Suncor Energy Inc (SU) 2002 Q4 法說會逐字稿

Ladies and gentlemen, thank you for standing by. Welcome to the Petro-Canada fourth quarter earnings conference call. During the presentation, all participants will be in 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 Thursday, January 30, 2003.

I would now like to turn the conference over to Gordon Richie (ph), senior director, investor relations with Petro-Canada. Please go ahead, sir.

Thank you, and good afternoon, everyone. Thank you for joining us today. With me today are Ron Brenneman, Petro-Canada's chief executive officer, and Harry Roberts, the chief financial officer.

We'll begin today with Ron's remarks, then before opening up the call to your questions, Harry will explain in greater detail some of the non-operating factors that you need to have in hand for the quarter.

I would note that today's discussion will include references to forward-looking statements, as well as some discussion on reserves potential for our company. So our discussion here today is subject to the disclaimer and the warning included in our press release that went out earlier today.

So with that I'll now hand the call over to Ron Brenneman.

Good afternoon, everyone, and thank you for joining us today.

2002 was really a watershed year for Petro-Canada. We doubled production. We achieved record earnings, and we retired half a billion dollars in debt. But behind the numbers, what really gives me satisfaction is that in 2002, we successfully executed our strategy on all fronts. And I believe that our strategy and our ability to execute established the foundation for a terrific future for this company. So it's a pleasure to share with you the track record and the outlook for each of our businesses in 2003. The downstream results provide an excellent example of our success and execution. I'm delighted with the results we're achieving in this business.

On the retail end, and I know you appreciate what a fiercely competitive business this is, Petro-Canada is winning on all measures. Our retail gasoline sales were up 4% over last year, well ahead of the industry growth of 2%. So our new image service stations are clearly performing as planned. C-stores are the best part of our retail story, as we achieved a remarkable 30% increase in sales in 2002. As you know, non-petroleum is a critical component of sustained profitability in the downstream business, and we got a nice little feather in our cap this year that highlighted our retail success - we were the first non-American company to win the Convenient Store Chain of the Year Award, which to our retail folks felt like winning the Super Bowl.

We're now roughly two-thirds of the way through our re-imaging program. Obviously, we tackled the best candidates first, so we'll need to be more selective for the remainder. That means rebuilding only those sites that would clearly meet our return criteria. Our refining and supply business is also on track, as we execute our strategy to improve reliability and achieve a (inaudible) cost structure. Our three refineries exceeded our reliability target of 90% over the year. We intend to sustain that performance this year, although we had a small setback this week with a minor fire at Oakville (ph). The lubricants business had an excellent year in 2002. Our strategy of migrating sales to high margin categories is clearly delivering results. Sales of specialty lubricants, the key to success in this business, increased 10% over last year and now represents 60% of total sales. So we're on track to reach our goal of 75% high margin sales by 2004.

So what's the bottom line out of this? In 2002, the downstream generated a mid-cycle revenue on capital employed of 9%, a considerable improvement from previous years. Our profitability initiatives thus far are delivering and we have more in store, so we're confident we will achieve our 12% mid-cycle ROCE target in 2004.

Let me switch now to the upstream, and I'll begin with good news from the East Coast, where the offshore capability that we built in Petro-Canada really came to the fore. Pera Nova (ph) had a world class start-up, 86% reliability in its first year of operations surpassed start-up reliability for similar FPSOs in the North Sea, and it's producing even better than we expected, averaging an impressive 135,000 barrels a day in the fourth quarter.

Hibernia (ph) operations also exceeded expectations, averaging 180,000 barrels a day for all of 2002. This year we will continue to delineate further opportunities for both of these profitable projects in the Far East section of the Terra Nova field and in the Avalon reservoir of the Hibernia field. Our intention here is to extend the plateau production of both of these fields. The White Rose project also is on track. Work on the FPSO is well underway for project start up in late 2005. Also this year we'll begin exploration for new world scale projects in the Flemish (ph) Pass. Mizin (ph), the first of two wells will start in the first quarter. Each well will take 45 to 60 days to drill. And our one-third share of the cost will be about $20 million per well.

