Suncor Energy Inc (SU) 2003 Q1 法說會逐字稿

Welcome to the Petro-Canada first quarter earnings results conference call.

During the presentation, all participants will be in the listen only mode. Afterwards, we will conduct a question and answer session. At that time, if you have a question, please press the one, followed by the four on your telephone. As a reminder, this conference is being recorded Tuesdays, April 29, 2003.

And I would now like to turn the conference over to Gordon Richie, Senior Director Investor Relations. Please go ahead, sir.

Good afternoon,everyone, and welcome. With me today are Ron Brenneman, Petro-Canada's Chief Executive Officer, and Harry Roberts, the company's Chief Financial Officer.

Before we hear from both Ron and Harry, I'd like to highlight the changes we've made in the first quarter earnings release. In the NDNA and in note one to the financial statements, we have provided expanded disclosure, showing segmented information for each of our major businesses, North American Gas, East Coast Oil, Oil Sands, International and Downstream.

We made the change to better align our segmented disclosure with the way we manage the company. And we plan on retaining the segmentation on going forward.

So with that brief note, I'll now hand the call over to Ron Brenneman who will provide his comments on Petro-Canada's first quarter. Ron?

Good afternoon, everyone, and thank you for joining us on this busy day for Petro-Canada. Today, we released our Q 1 results, we held our a board meeting, and then we held our annual general meeting. You're last, but not definitely least on our agenda today.

I'll focus my remarks on the first quarter's results because I talked a lot this morning about the higher level strategic outlook. You can locate the AGM speech on our web site.

The real story behind our Q 1 results is how Petro Canada's expanded asset base enabled to us capitalize on an exceptional business environment. Financial results in the quarter were outstanding and overall operational performance was impressive. The scale and diversity of our assets allowed to us overcome some operational hiccups that were mainly weather-related. I'll walk you through the five businesses and explain to you what I mean.

On the East Coast, Mother Nature threw all she had at us. We had seven hurricane-force storms this winter, winds exceeded 200 kilometers an hour, and 23 meter waves were recorded. That's 75 feet, for those of you south of the border.

Both Hibernia and Terra Nova performed well despite the weather. We did have to reduce production at Terra Nova for several weeks in late February and early March because we couldn't offload in the high seas. The waves actually did some minor damage to a shuttle tanker, but offsetting that we were able to avoid a planned shut down for some deck repair work, so we still managed to meet our production targets for the quarter, which speaks well of our capability to handle the extreme weather conditions of the North Atlantic.

At White Rose dredging of the glory holes has started with drilling scheduled for this summer. The keel for the busser was laid and construction of the turret is progressing. So things are going well but it's still early days. We should have a better fix on the overall project schedule by the end of the year.

Weather also delayed the [INDISCERNIBLE] semi-submersible which drove the [INDISCERNIBLE] prospect in the Flemish Pass. We reached total depth mid-April. We found reservoir of sand and oil, which is good news, but the quantity was non-commercial. We're on location at Tuckemore (phonetic), our second prospect in the Flemish Pass and we spudded that well yesterday.

Moving on to oil sands, that business had a mixed kind of quarter. At Syncrude, following a six-month run of solid operations, production fell off in Q1 because of extended planned and unplanned shutdowns of both the Aurora mine and at the Upgrader. So there's still work to be done to ensure consistent reliable operations at Syncrude and management is clearly focused on this going forward.

MacKay River continued to ramp up production in the quarter, averaging 13,200 barrels a day. We're still in startup mode there, very much learning as we go and fine-tuning the operation.

On the good news front the Oil Sands team has done an outstanding job on the regulatory side. We now have regulatory approval for the Edmonton Refinery conversion project. Because the team directly addressed all stakeholder concerns and interests public hearings weren't required, for either the refinery project or for Meadow Creek. Really a tremendous accomplishment.

We had originally expected to be advancing these projects on to detailed engineering at this point. However, the cost estimates we're seeing for the refinery conversion at this stage, based on recently completed projects, are much higher than we expected.

So we're refocusing our efforts on alternative approaches to make sure we're not passing up the more attractive configuration than the one we have right now. We're looking at overall scope, smaller or larger, and the choice of technology, [INDISCERNIBLE] versus [INDISCERNIBLE]. We expect to have these analyzed by the fourth quarter and we'll make a decision then on which way to go.

To date, we've committed about $300 million of capital on engineering and site preparation for the original project concept. Once we settle on the direction we're headed, we'll have a better handle on how much of that 300 million will be of value in our alternative scheme. What isn't of value will be expensed against earnings at that time.

We're taking advantage of the extra time this creates to also consolidate our earnings for the Meadow Creek design. We're looking at phasing to make project execution more manageable. We'll incorporate last winter's delineation results, and our reservoir model will benefit from pilot experience from two well pairs that have been running for a year and a half at the nearby pilot plant. We plan to use the coming months to incorporate all of this into a fourth quarter decision on how best to proceed.

When we started down this path, we deliberately took a phased approach to the whole strategy in order to learn as we go. And that's what we're doing. The objective of an integrated oil sands venture remains the same. It may take a little longer to get there, but the trade-off is worth it. We're taking a disciplined approach to capital investment to ensure that these long-run projects are value creative.

Moving on to North American Gas, this is a business where the cold winter worked in our favor. Our gas business delivered exceptional earnings in the quarter, as a result of high gas prices and solid operational performance.

Western Canada production averaged 714 million cubic feet a day, and that's excellent performance. Consistent with our on-going focus on profitability in Western Canada, we put two smaller noncore properties in Central Alberta up for sale. These are mainly oil-producing properties that represent about 3400 barrels of oil equivalent per day.

