Suncor Energy Inc (SU) 2002 Q1 法說會逐字稿

Ladies and gentlemen, welcome to Suncor Energy first quarter results conference call. I would now like to turn the meeting over to Mr. John Rogers, Vice President, Investor Relations. Please go ahead, Mr. Rogers.

Thank you Tracy, and good morning everyone and thanks for listing into our first quarter earnings release and also the outlook for the second quarter. We're actually

In the room I have with me

James, our Corporate Controller and Ken Alley, the Vice President of Finance. And in a remote location, we have Mike O'Brien, our CFO, he's down in Calgary. So, I think between the four of us, we should be well armed, hopefully to give you a good update in terms of the quarter and the outlook for the second quarter and hopefully answer your questions. So, we'll start out as usual with turning this over to Mike O'Brien who will comment for you on the first quarter, and then we will go on from there. So Mike, if I can turn it over to you.

o'brien: Thanks John, and good morning everyone. Just a couple of overview comments here, you know, we did have a very complex quarter of breaking in our new assets at the Millennium

and plus somebody called the first quarter for the integrated to be perfect storm. So, we had quite a complex quarter.

This guidance -- this release and guidance

a little than normal because we are going to try and anticipate some of the questions that you had when we gave you the guidance earlier in the month. So, I'm pleased to report our performance during the first quarter are 90 million, down from a 125 million during the same period last year, and our cash flow was 181 million compared with 275 during the same period, but our earnings did reflect, you know, substantially, in fact, dramatically lower commodities and refining margins, but we did see a substantive offset from the new 65,000 barrel a day increase we got out of the Millennium assets in spite of all the ups and downs during the quarter.

Let me give you a brief reference back to the guidance call that we gave you on April 4th. At that guidance call, we said earnings would be in the $80 to $85 million range and they came in slightly higher at 90 million primarily stronger commodity price and a little stronger sales volume. We predicted cash cost in the $16 to $16.25 Canadian range and the actual cost came in at $16.35 cents, so about 10 cents higher, and I'll speak in some detail to that and try to anticipate your questions there, a little later on in the presentation here.

Most of the other numbers we predicted were right on target. Just a quick comment on our refining and marketing business and natural gas and refining and marketing in the quarter, earnings were seven million down from 23 million the previous year, dramatically lower refining margins, they were off about a third and some softer volume because of warmer winter weather and recession impact really in eastern Canada.

Going into the second quarter, we're starting to see growth in the economies and we're seeing strengthening margins as we -- and volumes as we go forward. On the natural gas side of the business, dramatically lower. First quarter last year, we'd made $53 million after tax. This year five million. Natural gas prices way off, down 70 percent, quarter over quarter. Volumes were in the predicted range, roughly the same as the first quarter last year, but our exit rate was in excess, and in March was in excess of 180 million

. So, we are just starting to see some growth in that business which is what we have been anticipating.

So, let's turn now to Oil Sands and just some overview comments, you know, at the end of 2001, we completed the journey that started four years ago. We said the first six months would be a bit of a rocky ride as we bought this plant and all these assets up onstream and we're now starting to see the benefits of that hard work. In spite of a number of major challenges that we had during the quarter, we were able to produce at 60 percent of design capacity of the Millennium assets during that quarter.

And this was achieved in spite of some very cold stretches of weather and colder than we had seen in a number of years actually, with a number of consecutive days below -30 during January and that caused us some problems. We had to make adjustments and fix some part of the facilities during that period and when we were hit again with cold weather in March, it had little or no impact on production. So, we're starting to work our way through that whole problem area during the quarter.

The power outage which we had, which really to a large extent is a very unique outage and a function of, I think, a startup of lot of new assets and new relationships, it was the first power outage we'd had in six years. So, that again contributed to some complexity for us, but we did recover, but it did have an impact on the quarterly production. I think one of the things that we would say is that we probably got a little ahead of our selves in terms of our -- of our first quarter forecast and these assets came up so well at the end of last year, I think we were a little overconfident in terms of what kind of problems we'd say that we'd faced as we -- as we broke these ends. So, I think that probably is some of our problem and why we missed our guidance that we gave in January.

If you look at our confidence in this facility, I think what we've seen is we've seen that this plant has -- all plants have been up to design capacity or better. On an integrated basis, we've had the same, we've had over design performance. So, we feel very confident that these assets are going to do what we -- what we expected them to do. In spite of the eight day maintenance shutdown that we had on the hydrogen plant, we're already averaging over a 195 thousand barrels a day during the second quarter.