The East Coast continues to be a key components of Petro-Canada's growth storage. Our oil sands business also celebrated a critical start up in 2002. This was the first plank in a solid platform for long-term growth. You've heard us talk about building the Makai River Sagni (ph) project on time and on budget. Today we have further good news to report. All 25 well pairs are now producing bitumen (ph). December was our first full month on stream and production already averaged 9,400 barrels a day. With successful product execution at Makai, we are moving into the next leg of our integrated oil-sand strategy, the 80,000 barrel-a-day Meadow Creek Sagni project and the bitumen conversion project at our Edmonton refinery. The regulatory approval process on both projects is progressing well and should be completed by the third quarter.

I can't leave the subject of our oil sands growth plans without touching on the Kyoto issue. Uncertainty around the Kyoto implementation plan remains a concern to us. But we have been encouraged recently by the government's commitments to limit the oil and gas industry's financial exposure. We are also pleased to note Ottawa's evident desire to find a practical solution that will protect investment, particularly in the oil sands. That being said we are not there yet in achieving enough comfort around the Kyoto rules to proceed with sanctioning major new projects. So we are working closely with the government to resolve this issue.

I will conclude the discussion of oil sands by noting the improvement in Syncrude's performance. In the second half of 2002, production rose to 256,000 barrels a day, and operating costs fell to $14 a barrel. Syncrude is a core asset and we are confident that in time we will see that performance sustained. And speaking of core assets that deliver solid profitability, our western Canada natural gas business continues to excel. The strategy here is to maintain superior profitability and a maturing basin. We achieve this by focusing on capital efficiency, not necessarily volume. We built exceptional capability in our western Canada team and that's demonstrated by our consistency in achieving (inaudible) finding and development costs.

In 2002, our F&D costs were $1.556 in MCF. 2002 saw industry gas production in western Canada fall somewhere between 2 and 4%. A sign that the basin is indeed maturing. Given that, we are pleased with reserves replaced of 86% last year. Our future growth in natural gas production will come from North America's undeveloped basins like the McKensie (ph) Delta. Next month we will drill another exploratory well in the region with our partner Devan (ph), testing the same trend where we had success with the tuck well last year.

I stated that 2002 was a watershed year for Petro-Canada. The most significant event in a year of significant events, of course, was our step out internationally. With Petro-Canada well established in all the major plays in Canada, we looked internationally for one more big plank to build our platform for growth. We were specific about the type of opportunity that we were seeking and I believe we found a very good fit with our major acquisition early in the year.

Since May, Norm McIntyre has worked tirelessly to integrate the international unit into Petro-Canada. And we've gained an even greater appreciation of the assets and the capability of the people. I am very pleased with the results so far. In the North Sea we are pursuing two projects. The Clapham (ph) development in the UK sector will add peak production of 15,000 barrels a day early in 2004 and the development of our L5B (ph) gas discovery on the Dutch side is well underway.

We are pursuing new exploration and development opportunities in both Libya and Syria. In Trinidad, production will grow from 40 to 60 million cubic feet a day when Atlantic LNG's third train starts up in midyear, and we're looking for exploration opportunities there in the next licensing round. Having largely completed the acquisition, we can now focus on identifying new growth opportunities.

To sum up the upstream story, successful execution of our strategies has set the foundation for strong future growth. Our reserves position at the end of 2002 really tells the tale. Petro-Canada's total reserves, that's crude, probable and possible rose to 4.2 billion barrels of oil equivalent, and that's up 29% from a year ago. Our future will be built on this expanded reserve base and our track record demonstrates that we can translate those reserves into profitable, sustainable growth.

Let me touch briefly on the corporate side where we also delivered on our balance sheet objectives. In addition to funding our aggressive capital program, we retired over $565 million of the $2.1 billion of debt that we raised to finance the international acquisition -- 465 in 2002 and I've heard 300 million this month. We also obviously have been fortunate in our timing. High commodity prices and low interest rates have enabled us to pay down debt faster than we had expected. Our balance sheet is solid. Our debt to cash flow is 1.3 times, well ahead of our stated target of two. And our debt to debt plus equity ratio of 35% is within range of our long-term target of 30%.

So to wrap it up, I am very satisfied with our 2002 results. We got a big boost from commodity prices, but more fundamentally it was a year of successful execution across the board. We were really firing on all cylinders. We delivered profitability in the downstream at western Canada gas and added exceptional growth from the East Coast, the oil sands and international. Our people are energized and engaged. We know we are building an exciting future for this company.

