Suncor Energy Inc (SU) 2002 Q3 法說會逐字稿

Ladies and gentlemen, thank you for standing by and welcome to the Petro-Canada 3rd quarter earnings results conference call. During the presentation, all participants will be in a listen-only mode and we will conduct a question and answer session. At that time, if you have a question press 14 on your telephone. This conference is being recorded. Thursday, October 31, 2002. I would like to turn over to Gordon Richie, Senior Director Investor Relations, Petro-Canada.

Welcome to Petro-Canada's 3rd quarter conference call for investors and analysts. With me are Ron Brenneman, the Chief Executive Officer and Harry Roberts, the Chief Financial Officer.

Before I hand the call over to Ron, I would like to start with a review of some of the key known operating factor that is affected reported earnings and cash flow in the quarter. Reported net earnings were again affected by foreign currency translation in the quarter which lowered earnings by $80 million. In addition, a restructuring charge in the downstream impacted earnings by $5 million. When you take out these effects, earnings were $294 million or 1.12 per share which on a comparable basis is up from 63 cents a share in the 3rd quarter of 2001 and up from 1.05 per share in the 2nd quarter of 2002.

Second cash flow, tax referrals resulting from a partnership in the Canadian upstream operations and the inventory valuation method prescribed for income tax purposes in a downstream sometimes called the -- effect. Impact cash flow from operations every quarter. These two factors lowered cash flow in the quarter by approximately $45 million or 17 cents per share. So on a comparable basis, cash flow for the quarter was 2.61 per share, up from 1.31 a share in the 3rd quarter of last year. And up from 2.22 cents per share in the 2nd quarter of 2 thousand 2. With that background, I would like to hand over the call to Ron Brenneman to provide his comments on the quarter and open up for questions. Ron?

Good afternoon and thank you for joining us what has turned out to be a very busy day of earnings releases across the industry. I know we are competing for airtime when it happens so thanks for participating. I am pleased to be sharing my assessment of another quarter of excellent results for Petro-Canada. Our strong 3rd quarter was driven by the continued execution of our strategy to improve profitability in the base business and to deliver profitable growth. Higher oil prices contributed financially, but I am pleased with the solid operating results we delivered in the quarter.

Before I review our success in upstream growth, I would like to comment on how our drive for improved profitability in the base business is paying off in the downstream. The downstream reported a solid quarter. Compared to last year, we were down and differentials were down from 50 million last year. Reliable refining operations were a major factor. We averaged 105% of capacity. The impact of this solid performance was partially offset with the mix planned for 4th quarter maintenance shut down at the old refinery.

We are planning a minor turn around for our Montreal in the 4th quarter. Our program to improve lubricants earnings by increase in the sale of high merchant products remained on track. Here today high margin sales are up 12% over last year and running at over 60% of total lubricant sales. Marketing performance also continues to improve. Sales are retail gasoline were up 6% over the 3rd quarter last year and up 5% year to date. The roll out of new image service stations is on plan and convenience store sales track 30% above last year.

One of the key elements in the profitability drive in the downstream is the need to improve cost structure. We are always looking for opportunities there. The marketing programs are progressing well and along with the move to shed low margin business in Eastern Canada at restructuring in sale and marketing groups. This resulted in a staff reduction of 15%, about positioned a $5 million after tax to the bottom that keeps the gas closure programs on track. The full effect allows us to achieve targeted downstream of 12% in 2004 and that's mid-cycle margin and commodity prices. The drive in the upstream also contributed in the quarter.

Western Canada gas production was 707 million cubic feet a day. Production was down due to plan turn arounds, it did exceed expectations. We had an excellent quarter with gross production of 261,000 barrels a day. Operating costs under $13 a barrel.

Performance benefited from the 2nd quarter turn arounds and from the availability of excess untreated inventory. Excellent performance. There is still reliability issues to be resolved before we can expect this level to be sustainable overtime. On the East coast, scheduled maintenance turn arounds were executed at Hibernia. They are up and running smoothly, delivering excellent profitability at today's prices. I am pleased with the performance of international business. International contributed earnings of $78 million, 27% of the total in the quarter and 2 $226 million in cash flow, a third of the company's total. Production increased in the North Sea and thanks to the addition of the western extension of the field and the UK sector. Production in Syria had 107,000 barrels a day and exceeded objectives as they advanced the development program on existing leases.