And in fact, in the last few days, we went well over 200,000 barrels a day. So, going into second quarter outlook of 200,000 barrels a day, we believe that's a marker that we can meet. John will talk to you in a minute about the outlook for the second quarter and the full year, but I think what we wanted to do was recognizing that we did lose some ground in the first quarter and recognizing that, you know, the first six months is a break-in period for these assets.

We've throttled back our expectations a bit until we see ourselves running at sustained maximum capacity. And our expectation is that we will see ourselves in that stage during the third and fourth quarter of 02. There are two other areas that are being affected by not running at design capacity. One is cash cost and the second is our SG&A. Our cash cost were $16.35 per barrel.

On the surface, they are disappointing, but when you look underneath it and I think Rick talked of this in the guidance. There were four contributing factors and most of them are one-off. Number one, during the quarter, we did not run the plant at design capacity, and given the fixed cost nature of our facilities, that cost us about $2, Canadian, per barrel. So, about $2 a barrel Canadian because we didn't run at design capacity.

Second factor is the additional work that we had to do in the lining of the plant protecting it from cold weather, the impact of the cold weather, the power outages et cetera., and that added about $1.70, Canadian in additional cash costs that we believe that would not be there during a normal winter period.

The third major element was overburden. We talked to you about that in the guidance, but we spent $53 million in overburdens during the first quarter, that is about 40 percent of our expected $140 million spent over the year. From our point of view, we've made a decision to accelerate the overburden removal, it's counterintuitive, but it actually is more efficient in the winter when you don't have road issues and so forth and so on.

This timing difference added about a $1.20 Canadian to our cash cost. So, we still expect the entire to be 140 million, what we franchise-loaded. So that's -- the other two are one time issues. This is really a timing issue. And the fourth issue, there were some other small amounts that added about 35 cents per barrel to our cash cost, and one of the most significant one was our accrual around the long-term incentive payout program that paid out in the quarter and that again was a one time item. So, if you add up all of these items, it comes to about $5.25 cents Canadian to our cash cost during our first quarter.

So, of the 16.35, $5.25 cents is associated with either one time or timing items as we see it. And going forward, most of these differences go away such as the one-off expenses for the liability that cost us a $1.70, a $1.20 for the variance and the overburden removal and those things will go away as we proceed through. The one fact that will continue to be present until we are running our plant at 225,000 barrels a day will be that $2 impact because of our fixed cost. So, soon as we get up to that 225 sustained level, we'll see that $2 disappear.

So, we have changed our expectations a little bit on both volume and cash cost and we're trying to reflect the reality of what happened in the first quarter and create some expectation that will see some of that in the second quarter, and that in the third and fourth quarter, we should have this facility lined out. So, with that in mind, our cash costs are predicted to be $13.50 cents in the second quarter and our production to be or our sales to be around 200,000 barrels a day, and a there is about at least $1.50 of that 1350 that's directly attributable to higher cash cost because we are not running at the 225 level.

As our production moves towards design capacity in the second half of the year, you'll see our cash cost drop fairly dramatically. So, for the year in total, we're forecasting $12.50 Canadian per barrel. But there are still costs in the systems, and we haven't given up on our 850 to 950 goal, we've had a major cost review going on at the facility as we speak, and we believe that we'll get the plant up to design capacity, we believe to be that over the next little while here, we'll be able to start taking structural costs out of the system, and so, we haven't given up on our 225, we think that we'll be there by the end of the year, and the 850 to 950, we want to take the cost down to that level over the next twenty four months. So, all of those things are still intact.

The second area you'll note that is higher because of running at less than design capacity as our SG&A expects. And as I think you're aware, we depreciated and amortized some of our assets on a unit of production basis, but the majority of our assets are depreciated on a time basis. So, we've got to fixed amount of dollars we have to depreciate over whatever barrels we produce. SG&A this quarter was over $6 a barrel, reflecting the new Millennium assets being depreciated starting Jan 1, but not running at full capacity. Until we're running consistently at 225 a day, we won't see those rates get down to the $475 range that we predicted, but we do predict that we will be there.

The only other point I was going to comment on is our debt. At the end of March it stood at 3.3. It did rise slightly during the quarter from yearend due to timing of capital spending and an operational challenge that I spoke about earlier and accelerate overburden, et cetera, but we still expect that we will reduce that by about 700 million by the end of 03. So that is, sorry about the length of that, but we are trying to anticipate your questions which you had during the guidance call. With that, I'll pass it over to John to broaden out the picture with the outlook. John ...

