Suncor Energy Inc (SU) 2003 Q4 法說會逐字稿

(Operator Instructions) I'd now like to turn the conference over to Mr. Gordon Ritchie, Director of Investor Relations. Please go ahead, sir.

Thank you operator and good afternoon everyone, and thanks for joining us today. With me are Ron Brenneman, Petro-Canada's Chief Executive Officer and Harry Roberts, the company's Chief Financial Officer.

During the course of today's conference call, we will be discussing reserves and some forward-looking information and I would refer you to the cautions appearing in our press release and in our annual report MD&A.

Ron and Harry will share the microphone today. And once we've completed the prepared remarks, we will open up the lines for questions. So with that, I'll pass the call over to Ron.

Thanks Gordon. Good afternoon and thanks for joining us on such a busy day of earnings releases. I know all of you must be scrambling today, and I appreciate your interest in Petro-Canada.

Since today's call is a year-end wrap-up as well as a quarterly review, I'm going to change my usual order of things a bit. I'll start with a financial review of fourth quarter performance. Then I'll move to a full year discussion, going over our 2003 success within each business unit. Harry will then cover reserves, reporting and financial details before I wrap up the call with an outlook for 2004.

For the first time in several quarters, our results fell short of analysts' predictions. Much of that had to do with one-off situations that, for the most part, are now behind us. Let me explain what went on.

If you factor out the two one-time events noted in the report - namely the Edmonton refinery write-down and the charge related to higher Ontario taxes, there's still a gap between the adjusted earnings of $1.07 a share and what you might expect on a running rate basis. Where we came up short is in the Downstream and International businesses.

The Downstream came in lower than normal in all three segments. Marketing delivered earnings of $10 million - that's after the tax adjustments. And that's well below this year's run rate of about $30 million a quarter. The reason for the drop - and you should all be familiar with this - was the price at the pumps. In Q4 we saw aggressive price competition as retailers jockeyed for market share at a time of rising crude prices. Price competition will always be with us, but this was quite extreme.

Our lube plant was slow in coming back on stream after the fire in August. We made sure that none of our customers were short of supply during the outage. This meant that we had to continue purchasing more costly third-party supplies through October in order to rebuild inventories.

And finally in Refining, margins were hit by the weakening U.S. dollar. And we took additional charges and depreciation related to the closure of Oakville, which amounted to $15 million after tax.

All of these factors amount to about $60 million of Downstream earnings - or about $0.23 a share.

The second area that came up short was International. The Euro is the functional currency for our international operations, yet assets in some countries are denominated in U.S. dollars. This results in a loss when the Euro appreciates relative to the dollar. In addition to that currency effect, we incurred a one-time charge for a crude quality adjustment for the Bittern and West Guillemont fields. The combined impact of these factors lowered international earnings by about $24 million or nine cents a share.

So the quarter fell short in a financial sense. But as I said, for the most part, the events are behind us. The underlying fundamentals in our businesses are improving - and I can best illustrate that by looking back over 2003.

2003 was another good year for Petro-Canada. Our financial performance speaks for itself in that we exceeded the billion-dollar mark in net earnings for the first time in corporate history. Equally important, our balance sheet is now even stronger than it was before the Veba (ph) acquisition two years ago. Beyond the financials, though, I take great satisfaction in our strategic advances in 2003, and our success in execution. We took some big steps forward in the Downstream in Oil Sands, and in our International business. With a number of key strategic decisions behind us, and all five core businesses on track to deliver strong performance, we're in great shape for the future.

I'll begin in Oil Sands, where we reconfigured the downstream piece of our integrated strategy. Our agreement with Suncor gives us access to their big new coker. That, together with an expansion of our coker at Edmonton, will enable us to upgrade and refine 53,000 barrels per day of bitumen. This cost-effective approach will fully integrate our Edmonton refinery with oil sands production and will generate an attractive return on our upgrading investment by significantly lowering feedstock costs.

Operationally, Oil Sands had its share of challenges over the year. But the good news is that MacKay (ph)River had an excellent fourth quarter, as reliability improved significantly. Production for the quarter doubled from Q3 levels, averaging over 16,000 barrels a day. The plant is currently producing more than 20,000 barrels per day, and we're on track to reach peak volumes around mid-year.

Like Oil Sands, the Downstream also took a big strategic step forward in 2003. Our third quarter decision to consolidate our Eastern Canada refining and supply operations was an important step to improve long-term profitability. The change concentrates our Eastern Canada refinery capacity into a high potential refinery in Montreal, creating economies of scale.

Operationally, our refining and supply group also made good progress last year. Our rankings in the Solomon benchmarks improved at both the Edmonton and Montreal refineries.

In the Lubricants business we moved forward on our marketing strategy. Our sales of high margin products increased to 65% of total sales. So we're getting ever closer our target of 75%.

The retail business also had a good year, with convenience store sales up 16% in 2003, and same store sales up 9%. We now have about 80% of our targeted retail sites converted to the new image. Those new-image sites continue to show their value by far exceeding the older sites in throughputs, non-petroleum revenue and gross margin. In fact, our network is now ranked first among the national Canadian marketers on two key measures - throughput per site and c-store sales per store.

So all in all, we made steady progress with our Downstream initiatives. However, operationally we did struggle earlier in the year. Unplanned shutdowns in our refineries and in the lubricants plant largely offset the financial impact of the strategic gains we made. As a result, the downstream mid-cycle ROCE in 2003 came in at 9%, unchanged from a year ago. Improved reliability will clearly be a key priority for us in 2004.

Moving overseas now, I'm particularly pleased with the strategic progress we've made in the International business. You'll recall that we laid out a three-pronged strategy in the second quarter conference call, and we're now proceeding with implementation.

First, we're successfully exploiting our existing portfolio of assets. In Q4, two new North Sea projects, Clapham and L5b, came on stream on budget and ahead of schedule. And we're working on the next two add-ons: Pict and DeRuyter. So we're delivering on our strategy to sustain profitable North Sea production.

The second component of the strategy is to step out from our existing operations, both in today's core areas, as well as in new theatres.