Thank you for your attention. I would be pleased to answer any questions you may have after we hear from Harry on some data that you often ask about. Harry?

Thanks, Ron.

I have four points to note. First, we separated out the impact of foreign exchange translation on the first page of today's release. This removes the quarter over quarter swings in net earnings due to short-term exchange movements. Fourth quarter earnings from operations on this basis were 370 million, $1.40 per share, up from 76 million or 29 cents a share a year ago. Second, were two factors that affect cash flow. Tax deferrals results from the Canadian upstream partnership increased cash flow by approximately $30 million in the quarter and the (inaudible) effect on downstream added approximately 70 * million. After adjusting for these items, cash flow would have been $2.92 a share, up from a dollar 17 per share in the fourth quarter last year. The third item in the fourth quarter, the international business unit benefited from a one-time gain of approximately $17 million in earnings, resulting from positive tax adjustments in the Netherlands. These were partially offset by other international tax adjustments.

Finally, I know that pension liabilities are a hot topic these days. With the state of the capital markets we closely monitored advances over the last two years. At the end of 2002 Petro-Canada's unfunded pension liability for accounting purposes was approximately $280 million, up from $80 million at the end of 2001.This will affect us in two ways. First, we will make a cash contribution of approximately $30 million in 2003, which will effectively lower our overall cash flow and second, this will also increase our pension expense by approximately $45 million on a pre-tax basis during 2003.On an after tax earnings per share basis this increase translates to ten cents per share for the year. So the pension situation is well in hand.

Thank you, Harry. Operator that concludes our prepared remarks. We are now ready to open up the call to questions.

Thank you. Ladies and gentlemen if you would like to register a question please press the one followed by the four on your telephone. You will hear a three tone prompt to acknowledge your request. If your question has been answered and you would like to withdraw your registration press the one followed by the three. If you are using a speaker phone lift your hand set before entering the request. One moment please for the first question.

The first question comes from the line of Andrew Fairbanks (ph) with Merrill Lynch. Proceed with your question.

Good afternoon, guys. I wanted to say a couple of things. As you look out at the western basin natural gas outlook in terms of a production profile, what sort of long-term expectations do you think you would have? We transitioned from flat to down, do you think a 2 to 4% decline rate out over the next four or five years is reasonable?

Good afternoon, Andrew. It's good to hear from you.

Yeah, good to see you.

The western Canada basin I think we need to realize is a maturing basin. I'm not saying mature, but it is maturing. I think some of the industry results are beginning to bear that out. Our expectation is that we will continue to focus there on profitability of the basin. We will drive first quart tile operating costs. I indicated 86 percent replacement given the maturing nature of the basin, we consider to be a pretty significant accomplishment. As we go in time, I believe in our release we indicated something like 690 million cubic feet a day for next year. As we go out over the next couple of years I would expect to see the production be closer to 700 million than 650.

But obviously if you are not replacing reserves, ultimately you are going to start to see some decline over a period of time. And it's difficult to draw that much farther out than a couple of years. We, the way we run that business, we look to having something like one and a half years of prospect, drillable prospect inventory going out in time. We assure ourselves when we set the capital program that we have a sufficient number and quality of prospects that we can be quite selective in what it is we drill. I think we look at that each and every year. As we get out in time if we find we can't match up prospect quality with the sort of $425 million level of expenditure that we are making, we may choose to manage that basin differently.

Well, that's great. Thanks. One other, if I could. At the analyst meeting you spoke about a desire to reconfigure to a degree the neater upstream portfolio. That is, optimize which countries you wanted to emphasize capital and expansion in and perhaps prune out some others. Have you come to any further conclusions since that time that you can share with us?

We really haven't, Andrew. I think I indicated at that time we are going to take this year or basically the better part of it to go through an in depth analysis of the value that we see in the assets that we have. And do a screening of new opportunities that we might sees as being attractive for us to get into. And I think I indicated that it's entirely possible that if you go out a couple of years, we may be in one or two, maybe -- may not be in one or two countries that we are in today, and we may find ourselves in one or two -- I'm sorry, we may not be in one or two countries that we are in today and we may see ourselves in one or two countries that we are not in today So there may be some change in the mix here, but we really haven't taken any decisions on that yet.