Thanks, Mike. That was almost as long as the press release. I'll just give you a quick overview of the -- of the second quarter and what we're expecting for the year. Mike went through many of the points with you, but I would also reinforce a couple. During the second quarter, we do expect the averaging about 200,000 barrels a day. We did note in the outlook that quarter to-date, second quarter to-date, we are averaging in the neighborhood of about 197. So, certainly that 200,000 barrels a day marker looks pretty darn good, and for the full year, we are predicting 200,000 barrels a day.

That is down from the previous guidance that was 210, but I think you know, given our production volumes that we did have in the first quarter, it would have been very difficult to get up to the 210. So, we're just -- we're just moving it down slightly. The sales mix other than in the second quarter, we saw was a little bit higher, should be basically the way you understand it. So, there shouldn't be any change there nor would there be any change in terms of the expected realization on the crude with WTI equivalent at Chicago.

Cash-operating costs in the second quarter do reflect the lower production that we're expecting and obviously lower sales and at 1350, Mike did mention that in that 1350, there's probably about $1.50 in the cash costs that are directly attributable to not running at full capacity So, if we had been running at full capacity in the second quarter at 225, our cash cost would have been in the $12 range. So, by the end of the second quarter, with 1635 we had in the first quarter and then 1350 that we have in the second quarter, the average going into the second half of the year will be 1475 and we are predicting 1250 for the year.

So, obviously, in the second half of the year with the plant running in full capacity, excuse me, we should be at those cash costs falling off dramatically exactly the way you would think they would go. So, you know, natural gas is basically the way you understand it. Our volumes came in within production during the second quarter and our outlook for the second -- in the first quarter, our outlook for the second quarter and our outlook for the full year is basically the way you understand it. So, no real changes there.

On the second phase of the outlook, we did identify for you that you know we still are lining out the plant and there still could be some possibility for some production interruption and we think we've have taken that

into 200,000 barrel a day average that we have left you with, but, you know, I just wanted to mention that, reinforce that point. Natural gas prices, we're seeing a little bit higher now second quarter to-date, they're about 20 percent higher than the what we realized during the first quarter. So, a little bit left there

any prices, also a little bit of good news in the -- in the downstream with refining margins currently at about three percent higher than those realized in the first quarter of 2002.

Retail margins are 11 percent higher. So,

in the downstream which would be nice because you know, with seven, we're looking for bigger things for Sunoco, going forward. We did have a small fire at the Sunoco Refineries that impact the production, the Hydrocracker is expected to be back up late in April, and so, that's should -- that should fix itself. And the final point, we will do a 25D turnaround during

Sunoco during the second quarter also. We did outline the crude oil hedge position for you. So, the details are in your -- so you should be able to refer to that and update your models from that. So, Tracy, with that, that's all I was going to mention and I will turn it over for questions.

Certainly. Thank you, Mr. Rogers. Thank you, Mr. O'Brien. We will now poll for questions. If you have a question, please press one on your touch-tone telephone. If you're using a speakerphone, you may need to lift the handset first and then press one. And should you wish to cancel your question, please press the number sign. Please press one at this time if you do have a question. There may be brief pause for the participants are queuing for their questions. Thank you for your patience, gentlemen. Our first question is from Tom Ebbern from TD Newcrest. Please go ahead.

Good Morning. Two questions. The first on SG&A rate. Wondering if you can give us an idea of what percentage of your SG&A rate is determined on a time basis verses unit basis. And second question is on the light, sweet mix. I noticed for the outlook for the year, it's looking like about a 50-50 mix. Just wondering where you see -- it looks like Q2 is also about a 50-50 mix of light to sweet if you include the diesel in with the -- sorry sweet and sour with the diesel with the sour. Where do you see the lighter crudes increasing towards the second half of the years in terms of Q3, Q4, and are you still looking to get up to the 125 to 130,000 barrels a day by yearend on your lighter volumes?

o'brien: John, could I answer the first sweet sour and then you could pick up on the SG&A?

Fine.

o'brien: OK. Just to put in context here, you know, when you look at sweet, consider diesel part of the sweet mix. Diesel actually sells for about $5 a barrel over WTI. So, when look at sweet sour, you're looking at your light, sweet crudes and your diesel being the sweet portion and light sours and if we sell any

those being in the sour side. OK? So, when we look at this -- our current plant configuration, when the plant's running as it should, we would expect to be two thirds sweet, that's including WTI and diesel and one third sour.

And if you look as we go forward here through the balance of the year, if you look at the second quarter, you're kind of moving up into that 60-40 range, and it's rising then through the balance of the year as all the units are up. The first quarter was less than that because we had some of our hydrotreating constraint, and we've had some of that constraints with our hydrogen unit out. So, you're through with the first part of April, but basically you'll see a two third one third split and I think if you stand back and look at the operation, we're expecting to be in that state for currently -- in that state today as we speak and

basis, that's where it should be.