The target here is long-life reserves, and we're pursuing two potential opportunities at this stage - one to develop Kuwait's northern oil fields and the other to build a gas-to-liquids project in Qatar. However, I should also note that one project has fallen off the radar screen. Negotiations on the Terra Negra (ph) project in Venezuela have ended. So that asset - which had been part of the Veba acquisition - will remain with BP for the foreseeable future. Nonetheless, we're still interested in Venezuela, because it fits well with our long-life asset strategy. In fact, we're starting a long-term production test at La Ceba (ph) and we'll continue to pursue new opportunities in that region.

The third plank of the international strategy is to develop a balanced exploration program aimed at increasing our reserve base over time. We picked up the Mellita block in Tunisia in third quarter. In Q4 we added Block 2 in Syria and the Zotti (ph) block in Algeria. And we continue to pursue opportunities in both Libya and Trinidad. As we discussed last quarter, we've also restructured our exploration team to ensure that we've got the right resources pursuing the right opportunities. Our long-term goal is to significantly improve reserves replacement.

Our remaining two business units - East Coast Oil and North American Natural Gas - both delivered the excellent, disciplined performance that we've come to expect from those teams. The East Coast business exceeded our production expectations all year long. This is sure a nice price environment to be producing all those light, sweet East Coast barrels.

In North American Natural Gas, the maturing of the Western Canada Basin makes it increasingly difficult to profitably replace reserves and production. Nevertheless, our reserve replacement through exploration and development was 80%, in line with the 83% we achieved a year earlier. Our focus will continue to be on plays within our core areas, extending the success we've traditionally had with this approach.

In addition, we'll be looking for new opportunities beyond those areas with a more aggressive exploration program and possibly acquisitions. Our intent is to ensure that Western Canada gas continues to contribute strongly to the company's earnings and cash flow.

On the good news front in Western Canada, our gas marketing strategy is really paying dividends. An independent analyst report puts us in the top quartile for gas price realizations, beating the industry median by 51 cents on mcf in the first nine months of 2003.

All in all, I'm very pleased with our progress in 2003. And - we know what our priorities are for the coming year. Before I get to that, though, let me turn it over to Harry for a few minutes to cover some reporting and financial topics. Harry?

Thanks Ron. We are moving ahead with the expensing of stock options. In Q4, we made the decision to expense stock options effective January 1, 2003. This results in restated quarterly earnings for 2003, but the impact is relatively minor. Earnings were lowered by 2 million in the fourth quarter and by 9 million for all of 2003.

Reserves booking and reporting is a topic of particular focus in our industry. Petro-Canada has well-established, corporate-wide practices that have been continuously improved for over a decade. Our process is audited by both our internal financial auditors, Price Waterhouse Coopers, and by external engineering firms. And our Board of Directors approves our annual reserves filings. These steps ensure that our process continue to comply with Canadian and US regulatory requirements.

In addition, every year, the engineering firms audit a significant portion of our reserve estimates for accuracy. For example, last year Sproule Associates audited a majority of our domestic conventional reserves, while Gaffney Cline audited a similar portion of our international reserves. Over time, all of our reserve estimates are evaluated by external auditors.

The net result is a disciplined, reliable, corporate-wide process that is subject to continual external scrutiny and quality checks. Our confidence in the company's future is reflected another financial piece of news today - a 50% increase in the quarterly dividend. The decision to increase the dividend reflects our priorities for use of cash.

With strong cash flow coming from our diverse set of assets, we're confident in our ability to deliver on our first priority - to fund profitable growth. This allows us to focus on the second priority - returning cash to shareholders. And we did this by increasing the dividend. We'll continue to review our dividend payments on an annual basis and we'll be guided by the same priorities in the future.

Ron has already talked about the major factors that impacted earnings in the quarter. On the cash flow side, tax deferrals resulting from our Upstream partnership and the LIFO/FIFO effect in the Downstream did not have a material impact on the cash flow in the quarter. I'll now return the call to Ron for his 2004 outlook and wrap-up. Ron?

Thanks Harry. No doubt you've taken note that our production outlook for 2004 is down somewhat from 2003. We'll certainly be looking for ways operationally to exceed that number. But I would remind you that our focus continues to be on profitable growth for the long run. In that sense, 2004 is really a transition year for us.

We don't have any large projects coming on this year to offset natural decline in our mature areas. But we have Syncrude coming on in '05 and White Rose in '06. We're adding to our impressive list of exploration and development opportunities already in the hopper for later in the decade. And we clearly have the financial wherewithal to initiate or respond to additional opportunities that might not currently be on the radar screen.

Reserves are also getting a lot of attention these days. So, I'd like to provide you with the context in which we see our numbers. Our overall reserves replacement is down in North American Gas, in part due to the sale of some properties mid-year, and in part due to downward revisions in a couple of older fields in northeast BC. But the important metric to me is the 80% replacement we achieved with our capital program.

In International, reserve additions also came short of production and this is something we've been addressing. Veba didn't have much of an exploration portfolio - we knew that at the time. So we've been building our organization and have already had some success in building the portfolio. A reserve replacement of 50% is certainly not where we want to be, so there's still work to be done. But this is part of the transition in 2004. As I see it, Petro-Canada has five key priorities for 2004.

First, we will continue to focus on improving the reliability of our facilities, because this is an obvious area for improvement in the short term. In spite of last year's excellent financial results, we left about $75 million in after-tax earnings on the table because of reliability issues. This will get a lot of attention this year.

Our second priority is to execute the Eastern Canada downstream strategy, so 2004 will be a critical implementation year for the refining and supply group. In Montreal, we'll de-bottleneck the refinery and add logistical infrastructure. In Oakville we'll prepare the terminal to handle expanded shipments, and we'll do so while maintaining reliable operations. And the pipeline between Toronto and Montreal will be reversed, although that job is really in Trans Northern's hands.

The third priority is to fill in the detail and execute our Oil Sands strategy. The critical step for 2004 will be to ensure that the design basis for the Edmonton refinery conversion project meets our economic and timing objectives. And we also need to firm up plans for our next SAGD projects.

The fourth priority is to continue building on our solid track record on the East Coast. We need to assist in bringing the White Rose project in according to plan, and there may be room to start talking about reviving the Hebron project.

Building out our international portfolio is the fifth priority. As I explained earlier, we want to step out from our established areas of operation, both through acquisition and through exploration. We also want to add investment opportunities beyond our current capital program. We really want to take advantage of the balance sheet that we have been building up over time.