Meanwhile, we continue to look for natural gas in Canada's newer basins. In the McKenzie Delta we suspended drilling of the [INDISCERNIBLE] exploration well in mid-April due to breakup. We'll make a decision later this year on whether to complete the well next season.

Our accomplishments in the North Sea demonstrate the successful execution of our international strategy. Our two non-sea developments are on track for startup in early 2004 as planned. The [INDISCERNIBLE] Project will initially add 15,000 barrels a day and will be tied into the Tradenet PSO and the [INDISCERNIBLE] gas discovery should add about 12 million cubic feet a day in the Dutch sector.

In April, we reached agreement to exchange and acquire properties in the U.K. sector from Shell and Esso, resulting in a net investment of $65 million. The assets are close to the Tradenet PSO. The move will increase our working interests in the [INDISCERNIBLE] west and Northwest fields and our ownership in the Tradenet PSO.

The purchase also includes the undeveloped [INDISCERNIBLE], one that's similar in size to Clapham. We plan to tie in [INDISCERNIBLE] at a later day, to maintain utilization of the FPSO. This is an excellent example of our strategy to bring on profitable production close to existing infrastructure.

I'll also note that we started up the En Naga project in Libya. Initially the project will add some 3,000 barrels a day of production and there may be an opportunity for further field development down the road.

Returning to our Canadian business, our downstream had a record quarter with earnings of $130 million. The refining side of the business turned in excellent results, thanks to high cracking margins.

However, we did have some reliability issues here. Cold weather played a part in a minor fire at the Oakville (phonetic) refinery in January and shut down about half of the refinery's capacity. Our people there did a great job of containing the damage and minimizing the downtime. All areas of the refinery returned to production within two weeks.

Both lubricants and marketing faced a tough business environment. High crude prices put a lot of pressure on marketing margins, but we did continue to make progress in our gap closure initiatives to improve returns to 12% at mid-cycle margins.

Retail gasoline sales were up 4 percent over last year, and we increased nonpetroleum sales and the sales of high margin lubricants in the quarter.

Our regularly scheduled spring refinery turnarounds are going according to plan. Work has already been successfully completed at the Edmonton refinery, and a short crude unit outage at Montreal is all that remains to be done.

So that's the business unit round-up. On the corporate side, we put ourselves back into excellent financial shape. In less than a year, we've repaid $815 million of the 2.1 billion of debt taken on for the international acquisition. So we're strong financially and we have the capacity to pursue more opportunities.

In March we announced that Norm McIntyre, President responsible for international operations, will retire in the first quarter of 2004. I'll say more about Norm's outstanding contributions to Petro-Canada closer to his retirement date, but for now, I want to tell about you the succession plan we've put in place.

We're very pleased to have Peter Callus (phonetic) joining us in May. Peter is a former executive with Enterprise, and then Royal Dutch Shell. Since Gary Bruce is also retiring, we'll have Peter get to know the company by taking over corporate planning and communications responsibilities here in Calgary for the remainder of the year. Our intention is to move Peter back to London next year to take over for Norm. So I want to thank Gary for all his efforts, especially in building our East Coast business, and to welcome Peter to the company. Peter looks forward to meeting many of you in person over the next few months.

To conclude then, it was a solid first quarter. The expanded scope and diversity of our assets showed their true value in what was truly an extraordinary business environment.

Thanks for your attention and I'll now pass it over to Harry who will fill you in on some additional financial details. Harry?

Thanks, Ron.

There are four things that affected results in the quarter that I wanted to touch on. First, you should note that earnings from operations in the quarter include a $46 million charge to DD&A in international. As we are currently considering our options for our account extend interest, we reviewed the carrying value of the assets in light of a potential sale. As a result, we took the additional charge to DD&A.

Second, the impact of foreign currency translation. We benefited from a $94 million gain related to foreign currency translation. This gain is reflected in the revaluation of our U.S. dollar denominated debt, thanks to a strengthening Canadian dollar.

Third, two factors that affected cash flow from operation. Tax deferrals resulting from our Canadian upstream partnership, increased cash flow by approximately 70 million in the quarter compared to a decrease of 50 million in the first quarter of 2002. The LIFO-FIFO effect in the downstream lowered cash flow by about 36 million compared with a reduction of 35 million last year.

And fourth, in case you missed it in our statistical supplement, we have increased our estimate of Hibernia proved, plus probable reserves, up from 730 million barrels to 835 million barrels, thereby lowering DD&A per barrel. In addition, though, we have also increased the provision for abandonment costs to both Hibernia and Terra Nova. Overall, the two changes offset each other and total East Coast DD&A basically remains unchanged.

Thank you, Harry.

Operator, that concludes our prepared remarks and we're now ready to open up the lines for questions.

Thank you. Ladies and gentlemen, if you'd like to register a question in today's conference call, please press the one, followed by the four on your telephone. You'll hear a 3-tone prompt to acknowledge your request. If your question is answered, however, and you would like to withdraw your registration, then press the one, followed by the three. If you're using a speaker phone, please lift you handset before entering your request. One moment, please, for our first question.

And our first question is from the line of Mark Flannery with Credit Suisse First Boston. Please proceed with your question.

Yes, hi, thanks. This is a question, I guess, for Ron. Do you think you could put some more color on the size of the increase in the estimates for the Edmonton refinery conversion, versus what was perhaps in the original plan, either in terms of percentage or millions of dollars?

And the second part of that question is, am I right to assume that you're backing away from this investment, or at least let's say, recasting this investment, because you're bumping up against return hurdles, or at least failing to clear some of your return overturn hurdles?

Hi, Mark, let me see if I can help you out a bit there. The numbers that we had originally in our investor relations presentation for the first phase of the refinery conversion project were a range of 2.4 to 2.8 billion. And those date back to late 2001, early 2002, just after we filed the application with the energy utilities board here in Alberta. So they're right now close to a year and a half old.