Great. We'll stay tuned for that. Thanks, Ron.

Thanks.

Our next question comes from the line of Mark Gillman with First Albany Corporation. Proceed with your question.

Ron, Harry, good afternoon. Could you give us some detail on the recent drilling results and at Hibernia and Terra Nova and what in particular you did from a reserve standpoint on those two?

Hi, Mark. We drilled two fairly significant step up wells, one in the Avalon formation at Hibernia and one in the far east block following up on the discovery well last year at Terra Nova. We are in the process of evaluating that. It will take us time to put the whole picture together to be honest from a reserves point of view which is what you were asking about. Certainly the Avalon will depend on flood performance which we only have a couple wells on, so it's still early days. We need to do more drilling in the Far East to delineate that reservoir properly. We will be drilling two wells in the Far East this coming year. And we will continue the development and monitoring of performance on the Avalon. I will say in both cases we have had pretty encouraging results from a technical point of view in both of those reservoirs. We haven't -- we haven't really assembled all the data to the point where we can with confidence say that we could put out a new reserve number. We are basically staying for now with the ones that we have.

Basically there are no changes in the reserve numbers for either the Hibernia or Terra Nova interest, Ron?

Not at this point, no, Mark.

Okay. Thank you.

The next call comes from Kevin Calderwood (ph) with some Salomon (ph) Partners. Please proceed with your question.

Yes. Thanks for taking my call. I would like to ask about the clarification on your comments on Kyoto. I don't want to presume that you will be even looking at sanctioning until this until you see regulatory approval in Q2 '03. But will you spend the money you highlighted in the budget press release in 2003 to continue to plan for this project?

I gather I'm talking to Steve Calderwood, am I? Kevin's brother?

Yes.

Let me elaborate a little bit on where we sit with respect to Kyoto in our forward plans. We have two decision points in 2003. The first one around the end of the first quarter here when we will be deciding to spend upward of $200 million on detailed engineering and long lead time equipment that will firm up the cost estimates that we would use to base an appropriation decision on in the fourth quarter, sometime in the fourth quarter. So what we are looking for from the federal government is, I might call it a framework of principles that would govern the fiscal terms around these longer term large projects. The assurance that we have so far from the feds really has a lot to do with the management of our base business, projects and assets that are currently on stream. And because it only takes us out to 2010 doesn't do much for us when we think about what about longer projects that aren't starting up until 07 or 08 in our case? They are receptive to this. They understand the issue. We are in some very productive discussions with them at this point. With the idea that we come together with an understanding of the principles, as I said, that would govern these longer term projects in time for us to take this decision towards the end of the first quarter.

Hopefully that sort of clears Kyoto off. That's our objective. When we look at this decision on the major go informed appropriation of the big money in the fourth quarter of this year, we can do that on the basis of costs that we see, our projection of the business environment, the standard factors that surround a project decision making, one of which will be some degree of certainty around what the Kyoto impacts might be. So that's basically where we're trying to get to.

If I could ask one more question. Excuse me if I missed this on the beginning part of your call, but with respect to the Oakville refinery, was there any more information on what was the cause? I notice you being dismiss I have in terms of the fact that it was a minor fire. Does that mean in terms of utilization of the refinery it will be back up to full capacity any time soon?

The cause as best we can tell, it's still being investigated appears to be weather related. We had a very extensive cold snap in the Toronto area. I guess maybe you experienced that as well down where you are. So we had a piece of equipment freeze up as a consequence there was a line that ruptured. So napta (ph) spilled out on to a pump and that caused the fire. The damage is localized. It's mostly wiring and instrumentation in a localized area. We expect that will affect one of the two trains that we have at Oakville. Half of our capacity will be out of commission for anywhere from ten to 14 days while we make repairs. And we are just now in the process of lining up some alternative supply so that we can continue to supply our customers. So anything like that affects the reliability. We hope flow through the supply arrangement we can nullify that through profitability, if you like.

Thanks very much.

Our next question is from the line of Brian Dutton (ph) with UBS Warburg. Please proceed with your question.