We are pleased with the international acquisition adding solid earnings and cash flow, particularly in the current price environment. Profitability improvements are the major factor in the quarter and the drive for growth boosted earnings and laid a foundation for the future. We began steaming the reservoir at the river project on schedule and on budget. Official production is expected by year end and production will ramp up to 30,000 barrels a day by the 4th quarter of 2003.

We are working with management to reevaluate the cost of the stage three expansion. This is a big project. It not only expands the capacity of the plant, but modifications will increase the quality and value of the total output. The project is running a little behind and the start up now will be expected in 2005. The regulatory approval process is advancing for our 80,000 barrel a day project. We expect regulatory approval sometime next year.

On the East coast, we are pursuing opportunities to increase production and extend the plateau period at Hibernia. We applied a regulator for annual production above the current 100,000 barrel a day level and expect response in the 4th quarter. We spotted a second deliberation in the Far East block in September and that we spotted an appraisal in the Avalon in October. A white rose project continues on schedule and we are planning up to two in the deeper water next year.

On the international front, production increased to 217,000 barrels in the quarter and a number here will contribute in the near term. In the UK North Sea, we had encouraging results from it as well. Development plan is being worked on, but looks like we can tie in the field just as we did with the western extension.

In the Dutch sector, we drilled a successful exploration well in the B block close to existing infrastructure. Petro-Canada has a 30% interest in the well operated by winter. In Trinidad, initial production from the gas project came on stream and averaged 19 million cubic feet a day and ramping up to 40 million. In Venezuela, the ryes remain outstanding for the projects. Progress is slow and it won't be resolved until 2003.

We have a more conventional resolution process and it could be sorted out this quarter. Most importantly for the growth plans, we are establishing the international platform that we wanted for longer term growth. With the integration of the assets and organization behind us, we are now turning attention to the future with a view to adding longer term opportunities. To conclude, I am pleased with what we have accomplished with the focus and drive to grow the company.

Solid praying performance and high oil environment have paid off. At the same time, we have taken the opportunity to pay down debt. 113 million in the 3rd quarter and 50 million in October. Our debt to debt plus equity is under 40% ahead of original expectations following the international acquisition. Looking to future disclosure, we will provide you with plans in December. The internal planning process is complete and we will have volume guidance for 2003 when we report 4th quarter results. We're happy to answer any questions you may have.

Thank you, ladies and gentlemen, if you would like to register a question press 1 and 4 on your telephone. If your questions been answered and you would like to withdraw press 13. If you are using a speaker phone, please pick up your hand set before registering. The first question is from Andrew Fairbanks from Merrill Lynch.

Hi there. A question on the downstream profit improvement programs. You gave us mid-cycle margin assumption and the business up to about 10% return. Has that mid-cycle assessment changed much with the 3rd quarter results or about the same?

The 3rd quarter results were pretty much on track with that. The business environment that we have seen so far in 2002 averages what we would consider to be mid-cycle concern. On a year to date basis, we are about 10% and if you will recall that's what we expect we would end up at the end of the year. We are halfway to where we need to be and expect that by the time we get most of our profit improvement plans in place of next year and should be on a running rate basis through 2004 at 12% target rate.

That's great. One more. What time frame do you expect to add up to the new plateau level? Is there any issue for 3rd quarter or later on?

Throughout 4th quarter, I would expect it to be there through the 1st quarter of next year. This is not unusual. The second strain just starting up. We are not having any real issues with the platform itself. Usually start up with something as complex as an LNG train is the issue here.

Did you get that?

Sorry. Yes. That's fine.

The following question is from Mark Gillman of First Albany.

Good afternoon, guys. What was the level you applied to increase the average turn over output?

For the average for the year?

Right.

We didn't actually provide a number for that. This ends up being a bit of a negotiation process. Basically you sit down and make an application based on data and you negotiate an outcome from that.

I guess I was surprised at the permitted average is only 100.

That was the initial start up that we were allowed. Of course that's what we are trying to increase. That's on an annual average basis. We are here to suggest that the field is obviously capable of a lot more than 100. We have been able to demonstrate on a daily basis that the facility itself is capable of a little in excess of 150,000. This is the normal process of starting up a facility in that regulatory regime. There is unexpected in the way it's unfolding.

Okay. Who is your partner on this?

It's Conoco and Phillips.