We have been seeing these costs creep up a little bit over time as we progress through some early engineering and early definitional work, and more recently we saw these jump up by about the same order of magnitude that you've seen the cost increases in similar projects like Shell's project, the estimate of the Syncrude expansion project and the cost escalation that Suncore saw in their Millenium project. So in terms of order of magnitude, it's not unlike that the cost increases that we're seeing in those particular projects.

Your question about recasting the project at this stage, your assumption is essentially correct. Obviously, when you get that sort of cost escalation on the front end of a project, it really starts to impact the overall economics quite considerably.

While these projects, at the original cost, were reasonably robust, we're at a point where they're starting to look pretty marginal from an economic point of view, at least the concept that we originally embarked and which we've been pursuing here the last year and a fifth.

So our intention here is to look at alternatives at this stage and see if we can't find a solution that's much more economic. I indicated that might be bigger, it might be smaller, it might be different technology. But certainly, our intention is to achieve the same objective, integrated oil sands project, but we're going to take a little more time to sort out exactly what that might look like.

Great, thank you very much.

The next question is from the line of Mark Gillman with First Albany Corporation. Please proceed with your question.

Hi, Ron. A similar subject: I'm trying to understand the extent to which this hiatus also applies to Meadow Creek, and whether I'm reading a little bit too much between the lines in terms of your comments regarding delineation and pilot operations to suggest that there are separate reasons for kind of taking a step back on that. Is there a linkage between the decisions here?

The two are related, Mark. You know, our concern all along has been moving too much raw bitumen into a marketplace that might ultimately become somewhat oversupplied, and that was the thinking behind their integrated strategy. Of course, we originally were intending to start up Meadow Creek at the same time as the refinery conversion project so that we would have the integrated solution in place.

With the delay in the startup of the refinery conversion project, we also want to take a look -- take advantage of that time to really look more seriously at Meadow Creek. I think, for example, we would proceed on the basis of breaking that up into two different phases.

For a couple of reasons. One, the marketing issue that I discussed earlier. And two, we think that that would give us a more manageable project because the components will be about the same size at that stage as Meadow Creek and MacKay River. MacKay River gave us the confidence that we could execute that scale of project on time and on budget. So the two are very-- quite closely related, Mark.

But there was nothing about the delineation program or the pilot operations that gave you pause with respect to Meadow Creek, just focusing specifically on that project?

Our strategy all along is to learn as we go, and what -- we're wanting to make sure that we understand and can incorporate the pilots that have been operating for about a year and a half now, in fact, in an adjacent lease, so that we incorporate what we see from that performance into our design for Meadow Creek. So this really gives us an opportunity, if you'd like to take advantage of some more information.

We also have this winter's drilling program that we haven't really fully integrated into that picture. And obviously, if we're going to break this thing up into two pieces, we have to think about where the sweet spot is in that larger reservoir opportunity and make sure we position it properly.

Just ask you one other question on MacKay. What kind of steam oil ratio have you been running? Is it too early to evaluate that issue?

It's still pretty early. We're running in the, sort of, 2.5 to 3 range, Mark. One of the difficulties we've had there, quite frankly, is with the reliability of our steam-generating equipment. The reservoir itself is performing very much as we expected. We're basically tracking the kind of production performance of steam oil ratios that we've had in our models. So that part of it is performing quite well.

But we've had some issues of oil carryover into the steam generator from the oil-water separator, and, in fact, we've had three of our four boilers down in the month of April for a period of about two weeks, and what we're finding, is that, particularly as you're ramping up production, production is obviously very sensitive to the amount of steam that you're putting in the ground. I think it will become less sensitive once you get the reservoir fully saturated with steam, and it's more on a, sort of, a steady state basis.

But right now, the production levels are quite sensitive to steam, and when you take the motors out for a couple of weeks, that makes a big difference in production. But the important thing to us is that the reservoir itself is performing, because that's the real asset behind this long-life project and the steam boiler issues are fixable without any dents, so--

Okay, Ron, thank you.

The next question is from the line of Brian Dutton with UBS Warburg. Please proceed with your question.

Yes, hi, Ron. A couple of questions here. The first is on the East Coast. It looks like the regulator in Newfoundland has indicated that Hibernia production was extremely strong in March and produced on average just over 217,000 barrels a day. Have we seen a change there in the regulated allowable rate for Hibernia?

Hi, Brian. Hibernia has been performing quite well, as has Terra Nova, by the way. Both of those fields are producing exceptionally well. And we are, in fact, applying to increase the annual allowable average rate at Hibernia to more closely match what we now see the reservoir and the facility being capable of.

Our strategy there is the same as it's been at Terra Nova, to make sure that the allowable rates themselves aren't limited. In other words, we want to be able to engineer the development of both of those fields, so that we're -- we're not bumping up against artificial limits, but rather the limits of the reservoir and the limits of the facility combined.

Were you running a test there for the month like you did back in November for Terra Nova?

We have been able to run these fields on a single day basis in excess of the annual allowables, so that's what we were doing in March. We had -- I mentioned that we had some weathered-related problems in off-loading crude at both Hibernia and Terra Nova because the shuttle tankers weren't actually able to get up to the offloading buoys. And a lot of that happened in late February, early March, so what we did in March was run a little harder on both of those fields, and try to make up what we lost in the weather-related down time.

Just a second question, if I could. On the downstream, very strong earnings in the forward side. Could you maybe give us a little bit of light in terms of the contribution in the C-store sales?

C-store sales are running about 20 percent ahead of last year, which is basically what we would have expected for this year. I think you heard me talk last quarter about the success we had. For the calendar year 2002, we were actually running 30 percent ahead of the prior year, and at least our business plan didn't call for us to keep up that extraordinary performance, so 20 percent ahead of lasts year is pretty impressive from my point of view, and it's basically on track with our business plan.

