes on, even in delayed coking. So I wanted to reassure you of that.

I think that what we found is that there were a lot of long-term factors that suggested that in the current business environment, delayed coking was the way to go. And interestingly, I think, of the upgrading technology installed worldwide, 85% of the decisions are made on that basis as well. And if you wanted a more detailed technical discussion, I'll certainly -- if you could get a hold of us, we'll get our process engineering experts, our Vice President of Engineering, Mr. Martin Sandell, to talk to you.

The problem with me is that I'm a 30-year veteran of oil sands development and production and so forth. So, to say that product out of a delayed coker, there is hydrogenation there, I basically take exception to that. Because (multiple speakers). So, I am sorry to hear that, because the only hydrogenation you would have is from hydrogen being brought into the equation, but not by delayed coking. Delayed coking is a very, very crude process, as you know.

I'm sorry; you misunderstood me. There is a separate process afterwards that adds hydrogenation. Both processes use natural gas; one uses a lot more than the other.

Yes. The problem is that today, for example, Suncor production does not fetch world price market of crude oil, whereas places like Syncrude do, because they have premium sweet blend, which is de-aromatized. So maybe your selection of delayed coker is based on the current situation where cost overruns have been experienced.

But I'd like to make a point, is that Shell, even though they ran two (indiscernible) of hydrocrackers, they're still going for a third one regardless of the cost overrun. Because in the end, if you want to get $75 a barrel U.S. for your product, this is the type of technology that you need. Furthermore, you need crude oil to make transportation fuels, and transportation fuels basically are very paraffinic olefinic; they are not aromatic like bitumen is. So this is the big dilemma that we're talking about here.

Moses, I'm going to have to interrupt, because we may have some other people who want to raise some questions. What we will do is we'll get back to you. And as Will has indicated, Martin Sandell would be happy to review this in more detail. But I can assure you that a lot of time and effort was put into this decision to go coking versus hydrocracking, recognizing all of the benefits and disadvantages of both processes. I thank you very much for your comments.

(OPERATOR INSTRUCTIONS). Mr. Sharp, there are no further questions. Please continue.

Thank you, operator. Ladies and gentlemen, this concludes the conference call for today. I'd like to thank you very much, on behalf of Will and Wayne, and the others in UTS, for your participation today. I would ask that you please disconnect your lines. Thank you again.