I thought they indicated that was a noncommercial well.

I'm not aware of that.

I'll check it.

We are still in the process of testing. The initial testing program that we attempted on the first go around was not very successful. That may have been what you read. I'm not sure. It was inconclusive and as a result we are still working on it.

You indicated a 299 gas price in Trinidad. That's not what you are receiving, is it?

Where did you see that?

In your release.

That's probably the average for all of our international.

Did I misread that?

Off the table itself.

I'm sorry, it says Trinidad.

I don't know if one of the guys can help me out on that, Mark.

I sure hope it's that high, but I suspect it's by a factor of about three. Let me know if you could. Finally, weren't there rights outstanding on Norway?

Norway is gone.

They were exercised?

They were exercised along with rights of first refusal on Egypt. They never acquired the assets.

The purchase price associated with that?

Not particularly.

The following question is from Greg of Goldman Sachs.

The first housekeeping item, what is your 2002 Cap-X looking like?

We are running a little behind the latest number that we put out. I think the latest number we put out that was after we closed on the acquisition and a little under $2.2 billion for the year.

Our year to date is more like excluding the acquisition something like 1.3. If we compare to what we had originally planned to spend by this point by nine months in the year, we are running about $200 million behind. It's a whole host of relatively small thing that came off the rails here. About 100 of that is in the downstream area. That's the case of where we are finding that we can get with less capital basis for our refineries, for example.

There is a piece of that in the upstream where I would have to say that in early days in closing of the international acquisition, we did not have a good handle on what that capital budget estimates in international. It's not that we are running behind the real projects, it's just that they were probably more optimistic than we would have been on what was achievable in the time frame. There is a little bit in western Canada that's typically issues of access which we generally have at this time of the year.

Another question, you are making applications for exceeding annual average at 100,000, would you expect that before the end of the year to get notice from them?

We made the application here about a month ago now. The CNOPB is responsive to this. The issue is if we don't get it, we have to cut back to 100,000 barrel a day average. They don't want that, nor do we. I think they will be timely.

Thanks.

The following question is from Norton Meriner of First Energy. Please proceed.

Good afternoon gentlemen. I got thrown off on the currency exchange issue. Obviously that foreign currency translation was fairly straight forward to figure out, but you added another charge of $23 million and you describe it on page 5 as 23 million and 9 cents per share. I wondered if that is forecastable in the future.

This is Harry Roberts. It relates to some monetary item that is are carried on the balance sheet that relate to the IBU. It really reflects the exchange rate differential between the Canadian dollar and the Euro. The forecastability, I guess, is that when you watch the movements in that exchange rate, a strengthening of the dollar relative to the Euro affects that balance. If you look at the finance sheet, the impact adds about $5 million in earning.

It will go back and forth, depending on how the currency does?

That's correct. We have two moving on the balance related to the debt. The other is the Euro related to some items that are things like future tax and things like that..

Great. The other question was more generic. I obviously saw you guys had heavy oil differentials. I was expecting you to do better on finding marketing. Any thoughts of where you are now and any thoughts for the balance of the quarter into the winter?

I'm not sure your first premises is correct. If we have narrower light heavy differentials.

I'm backwards on that. You're right. We run about 60,000 barrels a day. We are paying more for the feet stock. Marketing margins were compressed to some extent because of rising crude prices. I'm not sure. Any thoughts looking ahead in terms of margins expanding or differentials are wider and you are finding margins should be better over all?

I think differentials are widens somewhat from the 3rd quarter. I think in the last few days, we have seen a strengthening in this which has been the big drag on the crack spread. Of course we are seeing a bit of a falloff in crude price which normally allows us to do better. It's rather difficult to predict, but I would say that where we are at, we have reasonable quarter in the 4th quarter.

Seasonally there is always more difficult to look back historically, it's in the 4th quarter. I'm talking about in a relative sense.

One last thing you mentioned is the 2.2 billion for the year. You are about 200 million behind. Do you do the backwards math and be 700 million in the 4th quarter.?

200 behind where we thought we would be at the end of nine months. You can't prorate that. Without any information, if I were to make a guess today, I would say it would be difficult or impossible for us to catch that's up to 200 million shortfall. It might be 200 or 250 million by the time we finish. We will be giving you numbers in early December once we go through the business plan. We take a careful look at what we think we can spend for the remainder of the year in another week or so. At the same time what we would like to spend for next year. Early December we will have better guidance on that.