Great. Thanks.

And then Tom, I'll just answer your question on SG&A . Actually, most of the answers are depreciated over time and opposed to unit of production. If you think of the refinery that captures a lot of our capital costs, you wouldn't depreciate that on a unit of production basis because you'll depreciate it over 30-35 years if you'll do on a time basis. So, don't get the volumes then that we're expecting, obviously you're going to land up for the higher SG&A. So, most of the assets up at Oil Sands would be done on a time basis.

Thanks very much.

OK. Thanks, Tom

Thank you, Mr. Ebbern. Our next question is from Duncan Mathieson from Scotia Capital Markets. Please go ahead.

Thanks.

use some math here on your operating costs because I don't see how you can get to the numbers you're talking about in the second half. If I strip down everything that you talked about, Mike, the five and a quarter and down to $11.10 cents. By my math, you need to get to 1250, you're going to be in the ten and a half dollar range is what you need in the second half, and yet you won't be running at design capacity by the math that I see that averaged 200 for the year. So, you won't get the two $2 a barrel back either. So, I don't quite see how you get to these operating costs given the primaries you've given for production for the remainder.

o'brien: John, I think you've got the details there. Do you want to take Duncan through that?

Sure. Duncan, one of the major variables in there, there's really two that are going to come out and one is you have to remember our cash overburden. The total expense for the year is $140 million. We spent about 40 percent of that in the first quarter.

So, you will see our cash overburden removal charges second, third and fourth quarter to not be near as high as they were during the first quarter. So, we are really are into a timing situation. The second thing is obviously higher production volumes is going to reduce those costs and the third thing will be we really are looking at, Mike had mentioned earlier, looking at the cost base set up at Oil Sands and we have to look at reducing a lot of those costs or some of those costs within that. So, the combination of cash overburden removal, higher production volumes and

from the system should get us in the range that we are talking about.

OK. Thanks.

Thanks, Duncan.

o'brien: Thanks, Duncan.

Thank you, Mr. Mathieson. Our next question is from Brian Dutton from UBS Warburg.

Yes, hi. Mike, at the end of the fourth quarter, you had a substantial amount I think light sour in inventory. Have you taken down most of that inventory now because I did see that, you know, sales did exceed production, but just wondering where is that inventory level now stood?

o'brien: Well, I think that Brian, that we did take some of it down, but then we actually built some back up here as, in the last little while as we lost our hydrogen plant and we're producing more sour. So, we've still -- we've got more inventory than we would normally run, let's put it that way, and we just felt it was prudent not to push that into the market. We had a couple of our major customers for sour, CITGO was out of the equation and Coke was down for an unanticipated turnaround. So, that kind of backed us a little bit. We are now moving that into market as we speak.

OK. Well, Mike, having I think announced the retirement at the end of last year, I take this is your last conference call.

o'brien: Yes, it is.

Well, thank you very much for all the help and the candor in answering our questions.

o'brien: Thanks, Brian. I appreciate that.

OK.

Thank you Mr. Dutton. Once again, if you do have a question at this time, please press one on your touch-tone telephone. Our next question is from Brock Winterton from RBC Capital Markets. Please go ahead.

Thank you. You are planning to push the turnaround into next year and you've reduced your production estimates this year to 200 largely in line with, I think, the reduction and volumes in the first quarter. Are you actually taking a little more conservative look at the remainder of the year as well?

o'brien: I think that's a fair comment, Brock. It's Mike here. I mean, on a straight up basis, we do believe that the most appropriate time to do the turnaround is probably the spring of next year. We have been able to give ourselves a little bit of space by bringing forward maintenance in these

outages we've had. So, we believe we can -- with the appropriate time is to do is next year.

That doesn't mean to say we couldn't be in the situation where we'd still have to take it in the -- in the fall here, but our base premise is that we will do it next year, and yes, we have, I mean, we've taken the approach here that we're very disappointed we didn't meet our targets in the first quarter and we were probably a little overoptimistic in terms of that. There are things that we're going to see through the second quarter here that are going to unfold, we believe, based on our experience in the first quarter.

And so, we're just trying to say, let's get ourselves into a state where we can get the targets and meet them. So, we are being more conservative.

And in terms of next year then, would it be worthwhile for us to be thinking about something in the order of 215,000 barrels a day as a target?

o'brien: The annual impact of the turnaround of the old plant we're going to take it down for 28 days, that's the 115,000 barrel a day old plant and that's about an average of 10,000 barrels a day for the period. So, that would -- that would not be out of the bounds.