Yes, good afternoon. Two questions. The first is on the convenience store sales. Ron, you mentioned that C-store sales were up 30% this year, or in '02. Do you have a same store sales number?

Hi, Brian. Same store sales are running about 20 percent ahead of this year. 10 percent of that 30 is new stores that we built.

Great. And the second question is back to Hibernia. You had some very strong production volumes coming from Hibernia in the fourth quarter. Then gross volumes were running 205, 210,000 barrels a day. Is that an indication that down the road we may be seeing an indication on the maximum daily allowable that the government permits on a calendar day basis?

The fourth quarter on the East Coast for both Hibernia and Terra Nova was exceptional in a calm of ways. In both of those platforms we were running peak production tests as backup for an application that we will be making, or have made for increasing the allowable production in both of those fields. So it's not a sustainable rate in that sense. The other thing is that we did not have any planned or unplanned shut downs. We had very few if any weather related turn downs which we are experiencing, for example, in January because of the weather off the East Coast and the difficulty or inability in some cases to actually get the shuttle tankers up to the tethering buoy. So I think you need to look at the fourth quarter performance in both those fields as being somewhat exceptional.

Okay, thank you.

Ladies and gentlemen, as a reminder, to register for a question on today's conference call, please press the one followed by the four on your touchtone phone.

Our next question is from the line of Robert Plexman (ph) with CIBC World Markets.

Given what we have seen in Venezuela in the past few months, how are you feeling about that country? You have the Sava (ph), and what do you do next with that? If you give us an update on the Saranegro (ph) as well?

Be happy to do that. Venezuela is a situation that we are following very closely. I think the outcome at this stage is very difficult to predict. But I do think that in the long term we will see a return to some measure of stability in the oil business in particular. I think that's inevitable. Whether Chavez stays in or leaves, that country is so dependent on oil income and foreign investment in the oil business that I fully expect that we will see some return to stability there within this year, in fact.

So I think the long-term value of assets an investments in Venezuela are going to continue to be as attractive as we might have seen them say a year ago before a lot of this disruption started. The current status of La Saba (ph), that's a conventional heavy oil discovery. Has three or four wells in it. And those one or two of those wells really needs to be put on long-term test to determine the long-term deliverability and reservoir draw that we can expect out of that in order to design a development scheme and really judge some economics around it. Of course, with all the disruption and everything shut in, there's been absolutely no progress at all on that long-term test facility. So that's where La Saba sits. And Saranegro, of course, it's hard to get anyone's attention on progressing a right of first refusal in the current circumstances. It's difficult to say what kind of timeline we might be on there until the Petavesa (ph) management are back at work and there's some stability in the oil business in particular.

Thanks, Ron.

We have a follow-up question from Mark Gillman with First Albany Corporation. Please proceed with your question.

Harry, I wonder if you can perhaps explain in English that maybe even I can understand the change with respect to the accounting on the foreign exchange translation and what it means?

Hi, Mark, I'll be glad to. What we are doing here is changing the accounting for the IBU to recognize the basis and the way that we manage it. The reason for the change at the year end is, it took us several months to really understand how the cash flows worked before we could move to the self sustaining. The essence of it is they basically finance their own operations. Most change that you would see will be the reporting of the Canadian Euro effects impacts will no longer show up in the income statement. Instead those show up on the balance sheet.

Harry, is that the balance sheet translational impact or the operational impact or both?

It is the translation of the impacts on items like future income taxes and site restoration and those things on the balance sheet. And so the only, going forward the only impacts you will see on earnings arising from foreign exchange will relate to the currently outstanding U.S. dollar denominated debt.

Okay, I've got it. If I could, one follow-up. Ron, unless I missed something, you changed the way you are quoting the F and D costs on the western Canadian program. I thought you quoted them in the past on a B plus B basis. Now it looks like you're talking about a peak basis proven. Simultaneous there with, we go into a program that going forward looks like it has a little bit different dimension. I thought frankly the prospect inventory was in place for at least maintenance if not modest growth on a high return basis going forward. What am I missing here in terms of apparent changes in the thinking?