Thank you very much.

The next question is from Peter and company.

Thank you. Just coming back to this foreign exchange thing in the Euro guidance or the lack of guidance on financials for the 4th quarter, do you see changing your posture with regard to some guidance on these unusual swing items?

I guess the issue we have on these swing things being the currencies. We talked a little bit about the Euro effect. If you look at the U.S. dollar effect related to the debt, a one-cent increase in the Canadian dollar or U.S. One-cent increase results in a 21 million movement in earnings. Because there two currencies here and each can move together and apart, it's hard to provide that sort of guidance and so I don't know what to say beyond that expect that. I expect your view on where the currencies go is as good as ours.

Okay. It's just that you put out an average and a range of estimates from surveying analyst and have the number come in right at the bottom if not at the low end of the range. Obviously the company could help itself and itself shareholders if there was some kind of guidance to what's happening in that sector. You mentioned your business plan being done for early December. Are you planning a press release or conference call at that time?

We normally put out a press release that covers capital expenditures for next year and an estimate for this year.

Okay. Thank you.

It's usually the first week in December that we get that out.

Right. Thank you very much.

The following is from Paul Chang from Lehman brothers.

Good afternoon. A single question I'm looking at your international DNP division. The production because of the timing of the acquisition, production for the 3rd quarter sequentially is up more than 50% compared to the 2nd quarter. Both oil and gas prices and you will realize on the international it's higher than what you realize in the 2nd quarter. With that in mind, you will expect on a sequential basis, the earning will be up more than 50%, but the international is up only about 35%. Is there any issue or anything we should be aware that why the earnings are not up more?

I need to correct a misunderstanding there. The production that we reported on a daily basis was 200,000 oil equivalent barrels a day and what we are talking about is 215.

In the 2nd quarter you don't have to full quarter of operations, right?

We only had two months. Right. By definition, your actual warning or that actual barrel you will be able to sell is up more than 50% or roughly. Your oil and gas prices that you realize on those barrels or gas that you can sell is higher in the 3rd quarter than the 2nd quarter.

If we assume on the same cost structure on that basis, you will come to a simple conclusion that on the sequential basis, your 3rd quarter earnings should be higher than the 2nd quarter by at least 50%. You are only higher by about 35%. I am not sure if it's second to 3rd quarter.

What has the running rate been for the international business on a monthly basis?

In the 3rd quarter, we made two adjustments in international business from from an accounting and one from a tax point of view. The accounting adjustment had to do with the reserve definition basis or the production sharing agreement in Syria that we use for purposes unit of production depreciation and that impacted the running rate by about a million to a million and a half a month from an earnings basis. In effect, we took the earnings in the 3rd quarter were negatively impacted by that amount that was attributed back to the 2nd quarter two months in the 2nd quarter as well.

Sorry to interrupt. That mean that is for that adjustment, it will make it roughly about four to five million impact and another three million retro active and the total impact is about $8 million or so.

That's right, but I will give you the bottom line. There is another factor here as well. The UK tax rate. Prior to closing, sometime in June, the UK government announced a change in the tax rate from 30 to 40%. It didn't actually go through parliament until the 3rd quarter sometime in late July. We couldn't actually book the impact. What we are here to do was book the recovery in June into the 3rd quarter. That's another million and a half.

When you go through all of that, the running rate on the international business for the 2nd quarter was about $25O million a month for May and June. The average for the 3rd quarter when you normalize that out was about a million a month. That's basically the impact of better prices in the third than the 2nd quarter. The other thing I point out is that we know the cumulative effect, we knew the per barrel impact at the time of the investor day conference. Those factors in the tables that you would have picked up in the investor day conference are on a revised basis, running rate basis. To the extent that you are using that data to predict earnings, they accurate.

You say that the 3rd quarter is about 30 million a month. I thought you reported 78 million profit in the for the international.

Yeah, but I just explained that --.

That was for the judgment. That's fine.

-- that was impacted by having to make adjustments for the 2nd quarter.

That's fine. Very good. Thank you.

Our following question is from Duncan Madison.

A couple have been addressed already, but I'm confused on the allowables. You talk about the capacity that is generally 125,000 barrels a day and applied to go to 150. Now there is this 100,000 barrel a day number. At the end of the day we produce at 150,000 barrels a day next year?