Before I take questions, there's just one more thing I'd like to mention. All of us at Petro-Canada are feeling like we're experiencing the end of an era this month, as we bid farewell to our President, Norm McIntyre. It's impossible to overstate Norm's impact on this company in his 22 years here. Later today we'll all be heading over to his retirement party, and if the hallway conversations are any indication, it should be a memorable event. We're grateful to Norm for his tremendous contributions, most recently of course, for his superb job integrating the Veba organization into Petro-Canada.

Fortunately, the changing of the guard is well in hand, as Peter Kallos is now installed in London and managing our international operations. Many of you met Peter during his time in Calgary, and I'm sure you share my confidence that his breadth of international oil and gas experience will serve us very well in the years to come.

And with that, thank you for your attention, and I'd be pleased to take your questions. Operator?

(Operator Instructions) Our first question comes from the line of Greg Pardy from Scotia Capital, please proceed with your question.

Hi Ron, I wanted to ask you a question I guess, just, first on the production guidance for 2004, and in looking at those numbers, can you give us a sense in terms of how conservative you think you've been, and secondly, it looks as though the North Sea, Trinidad, and West Africa all come off fairly hard as we go through the year, and the second part of the question is just on the reserves, can you just talk about costs in terms of your E&D program this year?

OK, let me start on the first one then, Greg on the production outlook. I wouldn't describe this as either optimistic or conservative; this is what we think - the realistic outlook is for 2004 and having said that, as I mentioned in my remarks, we are going to look for ways operationally to try to beat this.

There are a couple of opportunities we have, there is a potential short shutdown that we scheduled into the production program at Terra Nova which we are hopeful we can avoid; there is also a shutdown at Hibernia, which I know the operating management are looking for ways to defer into 2005, so there's a couple of areas that we might look to.

You mentioned Trinidad particularly, we had quite exceptional production from Trinidad this year, the actual contract off-take rates, are this 11,000 - I'm sorry, it's around 60 million cubic feet a day which translates into the number you see in the table here, versus the 73 that we actually produced in 2003. And the uptake from 60 to 73 is really a result of being able to sell additional production outside of contracted volumes.

Now the possibility exists that we could do that again in 2004, but we haven't counted on that in this budgeted number, having said I mean - a couple of examples for you to think about, Greg, I mean having said that, there are always some unforeseen events and some of them are weather-related off the East Coast, for example, some of them are reliability-related; so when we put it all together, this is the outlook we think is realistic for us to achieve.

OK, and in terms of the turnarounds, would they both scheduled for the third quarter? You know, or were they earlier near?

I think the ones in the second and the ones in the third, is that right?

That's correct, yes, and they are in - one in the second and one in the third, of course it will be weather dependent and we will work around that, in terms of using the best timing to do those turnarounds.

OK.

Your second question, Greg, had to do with costs, were you referring to F&D, or -- ?

Yes, I mean after the costs, I just want to highlight to you of your year end numbers last year was your low F&D costs in Canada and I know you've referred to an 80% reserve replacement, but you know, certainly looking at the reserve numbers, you know, they are not big additions, and I wanted to get a little better clarity between, you know, the revisions what you added, I guess - just a little bit more clarity there that would be great, specifically as related to costs and your E&D program.

Yes. OK, the number in the table that is in the press release is the net number, and it's net of two larger numbers; one would be the reserve additions, through our actual capital program this year which is about 80% of that production number, which I think was 48 million barrels, is that right?

And what's netted off of that, as I mentioned in my remarks, are some downward revisions in two, principally two older fields up the North East BC that are a very strong water drive, and to some extent are difficult to predict the performance of as they get to the end of their life, which they are very close to at this point. So this is not an unusual event in our mind. It's a small revision to a large number, in fact, but it happens to show up in the calendar year 2003.

So I think that as I said, the important metric from our point of view is the reserve replacement number from our capital program, this is what we keep our eye on, because this is what determines the economics and the effectiveness of the money that we spend on that business, and this year, we're again, quite pleased with the results that we achieved. We, unfortunately, are unable any more because of disclosure restrictions under; I think it's NI 5101, Harry (ph)?

5101.

51, I get these numbers all confused, now. In any event, it's the requirements of the OSC that have made it so restrictive in terms of the definition of F&D that we basically have said, that's too onerous and we're not going to try to comply with that, but I will say that I fully expect that our F&D costs, the way that we would normally calculate them, will again show up being very competitive in 2003; there are some third parties I'm sure you are aware, that do publish F&D comparable numbers, typically come out around mid-year, maybe in the third quarter sometimes, so unfortunately, it won't be until the end of the year that we can confirm that, but we were pretty pleased with that program results in 2003.

OK, and the last thing - just to finish, if you don't mind - is on your gas volumes, do you expect those volumes to go into fairly sharp decline during this year or is this another area where the numbers may be lot better than what you are giving us now?

Well, the number for 2004 relative to 2003 reflects a couple of things in particular, one is the sale of properties in 2003, so that's kind of a one-time hit, and the other is that during 2003 we had a couple of gas caps that were on blow-down, that will more or less complete in the early part of 2004 So these tend to be fairly rapid one-up production bumps that you get that don't sustain themselves.

So I think going forward, if you take that number we have as the equivalent of 640 million cubic feet a day, I think we will be back on the track that we had referenced over the past while or something like 3, 4 or 5% a year decline, of that number.

OK, thanks very much.

Our next question comes from the line of Brian Dunton from UBS. Please proceed with your question.

Yes good afternoon, Ron. Just on the subject here of asset sales. Could you quantify what the asset sales were 2003 to 2004 for the impact on production?

I think, Gordon, you got that number we had?

OK, of course, while Gordon's looking up that one, perhaps I can ask you another one in the interim, could you also maybe give us some color around your internal growth plans here, particularly, your international plans - you mentioned some projects in the Middle East, and North Africa and Algeria, could you maybe give us a little more detail on that?

Well what we referenced were the exploration blocks that we picked up in the last half of the year, Brian, the one in Algeria, the one in Tunisia and the one in Syria, so we will be starting program on those blocks through the course of 2004, but what I was trying to indicate was that was that's just the beginning, if you like, of building up what I've described as a more balanced exploration portfolio. Over time we expect to be able to do a lot better than the 50% reserve replacement that we achieved, last year in international we are fully intending to get that to a 100% or better over time.