Mark, the F and D costs are on the same basis we've always used with proven costs as the denominator. There hasn't been a change there. Your question about the going forward strategy here, it is no different than it has been. But I think what we expect to see is first of all our F and D costs will continue to go up as they have over the last two or three years. That is simply a factor of the, what we are seeing in the basin in general is that there is less and less gas found for each successful well. So if you project that forward, you would expect to see that kind of trend going into the future So I'm not sure that that strategy -- I don't see that strategy being any different than what we have been, than the tract that we have been on. But you get a different outcome when you are that 85 percent reserve replacement than you do when you are at a little over 100.

You're saying --

Does that help?

It doesn't in your mind make sense to exploit that prospect inventory at a little bit greater clip that might take the spending number to -- I don't know, 500 million? Five and a quarter?

Well, that's a question that we've asked ourselves, in fact, Mark, if we shouldn't be -- not so much accelerating which I think was the notion you were proposing here, but basically being more aggressive in the basin in total. But we have tested the capability of our organization from a technical point of view to identify, acquire and develop drilling prospects and execute a program. And we have found that we can do that most effectively in the range of the 425 to 450 that we are spending. And if we start to stretch ourselves beyond that, we get very close to the margin of effectiveness, if you like. So we are quite comfortable executing at the 425, 450 range. We are comfortable with the fact that we would expect to see our finding and development costs increase somewhat over time. But still maintain in the first quartile. That's what we consider to be extremely important and stay within the range of what we consider long run profitability in the basin given our price outlook. We look at this from several different directions and conclude that the track we are on is the would be one to stay on.

Finally, Ron, you mentioned increased allowable at Hibernia and Terra Nova, can you provide on a gross level what level you sought permission to go to each?

I really don't want to give specific numbers here, Mark. As I indicated before, this turns out to be a bit of a negotiation with the C N O P B. Our strategy here is to try to get the allowables up at a level where they don't really constrain production. In other words, we can feel free to operate within the constraints that, the physical constraints that exist in the facility itself and the reservoir limitations that are part of our ongoing development drilling program. And basically that's the number that we see -- that we targeted for 2003, which is 79,000 barrels a day.

Ron, am I correct that 150 is currently the number at Terra Nova and 180 in Hibernia?

Annual allowable at Terra Nova is 150 and the annual allowable at Hibernia is 200. That's currently what we have in place.

Okay, thanks very much.

And our next question is from the line of Bob Lian (ph) with CI Mutual. Proceed with your question.

Hi, good afternoon everybody. I got on a little bit late. I apologize if this was asked. Your thoughts on the North Sea, I know when you bought the Vava (ph) assets, it wasn't considered the growth area for you guys, more of a maintenance area going forward. I wonder if your thoughts there have changed at all with the number of assets that are for sale and as the balance sheet gets stronger. Would you consider further acquisitions in that area at all? Does it just not meet your criteria?

Hi, Bob, we'll go for it. We haven't addressed the North Sea previously. So maybe I can help you out on this. Our picture of that really hasn't change. Our objective in the North Sea is to try to sustain a total, something around 50,000 barrels a day. The nature of that basin and those reservoirs in particular, because they are so prolific, is that you've got a fairly rapid decline in the base case. And then as you bring projects on, of course, because they are so prolific you have fairly high production rates at the start. You're going to see a lumpy picture out through time even if we are successful in averaging say 50,000 barrels a day. So the drop that you may be referring to that we referenced in our press release from 50 some odd thousand this year down to 40 some odd thousand in 2003 is not unexpected. We expect to recover that back in 2004 when we bring on the Clapham field on the UK side and later on the L5B gas side on the Dutch side.

That's fine. I'm comfortable there. But no thoughts in terms of incremental acquisitions? Just given there does seem to be a whole pile of stuff for sale? No changes on that front?

We are always on the look out for attractive acquisitions in the areas we operate an the North Sea is no exception. If we saw something within our existing infrastructure or even gave us an entry point into another infrastructure cluster that we saw as being attractive, we would be quite happy to look at it quite seriously. So part of our plan in the North Sea would be to, where it is attractive, make asset acquisitions that fit.

Okay, thanks, Ron.

Our next question comes from the line of Morton Meriner (ph) from First Energy.

You are over 2.5 billion in cap-ex this year. Any idea what the company would be exiting in the 2003 volume wise?