Great. Thank you very much.

Then our next question is from the line of Wilfed Gobert with Peters & Company. Please proceed with your question.

Thank you. Ron, could you, or one of the guys, just review with us what the annual rate capacity at Hibernia and Terra Nova are right now? I understand from the Husky conference call that Terra Nova has increased to 175,000 barrels a day. Is that right?

I think Gordon has those numbers. I'll pass you over to Gordon, Wilf.

That's right, Wilf, we did apply to increase the allowable production at Terra Nova and we now have an average annual allowable rate of 180,000 barrels per day, and that's the same, whether you look at it on a daily basis, or an annual basis, it's 180, in total.

But, of course, that exceeds our productive capacity right now. With the number of wells we have grilled in the reservoir we could, at best, average something in the 160 to 170 range on a max daily. So, I think, back on Ron's comment about we don't see the regulated level as a constraint for us at Terra Nova.

Is that okay, Wilf? Is that what you were looking for? Hello?

Our next question is from the line of Martin Molyneaux with FirstEnergy Capital Corporation. Please proceed with your question.

Good afternoon, gentlemen. First off, congrats on the new and expanded level of disclosure. I think all of us who have to work with your numbers really appreciate that.

My question is, in terms of, well, on the marketing side, obviously an absolute bang up quarter. What are you guys think about going forward? Have we gotten off to a strong start to Q2 and any thoughts for the balance of the year?

Are you thinking about margins, Martin, or --

Yes, just margins. This is obviously well above what your previous expectations were, and I guess most of us on the phone. But what -- what does your crystal ball tell you for the balance of 2003, or even just going into the summer here, positioning-wise?

The situation we saw in the first quarter, you're right, was quite extraordinary. I think we're all pleasantly surprised with that. And it arose, principally, because of refineries carrying very low inventory, because of the crude price they were seeing, and the [INDISCERNIBLE] in the forward market which suggests that you ought to reduce and minimize your inventory in anticipation of being able to build up lower prices in the future.

So whenever you get a situation like that, any, sort of, either an interruption in supply or a little pressure on demand from cold weather, which happened, because of the increasing demand for heating oil, in particular, you tend to get some pretty robust margins, and that's exactly what happened in the first quarter.

So clearly, those kinds of margins aren't sustainable. I think we're seeing crude prices come off now. I suspect we'll see refiners starting to rebuild inventory, and as a consequence, we'll see margins come back to more of a long-term sustainable average level.

Okay.

That would be my expectation, but you know, this is a -- you know as well as anyone, this is a very volatile business.

Yeah.

And why that's we purposely track our performance on a mid cycle basis, because that's the way that we understand whether we're actually making progress in the fundamentals or not. And even underlying all of this extraordinary business environment in the first quarter, we did make progress on our midcylce returns when you strip out all the margin impact.

Okay. One question on the upstream side. In terms of Syrian volumes, it looks like they slipped a little bit in the first quarter. Is it just natural declines that are going on there, and if so, what can we expect decline-wise there? Any thoughts on that?

Syrian is a relatively mature area, Martin, and we -- Shell and [INDISCERNIBLE], the operating company that we are a part of, have had a program in place for some time to sustain that production level as best as possible.

But obviously, you're fighting decline in a relatively mature -- in fact there's a number of fields involved here; it's not just one field. They're all relatively mature, so I would expect that over the course of the year, we may see some slippage in volumes coming out of Syria, just because of the need to try to sustain production in a relatively mature area.

Okay. Good enough. Again, congrats on the big step forward in the disclosure.

Thank you. Okay, Gordon Richie's smiling over here.

This is the conference operator. For information, the line of Mr. Wilfed Gobert got disconnected during conference. Therefore, he was not answering to your question.

The next question is from the line of Andrew Fairbanks. Please proceed with your question.

Good afternoon, guys. Curious as you look at something as complex as an integrated oil sands project, do you evaluate that as essentially three separate projects that need to stand on their own? The oil sands production project itself, the upgrader, and the modifications of the refinery, or do you truly look at the whole thing as a singular completely integrated project, and the economics have to stand on an integrated basis?

We look at it both ways, Andrew, because we, theoretically, we have the option of proceeding with either one or the other pieces.

There's another element of this, actually, that you missed on your list there. There are actually three pieces. There's the upstream piece, and there's the upgrader piece, but intermixed in all of that, too is the requirement to make some investments to reduce both sulphur gasoline and sulphur and distillin.

So when you start looking at the configuration that makes sense, in this path that we were pursuing, for example, we were anticipating running our bitumen in this refinery, and as a consequence, we have made a certain level of preinvestment and desulphurization for both gasoline and distillin.

So, you're right, it is a complex issue, but we tend to look at it both in pieces, and that's the determining criteria of whether we proceed or not with any individual piece. And then we tend to look at it as a whole, just to see whether the strategy itself is going to be economic in the long run.

That's great. And then also, as you get your arms around, you know further oil sands developments in the current marginal economics of oil sand developments, and you also are getting a sense for the kind of opportunities within the Veba international set, is there is a balance point that's changing there? For example, as you look at the economics of oil sands, vis a vis international opportunities, do you see, potentially, some international opportunities there becoming more intriguing to you?

We're very opportunistic about where we choose to spend our money, Andrew. Starting from a very disciplined base. I mean, we're, I won't say totally indifferent, but we're quite anxious to invest either in Canada in the oil sands, or internationally, and preferably both.

We have a study underway, in fact, since we're basically finished with the integration of the Veba assets into Petro-Canada. A couple of months ago, we kicked off a study to really look at where the growth opportunities are, not only within the countries that we currently operate, but other new theaters that might be of interest to us.