Let me go back and make it clear. There two limits imposed on fields in that regime that supplies. It is a maximum daily rate which is now set for 150,000 barrels a day. At the start up it was 100. There is an average allowable for the year. That's sort of a total barrel number and you can work it back to thousands per day which is what we work in. That was initially set at 100,000 barrels a day. That would have meant we could produce in the calendar year, 36.5 million barrels. That's the limit that we are in the process of applying.

We have apply and we are in negotiations now to have raids. When all is said and done, my expectation is that we will not be limited by the numbers, so to speak rather by the capacity and the reliability of the platform itself. We are not limited by the reservoir. We have much more than platform capacity. Until we go through the business plan for next year and understand first of all where we are at in terms of approvals, that will be important. What we think we can deliver in terms of reliability on the platform, we are not putting out any numbers for next year.

Then the 150,000 barrel a day number that's tossed around is the annual allowable. You must have a higher daily rate than that.

The daily rate is actually 217,000 barrels a day. The annual rate is . That's why 217 is an odd number. It's part of this negotiation process and that's why we don't have one yet for them.

Thanks a lot.

The following question is from Mark Gillman of First Albany.

Just a couple of small things. I'm looking at the footnote and I guess I'm confused by the fact that I'm seeing about two or three different foreign exchange numbers. In the items not affecting cash flow, $31 million and in the table above it, $23 million and the text reference to an 80 million foreign exchange loss. Can you help out and tell me if there is tax effect?

To your first question, the $80 million referenced is the 57 that relates to the U.S. debt translation. The 23 is the total effect that relates to the liability side of the balance sheet on the form. The foreign operations. When you look at that 31 number that is underneath item six, that relates only to the long-term items. On the international business unit.

If you look at the working capital item that is related to the international business unit, they are a positive 8 or a gain on translation of eight million so that if you take the loss of 31 in the long-term items, add to that the gain on the working capital items, you have a net of 23 loss for the whole side of the balance sheet. In terms of tax effects, it's very important that there is about a two million dollar tax defect.

Discussing the downstream to benefits of inventory mix associated with the upcoming 4th quarter turned at Oakville. Also some excess untreated inventory. Can you talk about that and quantify both of those?

Those are two totally separate impacts, Mark. Let me deal with downstream first. Part of the seasonal effect is a swing from running heavier crudes in the summer time for asphalt production to lighter crudes through the winder for fuel products. That tends to occur around the 3rd quarter or 4th quarter switch.

It was exacerbated and the reason I commented on it, it was exacerbated by the timing of the shut downs which are also around the turn of the quarter. You end up and you don't want to go there because it's complicated. You end up with an earnings impact negative in the 3rd quarter and to some extent gets recovered in the 4th quarter. That was the issue I was referring to. Our 58 million downstream result was negatively impacted by this inventory swing which works its way through the earnings effect.

You're right. I didn't want to go there.

It's ugly. The second issue I mentioned is more straight forward. Its conversion units for the turn around is the 2nd quarter, of course it continued to run the mind. There was a short turn around in the mine, but build up some unfinished an intermediate processing units.

Once the conversion units came back up after the turn around, they were able to run off that excess inventory. The situation that sin crude has right now is the limitation on a steady basis also. Aurora mine is producing less than designed capacity. There's still reliability issues that need to be sorted out before we can expect to see this kind of production level and consequently that is more straight forward.

Thanks a lot.

The next question is from -- of Peters and company.

Regarding Venezuela, you can go back to that during Q4 there will be a resolution to the concession?

I said I expect to see a resolution. Because these are kind of negotiated outcomes. We are very close on them. We thought we were there once before too. Nevertheless, I'm optimistic we will get something sorted out in the 4th quarter on that.

Thank you.

I will jump in for a moment. Following up on your question from Mark about gas price realizations on Trinidad. I can confirm the 299 is in fact the top line revenue for gas in Trinidad. That is a correct number. Over to you, operator.

As a reminder to register press 14 on your telephone. It seems there no further questions at this time. I will turn the call back to you to conclude or continue presentation.

Thank you, operator and thanks again to one and all for joining us on this busy day. Don't hesitate to contact us after the call if you have any further follow-up questions. Thank you very much and have a good afternoon.

Ladies and gentlemen, this concludes this call for today. Thank you for your cooperation.