I guess and lastly, you hinted there perhaps using your balance sheet to explain your international operations, what do you see as the opportunities that are out there at this point? Are they cost competitive?

Well, that's a good question, the kind of opportunities that we are looking for are ones that I've described previously. First of all we are looking for long-life type assets, and that's why for example, we are part of the consortium in Kuwait and part of the Marathon Light Group in the Qatar gas to liquids project, because those happen to fit that criteria.

And we are also looking for those types of project in the areas in which we currently have some operations, typically that takes us to North Africa, Middle East, Northern Latin America, Trinidad, and Venezuela for example. So those are the areas that we are looking at, we are aware that at least some of the majors still have assets that they intend to sell, over time, they have pulled back a little bit, admittedly on those programs, I suspect because of the better prices we are seeing today and are probably quite happy to hang onto them, but in due course, I do expect to see some opportunities that we would be interested in, at this point, I can't be more specific than that.

OK, great.

I wanted to get back to you on the volumes there for the asset sales in Western Canada. They were producing at about 10 million cubic feet a day, and 2000 barrels a day of associated liquids.

OK, great and I guess there's this one last thing, you can pass on to Norm congratulations on his retirement plan.

OK, I'll do that, thanks.

OK, thanks a lot.

Our next question comes from the line of Leslie LaFave from Ontario Teachers Pension Plan, please proceed with your question.

Thank you, I'm sorry guys, I'm just going to follow up on these reserve, or the asset sales, one more time, could you just clarify for me what the volume of reserves those were, where I could back my way into a corporate F&D cost, excluding this position?

Have you got a number for that, Gordon? I haven't got the details.

The reserves associated with our net asset sales is about 12 million barrels

OK, alright thanks, and there was no mention of the CAPEX program in your guidance in your - so I'm assuming there's no change there - is that correct?

That's correct. It's essentially what we put out in early December, Leslie.

OK, good and finally, just curious whether or not there are any - I don't think so - but were there any reserve bookings - for White Rose this year, in '03?

Can I just back up on the CAPEX, because subsequent to our release in early December, we modified that when we announced the Oil Sands Integration Project and the deal with Suncor.

But it was nominal I think, in 2004.

We added 60 million dollars of capital associated with the Edmonton Refinery conversion project - which would be for the engineering work in 2004.

OK, that's fair enough, thank you.

And your other question was to do with White Rose?

Yes, there was nothing booked there this year, was there?

In terms of reserves?

Yes.

No.

No, we don't actually - it until we actually have the reserves on stream.

OK, and any thought around renewing or at least having an assured bid this year?

I think, a normal course issuer (ph) bid or shared buy back?

Yes.

It's not in our plans at this stage.

OK, great, thank you.

(Operator Instructions) Our next question comes from the line of Paul Cheng from Lehman Brothers. Please proceed with your question.

Good afternoon gentlemen. Ron, several questions, first related to Syncrude I think this is another quarter that seems to have a poor reliability. Do you really have any hope that that operation is really going to improve - is the reliability issue related to the hardware or related to the management?

I'm certainly optimistic, Paul, that the reliability will improve there and I say that for a couple of reasons. One, is and I should probably reference to the incident that spilled into the fourth quarter, was an unplanned shutdown of one of the two big cokers up there. I think you have to understand that these cokers are fairly complex pieces of machinery, and Syncrude has really the world record run length on these particular units, so they do push them and stretch them as far as they possibly can, which is the most economical way to run them, but the consequences of the odd time something happens that causes them to come down unexpectedly. I don't particularly, I don't take particular concern with that sort of incident.

The other reliability issues that we had have had to do with the Aurora 1 mine, which was new technology that was starting up as part of the Syncrude Two expansion, and this was a significant change in technology because of the remoteness of the mine from the upgrader.

And so Syncrude has had to come up the learning curve there. That, first of all, that mine is now performing really quite well, very close to design expectations.

And secondly, I would point out that Aurora 2, which is the mine that is coming on for the Syncrude Three upgrader expansion, was turned over to Operations in the fourth quarter so that Syncrude has now some spare upstream bitumen production capacity out of the mine that exceeds their coking capacity and that gives them a little bit of flexibility in terms of being able to handle issues on the mining site. So I'm pretty confident that Syncrude, in time, will get by its problems of reliability and I think that first of all we've got some hardware changes taking place that will help that, and that's going to be a big factor as we go forward.

So Ron, is it fair to say that, essentially, you do not believe that (inaudible) not the problem that has been bucking the operation over the past several, past couple of years is really related to any particular problem of the hardware or is it a management issue?

It's a - it's like a lot of these situations, Paul, it's hard to put your finger on any one particular cause. There's been a lot of in-depth analysis done of these incidents that we've had to try to understand that if there's a systemic issue, either within the operation hardware itself, or within the organization, and there were some organization changes made over the past year, as a consequence of that, and there's also been some capital invested in the hardware itself, so it's a kind of a combination of things that we have been addressing.

OK, on the 2004, capital spending, about $2.6, $2.7 billion if oil price averaged out, say close to maybe in the $28-$29 (inaudible) January, excessive cash flow and given your (inaudible) that is not that in shape, there is really no urgent need for you to pay down debt. What is the priority of the cash going to be? You have indicated that share buy back is really not going to be a top priority earlier?

Well, our first priority is to find good investment opportunities, and I think in answer to an earlier question I talked about the kind of things that we might be looking for, in terms of acquisitions for example.

And our second priority, if we are in time, unsuccessful on the quality investment front, would be to look at ways to return value to shareholders. I think our move on the dividend. for example, was one indication that we are quite prepared to go that direction. And I think to be clear, what I said about the normal course issue or the share buy-back, is that at this point we don't have one planned, but I never say never.

Sure and it seems that means that you are probably not overly excited by the potential opportunity that your government don't deserve (ph) the 18% of the - of your share that - or are you going to bid on that?

Well, I think we will see what the situation is at the time and what they might have in mind and we will take a look at it and decide what we do.

OK, just one more question, Ron, you have indicated what you think on the 2004 outlook. If we're looking, say, to extrapolate that there a little bit longer into '05 -'06, it doesn't look like there's a lot of new projects going to come on stream. So we assume that production will at best relatively flat, along those lines?