And I expect that we'll be able to bring that to some conclusion here toward the end of the year. So, in a sense, all of this is all coming together some time in the fourth quarter, and it's all aimed, if you'd like at our putting together a business plan, not just for 2004, but one that goes beyond that and looks at the kind of growth opportunities we might be able to identify and capture.

I guess one area that's probably early days, but would be curious if you would consider it. Post-war Iraq, would you consider that as, you know, a potential fourth major element within international?

It's pretty early to comment on that, but Iraq is a country that's, at this point, still on the list. We haven't really sifted and sorted through, where we might want to put our efforts and our capital in the early going, but Iraq is still on the list from that perspective.

That's great. Thanks, Ron.

And our next question is from the line of Bud Lyon with CI Mutual Funds. Please proceed with your question.

Hi, good afternoon, everybody. Again, just to reiterate Martin's point on the disclosure. Thanks for that. Every bit helps.

A couple of questions. Got to keep logging this Meadow Creek, Edmonton a little further. As it stands now, your latest cost estimates, if you're unable to get those costs down significantly, or get that project reconfigured, would it be your best guess at this point in time that that project would indeed not be a go?

You mean the original concept, is that what you're talking about?

Absolutely.

To be honest, I think we have pretty good numbers for the original concept and the technology. The engineering firms that we've been working with are the same ones that built the L.C. finer Shell, for example. We've hired engineering firms that have recently built sulphur plants and hydrogen plants, which are the other big components of this thing. So we're reasonably confident that we're looking at good data.

Now, whether we could progress the project in a different way and make the economic turn out a little differently, break it into stages -- You know, we've look at a very superficial way, at that and we think that might be a way of reducing the costs. But when you stretch a project out over a longer period of time, even if the costs are lower, it doesn't necessarily improve the economics because you've got a lot of underutilized capital in the interphases,if you like. You don't you really see the full benefit until you get the final piece in place. So it's a bit tricky to manage and it's just one options -- at this stage, we wanted to consider other possibilities than the one we've been currently working on. That's the real thrust of our study.

Okay, on a different topic for a minute. The lube business, I know you don't, sort of, segment out those earnings. One of the companies south of the border that's fairly active in the lube area mentioned that their margins, year over year were down in the order of magnitude of four bucks a barrel, predominantly on the lube cost run-up. Can you comment at all? Would I be completely out to lunch to say the same thing for Petro-Canada year over year?

We saw the same sort of pressure, Bob, particularly in January and February --

Yep.

With the crude price run up. We had a real struggle in lubes to try to maintain any sort of decent margin in that business.

The month of March was a little better, quite frankly, and one -- there have been some price increases put in place, the market price is effective April the 1st. And with the drop-off in crude prices, if those prices maintain, we should see some improvement in March and as we go into the second quarter here.

But no, when I mentioned that in my remarks, we did see some pressure on lubes because they get hit pretty hard with the increasing feed stock cost, and it's a difficult business in most segments to pass through any cost to the customers.

Sure. Okay. Yeah. And in terms of the sales mix, in terms of your mix of sales into the higher margin area, still happy with the direction that's taking?

We're still making progress on that, quarter over quarter, so that's going well.

Thanks very much.

Our next question is from the line of Leslie [INDISCERNIBLE] with the Ontario Teachers' Plan. Please proceed with your question.

Thank you. I apologize, but I'm still struggling a little bit with getting my arms around the Edmonton reconfiguration. I mean, there were so many customer runs with Shell and Sinclair and Syncrude at different points in time, would you be able to say that your estimate today would put you somewhere 30 to 50 percent above where you originally thought? Would that be an accurate range to assume?

I wish that were the case. The numbers are bigger than that, Leslie. If you look at the actual cost overruns from the original numbers that Shell, Syncrude, they're probably the best analogs for what we're talking about here. The numbers were actually bigger than that, and that's the sort of thing we're experiencing.

Okay. Can you say to what level, and when I say level I mean, percent of cost increase, you need to contain the budget to in order to proceed with this? Do you need to get the costs down to 50 percent greater than they were going to be, in order to go ahead and have a project with good runs returns?

Well, you have to look at a number of different aspects of the project, Leslie . One approach would be to try to get the cost down on what it is we had been pursuing. And as I indicated, we don't have a lot of hope for that, simply because we think we've got pretty good numbers from the engineering firms on that.

So the alternative is to look at a different approach, a different technology. Look at coking versus hydrogen addition, for example. Perhaps a different scale of projects that we had originally, so we're looking for something that changes not only the cost, but also the yield. Either in terms of throughput or in terms of what you get out for a barrel going in.

And it's that combination that we're looking for to try to improve the overall value added of the project itself. Ideally, we'd like to get somewhat close to the same earnings in cash flow impact with less capital using different technology, but that's the challenge that we face.

Okay. There is an impact, or there is a change on your capex budget for '03 now as a result of this deferral?

We had originally intended to spend in the order of $180 million for this detailed engineering package, had we gone forward into the fourth quarter, and we'll now end up spending about 60 million.

Okay.

So that piece of it will come down. On the other hand, I mentioned we were successful with this acquisition in the North Sea that has about 65 million of acquisition costs associated with it, and eventually some capital-- I guess not much of it will come in this year. There are going to be some puts and takes as we go, but I would guess our capital program this year will end up a little less than what we had indicated back in September, or December, I should say.

Okay. Just one final question: I noticed in your disclosures that the capital employed in shared services has gone down from 950 million to 190 million, I think. Could you shed some light on that for me?

I'm turning this over to Harry. He's thumbing through his notes. We're going to have to get back to you on that, Leslie. Can we do that?

Yeah, that's fine. No problem.

We don't seem to have that readily handy.

Okay. Thank you.

