Suncor Energy Inc (SU) 2008 Q1 法說會逐字稿

Welcome to Petro-Canada's first quarter 2008 earnings conference call.

I would now like to turn the meeting over to Mr.

Ken Hall, Senior Director of Investor Relations.

Please go ahead, Mr.

Hall.

Good morning, everyone, and thanks for joining us.

On the call this morning, our President and Chief Executive Officer Ron Brenneman and our Chief Financial Officer, Harry Roberts.

Please note today's comments contain forward-looking information, so actual results may differ materially from expected results because of various risk factors.

These factors are described in our quarterly release and our annual filings which are available on SEDAR, EDGAR, and our own website.

As in prior quarters, the format for our call will be that Ron will provide his perspectives and then we will open up the lines for questions.

First the analysts, and then to the media.

With that, I will turn it over to you, Ron.

Thanks, Ken and good morning.

We are off to a good start for the year with excellent first quarter earnings.

Operations were strong across-the-board and record crude prices along with strengthening natural gas prices, more than offset weaker refinery margins.

This quarter's results demonstrate a gain.

Our diversity pays off in delivering consistently strong financials.

Reliability at our major operator facilities was a big contributor to those financial results.

In oil sands, MacKay River operated at 94% and ran more than 23,000 barrels a day despite the extremely cold weather that we had in January.

With bitumen prices over $52 a barrel on the first quarter, new production records now being set, MacKay River is beginning to deliver the kind of financial performance that we expect.

On the East Coast, turnover reliability continues to improve and came in at 87%.

The water injection swivel, which you'll recall was prepared 18 months ago, is still somewhat of an exposure for us.

As a contingency measure to support ongoing reliability, we are fabricating a spare swivel, and we are assessing the capacity of on shore yard support services to install it in the event that performance deteriorates.

Currently, however, the swivel continues to function well.

Downstream reliability was excellent.

Our Montreal and Edmonton refineries and the lubricants plant had a combined reliability index of 99.

Montreal is still in a lockout situation but continues to operate safely and efficiently with our management work force running the facility.

Both of our refineries set throughput records in the quarter.

The downstream business environment was not as strong if the first quarter as it was last year, particularly refining margins.

North American demand for refined product has been softening, although not so much in Canada as in the United States.

Light heavy spreads however, remain very strong.

Light heavy spreads are the key economic driver for our Edmonton refinery conversion project, and the possible coker at Montreal.

So those projects are looking very good for us.

Our marketing business continued its strong contribution on the quarter, retail gasoline margins were solid and sales were up 1% over last year.

Convenience store sales were up more than 6% with same store sales up 4%.

Having a diversified portfolio also gives us a breadth of opportunity.

Our seven growth projects, two in the downstream and five in the upstream, are all progressing well.

Our Edmonton RCP project was 79% complete at the end of the first quarter and we remain on track for a fourth quarter start up.

We are planning a 60 day turn around starting in August to tie in the RCP project and to undertake maintenance on other units at the refinery.

Although this isn't a complete shut down, it will reduce through put for the duration of the turn around.

We have done as much as it can to mitigate the overall margin impact of the shut down through supply exchanges and by importing product into the Vancouver market.

That should allow us to maintain the refining margin on nearly 30% of our northern western Canada sales volume while retaining the marketing margin on 100%.

Once the turn around is complete and RCP starts up, we expect to see an incremental cash contribution of more than $300 million a year from this new project.

A lockout situation at our Montreal refinery is now in its sixth month and is beginning impact the schedule of the coker project there.

Engineering work has continued unhindered, however we are a couple of months behind now on some of the site preparation work.

In essence, we are putting the site work on hold until the labor situation is resolved.

And that will push the start up into sometime in 2010.

For now, our main focus is on completing the Edmonton project and on adding cash flow and earnings from there in 2009.

In Libya, we are just finalizing the detailed terms of the contract extension and conversion for our existing concessions.

We expect final government ratification shortly.

In the meantime, we have been building up our organizational capability to handle the stepped up activity needed to fully exploit the close to 1 billion barrels of contingent resource that we see.

The Syria gas project is also advancing.

We have completed front end engineering design, made our final investment decision, and awarded Petrofac the EPC contract to help build this project.

Petrofac has also agreed to buy a 10% stake in the project which will help ensure complete alignment on our objectives.

First gas is still expected in the third quarter of 2010.

on the East Coast, partners received regulatory approval for the development of the North Amethyst Field, one of three satellites of the White Rose extensions.

With that we have sanctioned the project and it's on its way for start up toward the end of 2009.

In Oil Sands we continue to work on Fort Hills feed and we're making significant progress on our labor strategy.

The team has been working with the Federal and Alberta governments to help us address the worker shortage challenges.

We intend to source from Alberta first, and are planning to fill up from 50% of our needs from across Canada and by temporary foreign workers.

We have secured preliminary approvals under the federal temporary foreign workers program for a good portion of our critical skilled labor needs and we are insisting that each EPC contractor have a specific plan to tap foreign sources of labor.

On the regulatory front we expect approval of an amended mine plan in the third quarter.