Well, we don't have an outlook for '05 or '06 as yet and at this point, Paul, a lot of things can happen in the course of a year. The projects that we do know about are the ones that I mentioned, we have Syncrude coming on in the latter part of '05 and we have White Rose coming on in early '06,

Sure.

We are looking, as I said, for additional opportunities that we may be successful with in the interim.

OK, finally on the international exploration, you have indicated you are going to set up a more balanced exploration program there. Have you already sent or did you acquire an exploration team, that different as (INAUDIBLE) in the past that doesn't really have such a large exposure over there?

Well in fact that's what we have been doing for the last year or so Paul. Norm has been quite focused on building the skills and capability that we need within that organization. Statistically, for example, about one third of that organization is new, since we made the acquisition. So, and most of that has been initiated by ourselves in order to build in - not only an exploration capability but also an operating capability, where that was a little short in the original organization. We're in pretty good shape on that ground right now.

OK, very good, thank you.

Our next question comes from the line of Tom Evern from TriStone Capital. Please proceed with your question.

Good afternoon. On the reserves, I wonder if you can tell me what percentage your reserves are evaluated by a third party each year?

We have about, Harry's got some numbers there I think, that he can reference.

For 2003 it was of about two-thirds were looked at by external engineering firms. That number, I think, we can look at varying from year to year, and as a run rate that could be somewhere around a third of the reserves would be looked at independently year-over-year.

So is the plan, a three-year cycle to have all your reserves evaluated?

That's exactly right, Tom. For example, while we might do 50% in any given year, some of that will be repeats from the previous year, but what we do insure is that every 3 years, every field is looked at least once.

Great, thanks very much.

Our next question comes from the line of Allan Stepa from Sawman Partners. Please proceed with your question.

Sure, I wanted to make sure I heard you correctly; are you looking for potential acquisitions in Western Canada in regards to natural gas, and if you are, what particular areas would you be looking at - are we talking foothills, are we talking additional land holdings in McKenzie Delta, if you could elaborate a little bit further on that please?

Well, we have, in fact, we have made a couple of small acquisitions in the foothills down in the Coleman area in the last couple of years, so those will be examples of where we are trying to fill in gaps along the trend that we currently consider a core to our operations.

But what I was referencing was that we are also looking now outside of our core areas, even into the U.S., for example, our base has extended into the U.S., to see if there aren't some opportunities that might be attractive to us. And I mean, when you do that, of course, you are always looking not only for organic opportunities, but also acquisition opportunities, so I just throw that in the list because it is a possibility.

And as far as scale and scope, what type of range are we talking - are we talking again add-ons of assets or, potentials you know, acquisitions of companies if it meets, you know, your metric, so to speak - what's the vision there?

Well, anything that looks attractive, we're not particularly targeting any particular size, Allan, so it could range from small asset acquisitions to medium size companies I would guess.

OK, and just one more quick follow-up question on the reserves, just to make sure, again we are talking about - you said two-thirds have been looked at - again we are talking evaluated versus reviewed. In the sense that evaluated is where the reserve engineers - they basically get the data and come up with their own numbers versus reviewing where they just basically do a cursory view. Is that correct? So, it'd be two-thirds have been evaluated?

There are two - you're quite right in making that distinction, Allan. There's two-thirds that we say have been reviewed by, in some way, external consultants and about half of those are independent numbers generated from raw data. And the other half would be auditing the numbers that we have and looking at the data we've used and how we've gone about it.

Perfect. Thank you.

Our next question comes from the line of Randy Ollenberger from BMO Nesbitt Burns. Please proceed with your question.

Great. Thanks, Ron. Just a couple of questions, here. Firstly, just want to clarify on the capital program. I think you - Leslie asked if it was intact from November, you know, notwithstanding the adjustment you made with the Oil Sands, but the question is really, on the international front, you were planning on spending more money. And I'm just wondering - just wanted to clarify that that's the case given the production outlook, which is actually showing a drop of, you know, roughly 10,000 VUEs or more from some of the Q4 levels.

Yes. Most of that drop, Randy, is in Syria. It's a result of the natural decline in those relatively mature fields there. And the capital that we're spending relates more to the North Sea projects, for example, that we have underway. I mentioned Pict and DeRuyter, for example. So, that's not necessarily related directly to the production decline.

So, the incremental capital is not really expected to bring any incremental, I guess, production in '04? Correct me on this.

It will come on stream in '04. The U.K. North Sea field?

Yes.

But, in addition to that we have some natural decline in the North Sea, so, in effect, we're both holding even there.

OK. Yes. That's what I wanted to clarify. The second thing was, I was wondering if you'd - you'll offer a little bit more color on Cerro Negro. You said the discussions are effectively over. Is that because BP has decided they want that asset or is it just because it was too complicated with all the turmoil at Pedevesa (ph) and so they've just been abandoned?

I'd say it's more of the latter, Randy. First of all, the passage of time - almost two years went by - made it very difficult to try to resurrect the offer that was made originally. And I think we indicated early on that it was a pretty complicated process that was laid out in that joint operating agreement.

Which was complicated further, I must say, by the fact that our offer was part of the corporate Veba acquisition. And that circumstance wasn't contemplated when the joint operating agreement was put together. It was contemplated that any offer would be made on a single-asset basis. So, there were a number of things that got in the way of being able to resolve that. And in the end, BP concluded that it was better to just let it sit.

OK. So, just one last question. I mean, you mentioned that you are considering, you know, opportunities in the United States et cetera. On the natural gas front, given the decline, you're now, you know, forecasting in Western Canada, here. Are you considering other opportunities? Coal bed methane, that type of thing. What type of things are you guys looking at?

I mean, we're pretty open to whatever we might see when we sort of expand our horizons a little bit. So, at this point, we haven't ruled anything out.

Good. Great. Thanks.

Our next question comes from the line of Terry Peters from CanAccord Capital. Please proceed with your question.

We seem to be focusing a lot on capital structure and spending, so I'll just continue on that front. You did mention that your balance sheet is - strength is back to where it was pre-Veba and I'm wondering, in reflecting on your strategy for your international - perhaps, you could let us know what kind of excess capacity do you think you could draw upon on your balance sheet in order to react or initiate some additional investment? What kind of incremental capital spending could you absorb at this point?