Our next question is from the line of Robert Plexman with CIBC World Markets. Please proceed with your question.

Hello, Ron. I have two questions for you this afternoon. First on the international side, when Petro-Canada bought Veba last year, at that time you mentioned that you would be taking a look at the assets and deciding which were core and which and then which were really noncore to Petro-Can's future. Just looking at the first quarter, the Kazahkstan assets, obviously, are not regarded as core. Are there other potential assets, regions that you're looking at that may also, over the near term, show up as being noncore and subject to dispositions. That's the first question.

The second one, a different region, the Mackenzie Delta, if the pipeline is constructed for 2008, would you expect to be a shipper?

On the international side, Robert, the only one that we've taken a decision on, at this stage, is Kazahkstan, I think the other one that we had flagged was Algeria because we have a declining, almost depleted oil field there. But we're still in discussions with the Algerians on a potential four field gas development. So, it's too early to say whether that's either a go or a grow situation. That's basically the choice that we're facing.

On this question of the pipeline, we have, on the basis of our discovery well in the Tuck Peninsula, we have nominated for capacity coming out of that field into the pipeline, so that we would be in a position to be a shipper, if that were to start up as early as 2008.

Okay. Thanks very much, Ron.

Our next question is from the line of Paul Cheng with Lehman Brothers. Please proceed with your question.

Good afternoon, gentlemen. Ron, on the oil sand of the Edmonton refinery reconfiguration, could we assume that after you go for a more thorough review, and the [INDISCERNIBLE] with the economics [INDISCERNIBLE] to maybe integrate the project, you probably would not pursue further the oil sands expansion. In other words, the oil sands expansion, that would need to be an integrate [INDISCERNIBLE] or just go ahead and produce the bitumen?

I think it's too early to make that call, Paul, because there are a number of options open to us here. It depends on, first of all, what kind of solution we come up with.

We do have all the right components here. We've got the resource base on the upstream size. We've got a refinery site that's in the right location, and we've acquired some lands and we've got some space on the refinery site, and we've moved some tanks to allow us to expand the unit area. We've got a lot of the pieces in place and I think it's a matter of us really finding what the right configuration is that makes sense from a value adding point of view. So we're certainly not in any position to speculate at this time how it might come out.

On the other side of it, would we continue to produce bitumen? We've always felt that there's room for more of bitumen in the marketplace. The issue has been that there's probably a limit to that. So I did mention that one of the strategies that we're looking quite seriously at now is breaking Meadow Creek into two pieces and that would certainly allow us to stage it into the marketplace, if we chose not to go ahead with the large integrated project or if it ended up getting scaled back, and meant that we would be putting some raw bitumen, or perhaps, partially upgraded bitumen into the marketplace.

So there's a whole range of possible outcomes here, and it's just too early to speculate on how that might turn out.

Ron, is there a definitive hurdle rate, like a 15 percent return, or something like that that you guys had in mind before that supporter will be able to go through; that they'll have to clear that hurdle?

No, normally we start out in the early stages, looking for 15% return, Paul, and as we get more definition on the project, and more confidence in our ability to execute to a specific capital number, in particular, we'd be willing to accept something more in the low teens, particularly if it's in a low risk area like Alberta. So it depends, a little bit on the nature of the project and the stage that you're at and the kind of confidence that you have in being able to deliver on it.

Thanks, Ron. If I could ask two simple questions. I think one is for Harry and one is for Gordon.

Harry, wondering, if you can give us a number with the delay in the Edmonton reconfiguration [INDISCERNIBLE], I think Ron mentioned that about 180 million, the regional budget for this year. How about for next year, for 2004, how much of that is budget?

Secondly, for Gordon, can you give us a fully diluted share count?

We haven't disclosed the budget for 2004 yet, so I won't be able to give you a number on that issue.

This is Ron. I'm not sure if I was clear on the impact on 2003. We had originally expected to spend 180 --

Right.

And I'm not sure if I mentioned that we'll be going ahead to spend about 60 of that.

Yes, I get that. I just want to get a rough idea of how much is originally expected in 2004 and if we assume that it's going to be further delayed?

We haven't put out numbers for 2004.

I think it's fair to say that it's too early to tell what the impact will be for 2004. On the fully diluted shares, the fully diluted shares, the quarter were 267.3.

Thank you.

We have a follow-up question from the line of Brian Dutton with UBS Warburg. Please proceed with your question.

Sorry, Ron, to belabor the point on Edmonton, but just to clarify, the technology that you're doing all your original cost estimates on, was that the hydrogen addition technology?

Yes. That was LC fining, basically the same technology that Shell has in their plant.

Okay. And Harry, the second question, just on the pension position, are you now expensing in the quarter, topping up on the pension?

In the quarter, we are -- we're expensing, I'm trying to think what it was. It was about 55 million for the year, so for the quarter, we would have taken -- that was about 14 or 15.

Okay. Great. Thank you.

Our next question is a follow-up question from the line of Mark Gillman with First Albany Corporation. Please proceed with your question.

I'm interested in understanding what didn't work at [INDISCERNIBLE]? I assume it's either seal or [INDISCERNIBLE] and how Tuckemore might be different from it, potentially?

Yeah. At , [INDISCERNIBLE], Mark, we did find hydrocarbons, we did find reservoir. The issue was insufficient hydrocarbons to make a commercial accumulation.

So the good news we take away from that is that there's a workable hydrocarbon system in that basin, which is -- which takes away, quite frankly, -- at least some of the basin risks. Tuckemore is in a different horizon, so to a large extent, it's independent of the results of [INDISCERNIBLE]. In fact, we would not have scheduled these two wells in sequence if that weren't the case.

And if I could just go back to Hibernia for a second, I'm turning to the contribution of Avalon, to some of the recent production numbers, and I don't think you answered the question previously as to what, in fact, the allowable currently is at Hibernia.