The hearing on the Sturgeon upgraders is scheduled for late June, early July, which means we won't know regulatory conditions on the upgrader until the full.

This will push our final investment decision into Q4 instead of Q3.

This is a major decision for us, so we want to make sure we have all the information that we need.

With all the up problem work we are doing ,we still expect to stay on schedule with the mine starting up in late 2011, and the upgrader in 2012.

We also took another step forward on the MacKay River expansion project with regulatory approval granted in the first quarter.

We continue to look at ways to optimize this project and evaluate opportunities for integration with Fort Hills.

That work is going well.

You'll recall from our December CapEx release that we have a substantial exploration program again this year, up to 17 wells.

In the first quarter, we had three well results of some significance.

Our delineation well on the Cassra discovery in Trinidad confirmed the original contingent resource range of about 1 trillion cubic feet that we put out in our release in January.

The second prospect in Trinidad that we drilled, Sancoche, was also completed as a natural gas discovery.

In addition, the first well in our Alaska foothills play, Gubik 3,encountered natural gas and met expectations.

So we continue to enjoy overall success with our exploration program.

I'll now pass the call over to Harry, who will give you an update on our efforts to help you value our downstream business.

Thanks, Ron.

Starting in 2008, and consistent with Canadian GAAP, we moved from LIFO to FIFO method for valuing the company's crude oil and refined product inventory.

We expect the net effect of this change to introduce greater volatility into our downstream net earnings.

To allow for a more consistent view of operations, we are providing a one line adjustment to net earnings to reflect the estimated current cost of supply when calculating operating earnings for the downstream.

Current cost of supply operating earnings are the profits earned, assuming that all volumes sold were based on the current month purchase costs after making allowance for the tax effect.

In Q-1, this adjustment to net earnings to reflect current cost of supply operating earnings was $123 million.

We will continue to provide this adjustment in future quarters, but not for the quarters prior to the beginning of 2008.

Also, in our discussions with investors and analysts, we kept hearing that the downstream business was difficult to model.

So we've done two things.

First, we have expanded our disclosure to include regional detail on crude oil processed as well as regional detail on the gasoline and distillate product sales.

We have also expanded the economic sensitivities table to include additional crack spreads and crude price differentials and we've added realized regional rack and pump prices.

Second we have prepared and issued an information booklet to show how to calculate refining and marketing margins and where to look for additional information.

This booklet can be accessed on our website.

If you have further questions on the booklet, please contact investor relations.

Back to you, Ron.

Petro-Canada had an excellent first quarter thanks to reliable operations, strong production and a robust business environment.

For the remainder of the year, we remain focused on our 2008 priorities: To deliver production within our guidance range through safe, strong and reliable operations, and to advance growth through our seven major projects.

We are off to a great start this year, and we continue to execute these priorities and unlock the long-term value of our quality portfolio of assets.

Over to you, Ken.

Thanks, Ron.

Operator, we'd now be pleased to answer investor questions.

When these are done, we will take questions from the media.

Thank you, sir.

(OPERATOR INSTRUCTIONS).

Our first question is from Andrew Fairbanks from Merrill Lynch.

Please go ahead.

Ron, I was wondering if you could talk about the exploration program the balance of the year where the wells are principally targeting geographically and by play?

We've got, Andrew, we have one other well that we have just spudded in the big block offshore Trinidad.

Benny prospect, we call it.

We have one well the last and I believe fourth well on the shallower water blocks in Trinidad.

We have one well coming up in Norway,Talisman-operated well.

We have a couple in Libya, a couple or three in Libya.

And we have one left in the -- a couple left, I should say, in the UK.

And that about does it.

The second well that we were drilling in the Alaska foothills play we suspended, basically, as planned, I should say, basically because we ran out of weather time up there.

So that's -- and we won't be able to get at that, obviously, until next winter.

So that's about the rest of the program, Andrew.

Fantastic.

Thanks, Ron.

The following question is from Ryan Todd from Deutsche Bank.

Please go ahead.

Good morning, gentlemen.

A couple of questions on I guess first of all, if you give us an update on Buzzard on the impact of the strike of production maybe that you see going forward, and then on a global gas plan going forward, given what's happened with the gas promises over there I know that was a little while back.

Have you thought any more about how you see your global gas portfolio potentially accelerating some of your Arctic gas?

Good morning, Ryan.

Buzzard is actually performing quite well, I think you will have seen from our release that ran in the first quarter a little over 200,000 barrels a day.

So the facility and the field are doing quite well.

We are just coming out of this two-day shut down that we took because of the shut down of the 40s pipeline.

I believe that we are just starting up again today, so that should be a relatively short outage and can easily be accommodated in the production guidance that we've got for the year.

So I don't think that's a big concern to us.

It's one of the pickups that you do encounter periodically.

On the global gas side, we have two possibilities that I would refer to.

One is the one that you touched on, which is our gas in the Arctic islands.

Where we have a small team of people that are now addressing the possibility of development.

There is a number of hurdles that need to be overcome in order for that to become reality.

So it's going to take a little time before we can make a proper assessment of that.