And in particular, if you look at your goal of going from 50% reserve replacement to 100% internationally, you're only bumping your spending up by 10%. What kind of level of capital spending do you think you need internationally to, kind of, achieve that objective?

I'll ask Harry to comment on the first one, Terry.

Terry, let me just try and put some sense around the first part of the question. When you talk about balance sheet strength and the fact that our debt to cash flow is at 0.7 times and our debt to capital is 22%, when we think about how far we'd like to stretch the balance sheet relative to capital or transactions, we think of debt to cash flow in that, kind of, 2.5 times range and the debt to cap in the 45% range.

Those are, kind of, the levels that we took the balance sheet to when we did the Veba transaction. So, again, the transactions really depend on the nature and the size, but that's the kind of realm that we're thinking about. Ron?

And the international CAPEX area, if I understood what you were asking about the exploration program and what impact that might have or ...

Or your total capital program is in Dollars, is going up by about 10% into 2004. Yet, you know, you have been objective to do better on the replacement front. So, you're going to have to spend a lot more money, I would presume, than bumping up your capital program by 10%. And I'm wondering if you have, kind of, a number in your mind. Is it $1 billion or $1.5 billion - in order to - if you had the opportunities to replace your production internationally?

Yes. I guess, the only metric that I can relate to is what we think we need to spend when - on a balanced exploration program. And this is just simple numerics. If we want to replace production in the international business and of the offshore or the East Coast, we, kind of, group those together, we need to, first of all, to get into the right economic zone, meet the, sort of, first quartile finding cost that you find in international operations, which is about U.S. $1 a barrel. And so, if we're producing 200 million barrels a year, we need to - we need to find good opportunities to spend about 200 million U.S. a year on our exploration program.

And we're quite a ways away from that at this point. So, that's one thing that you could think of as adding to the capital program over time. And then, of course, we would anticipate success from that that would then lead to development expenditures. And those would be a function of what you find. Is that the sort of thing you were looking for?

Yes, in general. I just wondered if I - if this was a year forward as to - if there was going to be an opportunity that you would react to. I mean, I think when you acquired Veba, it was large and actually, the market reacted negatively, I think, at first and then has come around to being convinced it was a good investment. I'm just wondering if your balance sheet is now setting you up to do the same thing and you have a strong desire or capacity to really push hard on your three-pronged strategy internationally?

Oh, yes. That's exactly what we're doing. And so, I would anticipate that our capital program will increase over time, internationally, with the kind of success that I expect we'll have. And that's why I described, in my remarks, 2004 as a bit of a transition year because it's going to take us time, obviously, to build the, first of all, the exploration portfolio, but also to get after some of the acquisition opportunities that we think might be out there for us.

OK. That's great. Thanks very much.

Our next question comes from the line of Bob Lyon from CI Mutual Funds. Please proceed with your question.

A quick question on royalties on the East Coast. Can you tell me what you guys are budgeting for '04 as an average royalty rate for your East Coast Oil?

Bob, Gordon Ritchie here. I think we see royalties do tend to creep up. I don't have the number with me here, but well, I can get back to you on that. They tend to go up a percentage point or two each year as we get - as we move through the fiscal regime.

That's fine. You can get back to me.

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

Hello, Ron. I'm trying to get a better understanding of what was going on in the Downstream in the quarter. And the release said - talk about the impact of the appreciation of the Canadian Dollar on the 3-2-1 crack spread. Now, that spread was pretty solid all year long and the Dollar was appreciating most of the year like - was all that a big factor in what happened in the Downstream and do you reach a limit by- with the Dollar where it is, is there, like, sustained impairment in the returns? Or is this sort of a - more of a transitory thing?

I think it's more of a transitory thing, Robert. It's really, when you get these bumps going into the market in a margin-tight business, like the Downstream, whether that's rising crude prices putting pressure on feed stock (ph) costs that has to be passed through to the customer, which was a big factor in the - on the marketing side, for example. But, whether that's an impact of currency in the case of the 3-2-1 crack spread for refiners and therefore rack (ph) prices - it's the same sort of situation. So, it tends to have more to do with the transition than the steady state.

OK. Thanks. And if I can ask you one more short one, regarding Libya. There's talk about sanctions ending fairly soon. Is there something you can do to exploit the advantage you have in Libya before it opens up to everyone else?

Well, I think we have a natural advantage by being there, in the first place, Robert. That is a part of the world where established operations and relationships are quite important in being able to access new opportunities. And secondly, I mentioned that we are in discussions on some exploration opportunities in Libya. So, we've already been working on trying to get a leg up, if you like.

OK. Thanks, Ron.

Our next question comes from the line of Jay Saunders from Deutsche Bank. Please proceed with your question.

Thanks. A few production-related questions. On the East Coast Oil, the drop from 86 to 80 in '04, how much of that is related to the downtime or potential downtime?

Second question - on the Oil Sands, given what's happened at Syncrude, I think you guys came out with a number of about 43,000 barrels a day in '05. Do you still think that you guys - that that's a reasonable number?

And finally, just the - in the international segment, can you break out Libya and Syria for your '04 outlook, please?

On the East Coast, Jay, I'm guessing that most of that drop from 86 to 80 would be the -shutdown-related. I mean, there's really no difference in either reservoir performance or facility capability from '04 to '03.

So, it has to do with the anticipated downtime, which, as I mentioned before, is a plan at this point. And the 43,000 barrels a day at Syncrude is still a good number. But it wouldn't be for all of '05, because it's coming on-stream later in the year. And I suspect, if we were to make a projection at this point, you wouldn't expect instantaneously 43,000 barrels a day at startup. Normally, there's a break-in period required for this kind of machinery. So ...

do you get there by mid-'06 or - how long does that last?

Yes. I don't know what kind of assumption you might make.

OK. And then, Libya and Syria?

I don't know whether we've done that. Have we, Gord, split out Libya and Syria in our

we're - we've got 133,000 barrels a day from North Africa/Near East.

OK. If I may, there's one more I forgot on White Rose. It seems I had thought that was going to come on in late '05 and now you're saying early '06, is that just something I missed or is there a - do you have a delay in there?