Yes, I've got the number.

Yes, on Hibernia our annual allowable is still at 180,000 barrels a day, but our daily allowables have been increased from 217,000 to 231,000 barrels a day. And we do have application in -- or HNBC has an application in, to move the annual allowable number up into the -- into those higher levels, north of 200. So that is underway, but the way it stands work those are the two numbers.

I'm sorry I missed the question. Your first question had to do with the Avalon?

Yeah, what kind of contributions to the overall Hibernia numbers are you getting from the Avalon?

I'm sorry I didn't catch that.

What level of contribution to the overall Hibernia numbers, Ron, are you getting from the Avalon?

Oh, okay. I got ya. The original 730 million barrel proved and probable had 115 associated with the Avalon. The rest of it associated with Hibernia sands. The increase of 105, that we just marked up, was split about 70 percent in the Hibernia sands, and that's largely a result of additional oil in place as we drilled up the reservoir. And the other 30 percent is associated with the Avalon.

Now, in the case of the Avalon, we're not exactly comparing apples and apples here, because what we're recognizing in the current number is the fact that we've been able to establish a water flood in a concentrated area of the larger field that is producing reasonably well. In fact, the anticipated recoveries in there are in excess of 20 percent.

You really shouldn't extrapolate that to the entire Avalon field, because we obviously started with the sweet spot here, and our strategy over time is to delineate this a little further and establish whether this reservoir can justify actually putting in a subsea development and tying it back as an entity into the Hibernia platform. Is that the sort of thing you were looking for?

Yeah, Ron. So that the reserve increase on the Avalon is essentially taking that recovery rate from single digits up to the 20 in the sweet spot?

Exactly.

Okay, got it, thanks.

And it's because of the water flood performance that we're seeing in the early development there.

The next question is a follow-up question from the Bob Lyon with CI Mutual Fund. Please proceed with your question.

Hi. A couple quick things again.

One more time on Edmonton, have you guys, in light of Sun Corp.'s recent move, does that impact your thinking, at all, in terms of the range of the possibilities for upgrading bitumen?

Are you thinking about their purchase of the refinery in Denver?

Exactly. Is that anything along those lines remotely an option for yourself, is that possibly another scenario?

The way I see that, Bob, is we have the refinery already in Edmonton, which is actually a preferable location, from that point of view, to Denver --

Sure --

So the question may be, is there some commercial opportunity that may exist between ourselves and Sun Corp? And that's something that we would certainly be interested in pursuing.

Okay, fair enough.

There's a whole range of possibilities here that, we don't want to rule anything out at this point. We'll start with a very broad base of ideas, and we'll chase each of them until we find the right answer.

All right. One more point there: In terms of the timing and and seeing what's been going on in the various oil sands projects, like these cost overruns have been kind of over there for some time. Have you seen a slow build for this project, or did you suddenly get a new estimate back, that sort of came in the door during the quarter? Can you just walk me to through the process a bit as to how, you know, how we came up, sort of, now with the, sort of, cost overrun estimate?

No, this didn't appear all of a sudden out of nowhere. We did see some creeping up overtime, as I indicated earlier, as we worked the engineering. And at the time we put our business plan together last fall, in November, not that long ago now, we had numbers that still made sense for us. We were looking at returns down in the low teens, and as I indicated, if we had the confidence that we could execute on that number, then we would have been quite happy to proceed.

It's only in the last month or so, mostly, when we shifted from the, sort of, basic engineering concepts into engaging the engineering firms that actually did the work for Shell, and as I indicated before, built some sulphur plants and hydrogen plants recently, that all of this started to come together and the numbers started to pop up and that's when the alarm bells went off.

Thanks. I'll top it off. One more, an easier one, if I can. The Hibernia, what is the best single daily rate you've gotten out of the reservoir so far?

I'm guessing it's in the range of 220, Bob.

All right.

I don't know that I have that number anywhere.

Fair enough. Thanks again, guys.

And our last question that is presently registered is from the line of Andrew Fairbanks with Merrill Lynch. Please proceed with your question.

Hi, Ron. I wonder if could you just give us the latest updates on the Venezuelan [INDISCERNIBLE]?

Yeah. The [INDISCERNIBLE]. We have actually reestablished contacts with the new organization of [INDISCERNIBLE], and are starting to look toward some discussions with them that would get this process back on track again. We lost a few months, obviously, because of the upheaval down there. Things are getting back to normal, at least from an organizational point of view. So, we're trying to get this thing back on track but t's still very early days.

I guess it's hard to guess, but would you see that as potentially a six-month process, twelve-month process to bring that to conclusion?

I'm hesitant to try to put a prediction on that. It's possible we could see something by the end of the year, but I've said that before, too.

Okay, fair enough. Thanks a lot.

There is a follow-up question from the line of Martin Molyneaux with FirstEnergy Capital Corporation. Please proceed with your question:.

Ron, with the really strong first quarter, generating almost a billion dollars, it looks to me -- and there are numbers that you're going to pay down debt by something in that range of about a billion dollars in 2003, and obviously, Edmonton refineries is a much bigger question mark for capital expenditures over the next 2 or 3 years. When you and the board met yesterday, any discussions on what to do with the financial flexibility and any thoughts on increasing the dividend?

We had some discussion on what to do with the cash cash, Martin, and it's basically the same strategy we've been advocating all along. Our first priority will be to look for quality investment opportunities.

Our second priority would be to pay down debt to the point where we're happy with the leverage on our balance sheet. And our third priority would be to return cash to the shareholder, either through some sort of a buyback or reconsideration of our dividend rate. We really haven't changed our thinking on that at all.

Okay. With -- with the scenarios that are coming down in terms of Edmonton and [INDISCERNIBLE] exercise, has the London group been seeing more deal flow?