Right. Thank you.

o'brien: Thank you.

Thank you, Mr. Winterton. Our next question is from Robert Plexman from CIBC World Markets. Please go ahead.

Good morning, Mike and John.

o'brien: Hi, Robert.

The downstream return was pretty good considering how difficult the industry conditions were during the winter, and you mentioned in the release, you know, some of the -- some of the initiatives you have taken. Can you quantify the impact in terms of the cost savings and what the downstream return might have been without those -- the impact of those initiatives?

o'brien: Sorry I'm -- Robert, I'm not clear on what you're specifically asking. Which initiatives are you talking about?

The initiatives on the downstream part of the business, Mike.

o'brien: Yeah,

yeah.

I mean you have taken some initiatives in that business, cost savings and that kind of thing and just wondering if you can -- if you can quantify the impact of those cost savings. I mean if you are sort of left more exposed to the -- to the market with first quarter earnings, how much slower they would have been without the impact of some of the initiatives you've -- you've taken over the past while?

o'brien: Well, I don't think -- I don't think I have a number that I can give you. I mean it, I would not say it's a material reduction in cost that we have gone through, in fact, in the first quarter, we did experience, you know, year over year we had better operating performance.

So, it was more better operating performance year over year than absolute cost reduction, I think I would say, I mean I think what -- I think what we're seeing is when you look at relatively good performance, I mean, there are a couple of things that hurt our competition.

One was a lot of the competition are heavily dependent on heavy oil for their crude

and the shrinking of the light-heavy differential put pressure on those refining operations. So, that was one piece and the second piece, I'd say is that, you know, structurally the refining market and the retail market in Ontario are in pretty good shape so that, you know, the people aren't beating each other up because the utilizations are really good. So, I think those would be probably the two key points.

OK. And one quick question, second question, heading into the second quarter in consideration of that outage that you had, what's your product inventory situation like, I mean, do you have to buy, get them into the market and buy much product in the -- in the second quarter?

o'brien: We will be purchasing a little bit of product into the second quarter. Our inventories in the downstream have been grown to prepare for this outage. So, we don't think it'll -- it'll be significant.

OK. Thanks, Mike. And let me join Brian in expressing my appreciation for all the help. Enjoy your retirement.

o'brien: It goes both ways, thank you.

Thanks, Robert.

Thank you, Mr. Plexman. Once again, if you do have a question at this time, please press one. We'll take our next question from Wilf Gobert from Peters and Company. Please go ahead.

Thank you. Mike, this may be a bit of red herring, before McMurray, there was -- there was a murder in the Athabasca camp and I'm wondering whether that is causing any fallout in terms of the operations of the camp or even the operations of the facility and ...

o'brien: Are you referring to something that happened recently?

Yeah.

o'brien: That actually I believe happened at the Shell camp.

Yes, I'm sorry, I meant, yeah at the Athabasca Muskeg ...

o'brien: Right. OK.

So, I'm just wondering whether or not that has lead to any other problems in the general area as a result of the police investigation and camp life, if you want, which I understand that particular camp had a wet camp, a wet bar.

o'brien: Wilf, I am out of my depth here ,you know, I guess what we just see as you got so many people up there, it's a microcosm of what happens in the world. So, I'm not aware and I've not been made aware by Mike Asher that there is anything untoward as a result.

OK. That's fine. So, OK, good.

The only other piece I might throw in there, Wilf, since that we have been out of the construction mode for quite some time as we settled out our operations are running quite well, and, you know, I think coming together quite well for us that way.

Great. Thank you.

o'brien: Wilf ...

Yeah.

o'brien: I just wanted to compliment you on your perfect storm. That was a wonderful. I took that analogy too. I was having a new boat and a lot of icebergs around.

Well, it wasn't quite the same as Bob Peterson saying that refining a market business was a charity program.

o'brien: You know, that was a classic as well.

Thanks Mike, thanks again.

Thank you, and at this time, Mr. Rogers, I'm showing no further questions from the phone line. I would like to turn the meeting back over to you for any closing remarks.

Thanks Tracy, it's been quite a conference call. Let me take this opportunity to thank Mike O'Brien for everything you've done Mike, and communicating on everybody. So, on behalf of everybody, I will thank you. As I mentioned I'm up in Fort McMurray. So, if you do have any questions at all give John

a call or leave me a voice mail and I'll be happy to get back to you but other than that thanks for listening in and we'll talk to everybody later. Thanks.

o'brien: Thanks everyone, bye, bye.