Well, the project target startup is still late '05, but the operator, Husky, has talked about '05/'06, which is allowing for a little bit of contingency, if you like, in the timing.

Yes. OK.

I think, realistically, we're thinking about early part of '06.

Ok. Great. Thanks.

Our next question comes from the line of Andrew Fairbanks from Merrill Lynch. Please proceed with your question.

Thanks. Good afternoon, Ron. Wondered if you could just give us a sense for the potential timing on announcement for the Kuwaiti northern oil fields or the Qatar LNG. Is this something that'd worthwhile to expect in the first half of the year or the second half of the year? And then what respective rates of return do you expect out of those projects that you're - for your basic case of oil and gas assumptions?

Well, on the second one, the rates of return are a negotiated item. So, I'd rather not speculate on where we think we might end up there, Andrew. And as far as timing goes, the - it's a bit speculative because the Kuwaiti deal, for example, is still a discussion item between the Kuwaiti National Oil company and the Parliament of Kuwait and these discussions have gone on a little longer than most people had expected. So, I think it's difficult to pinpoint when we might see a resolution on that.

And on the Qatar LNG project, we continue to make progress with Marathon on that. We signed a letter of understanding back in the third quarter of 2003 that basically laid out the intent of the, you know, the project's scope and timing and that sort of thing. And at this point, we're just, with Marathon, working on the details to firm up the next stage in the proposal process. So, this'll be ongoing, I suspect, through 2004.

Very good. Fair enough. Just one other, if I could. The - some of the longer-term production forecasts or charts you've shown for the East Coast indicated that with some of the work-over and additional horizon work you've got going at many of the projects, the notion was we may see a longer plateau than one might expect for those basins. Is that still the case? We've got a little bit of a dip, you know, as you indicated, going into '04. Would you think you'll be able to hold '04 levels fairly flat for a couple of years and then go into decline or should we put the decline in starting in '04?

I wouldn't read too much into that oceanal drop in '04 versus '03, Andrew. I mean, as I indicated in response to an earlier question, a lot of that is just operational-related and not necessarily - certainly not reservoir or facility-related. And our plan is still, as we had indicated in those earlier charts, to extend those plateaus as long as we can. We are continuing to delineate the Far East block at Terra Nova and continuing to evaluate the Avalon Sands at Hibernia. And we intend to be able to come forward some time in the latter part of 2004 with a development scheme for both of those opportunities.

And in addition to that, there are some satellite - smaller satellite fields - independent fields that are within reach of those two platforms, particularly Hibernia, that we're starting to do some evaluation work on, technically at least, in '04 to see what we need to do from a program point of view to firm up those opportunities, so that they can be slotted in at the right time. So, it's still very much our intent. I expect that when we have our Investor Day in March, we'll probably have an update to that chart that we showed last year.

Well, that's great. Thanks, Ron.

Our next question comes from the line of Tyler Dann from Banc of America Securities. Please proceed with your question.

Hi this is actually Kurt (inaudible) for Tyler. He had to step away. I wanted to ask you if there was anything internally that changed the way you forecast your productions from the companies you follow. I'm speaking to the way they go about reaching the production forecast and how they've changed from their internal controls. Is there anything you could speak to in that regard?

Changing from what we've done historically?

Right. Or were there any surprises that led to your current forecast?

No. We've taken the same approach that we have traditionally in putting it together.

Also, could you give us any feel for what you view as your company-wide decline rate, both, organically and without additional spending?

Well, that's pretty tough because it's quite a mix of assets. I mean, it ranges all the way from zero in the Oil Sands and Libya and Trinidad, for example, which are basically long-life assets.

And did anything change in the way you view that decline rate over the past six to 12 months?

No.

OK. Thank you.

You could get up to the 20% range in areas like Western Canada and Syria and the North Sea, for example.

Sure. All right. Thank you very much.

OK.

Our next question comes from the line of Wilf Gobert from Peters & Co. Please proceed with your question.

Thank you. Could you give me some expansion or give us expansion on the provincial tax rate changes, specifically Note 6? My understanding is the provincial tax rate changes are for Ontario. And if that's the case, why does the tax rate change apply across all business segments? And are these tax impacts for just 2003 or are they related to future tax liability?

Wilf, it's Harry. The reason that we show it this way is related to our corporate structure. And that is to say that all of the assets for Downstream and the various operating entities fit within Petro-Canada. So, for tax purposes, when a rate like Ontario's, which was higher as a result of the new government coming in, it impacts on all of the operating segments. And in terms of going forward, it is a - it does represent a change to our future tax liability.

OK. So, can you indicate how much of the total applied to 2003 pre-tax profits and therefore, how much of it was related to the future? Or is this all related to the future?

We have to take account of it all in 2003. And then it adjusts into the future tax liability number. So, I don't know. I'm not quite sure of that question you're asking, but we had to account - that's why the tax rate, if you look in 2003, is higher, at about 64%, it's because we had to take that 9% in - that additional 9%, as a result of that change. But, if we go forward, the tax rate restores to normal when you look at the effective tax rate for our earnings.

So, if you looked into the year 2004, for instance, if you were to use an overall tax rate of around 45% for the corporation, that would more or less cover off what that liability would look like. So, the Canadian operations would be about 39% and the IPU would be around 70%.

OK. Good. That answers. Thank you.

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

Good afternoon, gentlemen. I guess I'm - got a couple of questions in terms of the Western Canadian gas. And first off, what did you exit out of 2003 in terms of Western Canadian gas production?

Well, our fourth quarter was pretty representative of what we exited with - I think it was around 690.

OK. So, we're going to exit at 690. You're saying you're going to average 640 for the year, so, it evolves - is it safe for me to think of something in the 590 to 600 range as your exit for 2004?

I don't actually have an exit number, Martin. You just put the average number in.

I guess then, the question is, you know, how fast do these gas caps come out of the equation?

Well, now, you're down to specifics. I don't have an answer to that one.

OK. And historically, there has been talk from some of your partners in Hibernia about potentially expanding the facilities. Where does that ability to produce - where does that stand now? Are we back to everybody on the same page thinking, you know, we've gotten some development in the range that they are at currently?

Are you talking about Hibernia?

Yes.

I'm not aware of any discussions about expanding Hibernia, Martin.