I'm sorry, seeing more --?

More deal flow? Are you, now that Veba has a great balance sheet behind it, are perspective acquisitions coming at you more freely?

Very much so. I think, first of all, being London, is quite important from that perspective. Because that tends to be one of the key centers for deal flows in the international arena.

And secondly, our name recognition is starting to make a difference for us, so we are getting a lot of visitors, a lot of offers, and it's exactly the situation that we'd anticipated when we made the acquisition. And this is all part of piecing together the study that I mentioned earlier in deciding where it is we want to go and where are the entry points and how aggressive do we want to be in these different areas.

Okay, finally to kind of clean up something here: Are my numbers right, you pretty much paid down about 40 percent of the Veba purchase price?

We originally borrowed 2.1, Martin, and of that amount we've repaid 811, so -- yes, 39 percent.

Right.

That's pretty close.

Thank you.

The last question that is presently registered, it is a follow-up question from the line of Mark Gillman with First Albany Corporation. Please proceed with your question.

Ron is there is an oil and gas reserve number that goes with that U.K. asset transaction?

It's about the same size as Clapham, Mark. It has two wells in it. So we have an intersection of both the oil-gas contact, and the oil-water contact, and the reserve range is anywhere from 10 to 15 million barrels.

Net to the interest you're acquiring?

It's 100 percent. 100% Petro-Canada.

Would you just comment on the asphalt business in the first quarter? I mean, I assume you probably took a pretty good hit on that?

I have -- I can't -- I really can't comment on that, Mark. I'm not sure how our asphalt business fared in the first quarter. It's not usually a big factor for us.

Accepted margins probably were nonexistent or substantially negative for the same reason that the lube situation was what it was?

Except that the volumes are significantly lower in the winter months than they are in the summer months.

Okay. Thanks, Ron.

Ladies and gentlemen, as a reminder, if you'd like to register a question at today's conference, please press one four at this moment.

There is a question from the line of Mark Heim with Yorkton Securities. Please proceed with your question.

Thank you. Can you comment on the long-term price deck you've used in identifying the economics at Meadow Creek and the Edmonton refinery conversion. Are they still around 21 bucks for WTI?

Yeah, we're still using $21 WTI, and the long-run light/heavy spreads for those economics.

All right. And if you were to not go ahead with that project, do you have capabilities or potential to basically just run sour synthetic and sour light through your Edmonton refinery and capture the increasing differentials that we're starting to see in that phase of the market?

In fact, that's one of the possibilities that we're looking at, Mark. We would have to make some investments in order to run sour synthetic.

Okay. Right now, you can run -- what is it, 60,000 barrels a day of synthetic through Edmonton?

We run about 35,000 barrels a day of -- 45,000 barrels a day of sweet synthetic Syncrude, 45,000, and the other 85 is light sweet, conventional.

Okay. So, any rough ideas as to what sort of mix you'd be able to go to under a different capital investment program here?

There's a whole range of possibilities. The original concept was to run 85,000 barrels a day of bitumen. This is why I say we really need to look at the scope and the technology selection here because you could back down to some combination of bitumen, sour synthetic, and conventional or sweet synthetics. So then all of that would govern then the kind of capital that you may be required to go ahead.

Fair enough. One more question related to gas, a little bit of a sweet surprise. Your gas prices seems abnormally high relative to the Ecco benchmark. Was there some exposure to some California market, et cetera, which led to this abnormally high price realization relative to your peers?

I haven't seen -- well, I actually haven't seen any analysis at this stage, Mark, so I can't comment on that. We really haven't changed our gas sales mix to any large extent from quarter to quarter. We tend to have a certain amount exposed to Ecco, a certain amount to Nymex, a certain smaller amount goes down the West Coast.

Okay, it looks like your average royalty rate based off your segmentation --

We have lost connection with the line that was asking a question. Please register your question . Mr. Heim, please reregister your question by pressing 1 and 4. Mr. Heim, you line is open. Please proceed with your question.

Sorry, did I lose you guys there? Just with respect to your royalty rates on Canadian gas, again through your segmentation it looks like about 14 percent in the first quarter, which does seem a little bit low, is there some sort of breakdown that you expect forward on average royalty rates for your domestic production?

Don't see anything outstanding, Mark, or anything special there. We can check -- I'll check the royalty rates for you. 25 percent would be --

The 25 percent seems more normal, that's why it just seems surprisingly low.

I think it should be in the range of 25, but I'll check the numbers.

Maybe Gordon could get back to you on that one, Mark.

Great. Thank you.

Our next question is from the line of Duncan Mafesin with UBS Global Asset Management. Please proceed with your question.

I wonder if you could comment on whether you're starting to lose any patience with the Syncrude structure and the management team in terms of getting the problems there fixed, and whether there's anything to be done with the management structure there?

Duncan, we're still working that issue. There's no question that we have Syncrude's management attention on this whole issue of reliability and consistency of results. We were somewhat encouraged by what we saw in the last six months of last year, where they ran at very reliable rates, and at the kind of profitability levels that we'd like to see on a more sustained basis, so first quarter of this year was clearly a disappointment for us.

We'd like to see them get back on track, but at this stage, we're not contemplating any changes in the structure or whatever.

Okay, thanks.

There are no more questions registered at the present time. Mr. Richie, I will turn the conference call back to you. Please continue with your presentation for closing remarks.

Thank you, operator, and thanks, everybody, for all the questions this afternoon. We appreciate your interests. We'll wish you a good afternoon, and if anything pops up after we hang up, of course, Derek and I are around for the balance of the day. All the best, and thanks for being with us today.

Ladies and gentlemen, that does conclude the conference call for today. We thank you for your participation and kindly ask that you disconnect your lines. Thank you.