Exiting out of -- you mean production volume wise? I think all you can do from that perspective is add up those numbers that we've given you for the individual areas. And that's what we expect our average to be through the year.

Right.

I think we indicated the one item that is coming on stream in the year is the second L and G train at Trinidad, which will affect the exit rate.

Let's look at this another way, then. The volumes you put out in the press release in terms of guidance for 2003 aren't materially different or virtually identical to what you actually did in the fourth quarter. So you are spending two and a half billion dollars. I realize you've got dollars there that are really for projects that are 2004 and beyond. You've got obviously the R and M dollars in there also. So I guess my question is, how much is maintenance dollars of the 2.5 billion? How much is 2004 and beyond gross dollars and what is the growth dollars for 2003?

I don't have that specific a breakdown, but I think you need to recognize that if you start walking through our different businesses, I did comment on the fourth quarter production volumes on the East Coast as being somewhat exceptional.

Right.

I think I commented on the North Sea where we expect to see some decline next year. So we are spending money in 2003 on projects that won't necessarily materialize in the current year. We are spending money, for example, on -- I mentioned 200 million plus on detailed engineering for projects that won't go on stream until 2007 time frame. I'm not sure I can even answer your question. Even if I had the analytical tools to do it.

Fair enough.

Your next question is from the line of, a follow-up question from Mark Gillman with First Albany Corporation. Proceed with your question.

Ron, have you guys assessed either the strategic need for the opportunity to financially participate in subsequent L and G trends in Trinidad?

We would be interested in doing that, Mark, but it's contractually not easy to get in when you passed on the opportunity in the first one.

Did you pass? Or did Veba (ph) pass.

Our predecessor company passed.

You are bound by that?

Yes. I don't see that being a real possibility for us, Mark.

You say there's a constraint on your growth capability there?

Not particularly. We have a attractive fooling arrangement with the L and G owners. We are pleased with the gas contract situation that that puts us in. It hasn't really been a constraint, no. As I indicated in my remarks, we nominated for some production into this second train. And that really hasn't constrained us in any way from being able to market reserves.

Does it disadvantage you competitively, though, going forward?

Not particularly, no.

No?

If you are asking would I rather be in the L and G business? The answer would be yes. In that particular instance, it would be obviously recognized a possible limitation. We are set up from a contractual point of view.

Thanks, Ron.

Ladies and gentlemen, as a reminder, if you would like to register for a question on today's conference, please press the one, four.

The next question is from the line of -- follow-up question from Morton Meriner from First Energy. Please proceed with your question.

Gentlemen, I think the question was kind of asked earlier in terms of neater deal flow, is it higher as we sit today than it was a year ago when you were working through Veba or are with high, low prices are you seeing less viable transactions crossing your desks?

The deal flow from our perspective always seems to be a little lumpy. But I think if I think back over the past year, the only significant transaction that I can put my finger on would be the sale that BP made of the 40s field and some assets in the U.S. to, I think it was Apache Corp., which was a pretty significant transaction. I see that there's some expectations, speculation from the analysts that there will be similar sales from the super majors like BP, maybe even Exxon, Mobil and Shell that we might see in the next little while I don't know if those are price driven from a pricing point of view as they might be strategy driven. I would think that those bigger companies in particular are a little longer term thinking than the current price environment. But who knows.

Okay.

We have a follow-up question from the line of Steve Calderwood with Salomon Partners.

You mentioned the fortunate timing with respect to the Veba assets and the response of oil prices. Does that make you perhaps want to lock in an oil price for a portion of the Veba production or the production that you have? Or are you committed to sort of staying relatively unhedged on your upstream assets?

We are committed to staying unhedged, Steve. Having said that, I would never say never. There may be circumstances that we would find ourselves in the future where we might see it attractive to sell forward some production for purposes of establishing some certainty around cash flow, but we don't really see that need right now. Our balance sheet is in very good shape. That will basically stay open on the market.

Absolutely, thank you.

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

Thank you, operator. And thank you, everyone, for joining us this afternoon. As always, if you have any other follow-up thoughts, Derek (ph), Dileon (ph), and myself are available so please give us a call. And thanks for your attention today.

Ladies and gentlemen that does conclude the conference call for today. We thank you for your participation and ask that you please disconnect your lines. Have a good day.