Well, there was about 14, 15 months ago, there was talk on an (inaudible). In terms of MacKay River, where do you think we - like, is the feeling at the designed capacity or have the guys, in terms of all the work that they've done on it, come up with any ideas for inching it beyond the original target?

Our first objective is to stabilize at the design rates, which is in the order of 30,000 barrels a day on a calendar day basis.

OK. And then, in terms of operating costs, where do - where's the thinking, now, in terms of stabilizing operating costs? Obviously, natural gas is a component of that, but with all of the changes that have gone up, what do the stabilized operating costs look like?

We're looking at $3.50 plus a little less than an mcf of gas once we get the Cogen (ph) unit on-stream.

And the Cogen (ph) unit is due when?

Should be up - it's actually being run in right now; so, by the end of the first quarter we should have it fully on-stream.

Great. Thank you.

Our next question comes from the line of Duncan Matheson (ph) from UBS Global Asset Management. Please proceed with your question.

Yes. If I could just follow-up on Martin there that I got a problem with your North American Gas story here. A couple of years ago, prior to Iran, when you arrived there was always talk about going to 1 b a day and then that got tossed aside and it was - the strategy was - sustained 700 million a day and you felt that you could possibly do that within the confines of the Basin.

So, here we are with higher prices and yet, you're not doing that. It seems like, you know, Martin was alluding to the fact that if you're going to average 640 for this year, it means Emirates (ph) close to 700 now, the number's coming down pretty fast. What is the gas story, now? Is it more like a 600 million a day average?

Well, I think we've talked about, more recently, a 3 to 4 or 5% decline rate, Duncan? And I think if you were looking into the future, that's what you should expect. Now, this step-out activity that we're talking about, we're optimistic that with some new opportunities we can arrest that decline, but in the base case from our core areas, that's basically how we see the business.

So, you see a 10% drop this year and then followed by three to five ongoing?

Right.

Now, at the - I've been doing some finding cost numbers and thank God there's some revisions in there, because I got some funny numbers, but a pretty hefty finding cost - is this business, even with the higher prices - can it still make the cost-to-capital returns that you've been so strict on or do you need to reassess what you're doing in the gas business?

Well, we're - I mean, our finding costs are still really very competitive with the kind of results that we had in 2003. And there, I would say, there's still room for finding cost to move up, not materially, but gradually and still maintain a - the kind of profitability that we'd be looking for here.

We're basically looking at each and every capital item that we're spending money on at a 15% return using our gas price outlet, which is about $3.60 long run. So, we're still seeing pretty attractive economics, even at that.

OK. And in terms of the revisions that happened on the two fields in Northeast BC, are those the only two fields with those water issues or are there other ones up there that could, sort of, bite us as we go forward?

Those are the two main fields that are water-driven. Most of our production comes out of the foothills through the western part of Alberta, here. And most of that production is from conventional sandstone reservoirs or conventional carbonate reservoirs that aren't water-driven. So, we don't have that issue with the vast majority of our reserve base.

OK. And another follow-up on the East Coast on White Rose. I noticed in your press release, you talk about the FTSO (ph) is leaving Korea and will arrive in the second quarter. Is that behind schedule? I just originally thought it was going to arrive in January. Aren't we standing to lose some time?

It's pretty much on schedule, Duncan. It's supposed to be here in the April/May timeframe. I think that - the last word I heard was that there were still - one of our guys was over for the official commissioning here in the early part of January. At that time there were still some items that weren't quite complete. And so, rather than allow the vessel to sail and anticipate having to complete that work in the yards of Newfoundland, they chose to keep it there for another couple of weeks and clean that work up. But, that's not material in the great scheme of things.

OK. And finally, it's a bit of a loaded question, but do you think - are you a bit surprised by how the stock reacted today to this news? And do you think that when you do guidance, perhaps, you should try to get your conference call a little closer to the press release timing?

Well, yes, I was a bit surprised, to be honest. And it's kind of a Catch-22. For the last year or so, we've been trying to get our press release out early so that the analysts have a chance to look at it before we get to the conference call and we can have a productive dialogue about some of the strategic issues. But, from time to time, this is the consequence and the kind of risk that you run, I guess.

Okey doke. Thanks.

Our next question is a follow-up question from the line of Leslie LaFave from the Ontario Teachers Pension Plan. Please proceed with your question.

Thank you. Ron, you, at the beginning of your comments, walked through the adjustment to the Downstream earnings for the quarter. And I'm wondering if you could do that same exercise for the full year number or should I call somebody offline about that?

Gordon probably has that analysis. I know we do have the numbers. I just - I don't have it in front of me, here, though, Leslie.

OK. All right. And just to confirm on the asset sales of 12 million VUE, I believe it was. Those were all in Western Canada, is that correct?

That's correct, yes.

OK. Great. Thank you.

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

Hi, Ron. In terms of the Oil Sands (inaudible), now they're with your - you are joined with Suncor. I think before that there's some hope that in 10 years' time, total Oil Sands including your fully (inaudible) operation, as well as the Syncrude together may contribute up to 200,000 barrels a day after production, as you moving into the newest creek (ph), the (inaudible) operation. Are we know that - looking at our far more modest ambition in that particular (inaudible) of the business?

Well, what we're looking at - I'm not sure what you might have picked up previously, Paul, but what we're looking at now is our next SAGD project coming on-stream around the end of the decade. And what we've said is that our current thinking, rather than thinking that bigger is beautiful, we're now thinking that the next increment would be more the size of MacKay River or maybe up to 40,000 barrels a day. So, that's more our current thinking at this point.

OK. Very good. Thank you.

Mr. Ritchie, there are no further questions at this time. I would now turn the conference back to you. Please continue with your presentation or closing remarks.

Thank you, Operator. And just before we sign off, I do want to re-extend an invitation to all of you to join us at our second day for analysts and investors, which we're holding on Monday, March 8th in Toronto at the King Edward Hotel. We've got a mid-morning start, so the participants from Montreal, Boston and New York can fly in on that morning.

And in conjunction with the event, we'll be holding a field trip to the Lubricants facility in Mississauga on Tuesday morning. So, I hope many of you can join us on March 8th. Thanks for your time and as always, Derek and I are available to follow-up with any questions that you may have after the call.

Have a good day.

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