As I tell our people, we can't get there if we don't get started and that's basically where we are.

The other possibility is Trinidad.

I mentioned the success we had in the delineation well on Cassra and the second discovery down there.

So that's shaping up to be a pretty good prospect for you a global gas development, possibly LNG candidate.

So we got those two possibilities that are actually looking pretty good.

Great.

Thanks.

(OPERATOR INSTRUCTIONS) The following question is from Arjun Murti from Goldman Sachs, please go ahead.

Thank you.

Ron obviously oil prices are doing a lot better so far this year than many people had expected or were contemplated at the time.

Companies created their budgets.

How are you thinking about capital spending or incremental free cash flow for the remainder of this year?

How you may prioritize that?

Good morning.

We won't change our capital program because of the short-term oil price outlook.

we pretty much lock into that at the beginning of the year and we stay with it regardless.

Because it is essentially based on more of a long run expectation of prices from an economic point of view.

And also the capability of our organization to execute.

So basically it is a resource consideration internally.

From a free cash or cash flow point of view, of course it does impact our cash flow.

You saw that come if quite strong if the first quarter at $1.8 billion.

Obviously if prices hold up for -- where they are for the remainder we would continue to see some pretty strong cash flow coming out of that.

That would simply reduce the amount of borrowing that we may have to do in the long run in order to finance the projects that we have coming at us in the next two or three years.

I guess Ron the last couple of years you guys have bought back some stock but obviously you have some pretty major capital commitments.

Sounds like you are going to take a more conservative tack and I guess either build up the cash or pay down debt first and we'll see how prices play out, would that be fair?

Well during our release in December, we indicated that our capital program going forward would probably be in the 6 to $7 billion a year range.

I think the number we have this year is 5.3, so it is stepping up a little bit.

With that kind of capital program, and again, depending on what assumptions you make about crude prices, we would expect to be in a borrowing mode in order to finance that.

So that's why we filed the shelf prospectus here in the first quarter that would allow us to go in the market at the right time and essentially put some debt onto the balance sleet and put us in shape for being able to fund those projects going forward.

So with the picture that you should have is that we're in a net borrowing position over the next couple of years to fund these big projects until they come on stream and sort of 2011, 2012 time frame.

That is very helpful.

Thank you very much.

The following question is from Robert Plexman from CIBC World Markets.

Please go ahead.

Good morning, Ron.

There has been some press reports indicating you might be close with the Newfoundland government regarding Hebron reaching an agreement there.

Could you comment on that for us?

While we are talking about Newfoundland, how about South Hibernia, any progress there in discussion with the government?

On both of those, Robert, we do there is kind of a buzzing sound coming.

Can you hear me all right now?

I can't really hear you, Ron.

Let me try again.

We seem to have an interruption there.

That better?

That is a little better, yes.

On both of those projects we do continue to make progress with the Newfoundland government, we are in continuous talks on both Hebron and Hibernia south we are hopeful that in the case of Hebron, we may be only months away from being able to lockdown the fiscal terms and the finalization of the agreement itself which is really what we are trying to do.

On Hibernia south the situation is a little more complex and it may take a little longer.

But again we are in those discussions and we are making pretty good progress.

If I could ask you one more.

This is about the impact of the new federal environmental regulations, you have had a chance to assess the impact on Fort Hill, especially the requirements that requires that you be carbon capture ready by 2018.

What impact that would have on the Fort Hills cost?

Yes unfortunately, Robert, we are still working or trying to dig out some of the details on this from the federal government so that we can better understand what the expectations are.

And parallel to that, though, are looking at the possibility of implementing some measure of carbon capture and storage with the Fort Hills project.

Not coincident with the start up of the first phase, but perhaps somewhere between the first phase and the second phase and maybe coincident with the second phase at a certain level it appears to be feasible.

There is a big question about how these projects get funded, whether there is some cash or funding that comes out of the tech fund that's building up here in Alberta, for example.

Quite a number of unknowns associated with it.

We are sort of addressing that issue and trying to sort out what can be done.

Thanks, Ron.

Thank you.

The following question is from Brian Dutton with Credit Suisse.

Please go ahead.

Good morning, Ron.

I was wondering if you could give us some additional color on the downstream business.

It looks like your rag forward or the marketing side of the business has been consistently generating 40 to $50 million a quarter for you.

Do you see that trend continuing?

It seems to be holding up there, Brian.

I think if you look back historically, the benchmark in my mind that I always had for that business was about $30 million a quarter.

We seem to be doing a little better than that these days.

Some of that strength comes out of the rack forward part of the business here in western Canada, which is particularly buoyant because of the economic activity here.

But also we are seeing a little more stability in gasoline prices, which you might notice in the greater Toronto area.

So without that up and down volatility, extreme volatility we would have seen I have to go back a little more than a year ago now I guess, we do end up with a little better overall margin result.

So that, I would say that both of those circumstances seem to be holding up reasonably well.

And I would expect that to more or less continue for the remainder of the year.

Thank you.

Thank you.

The following question is from Ross Payne from Wachovia.

Please go ahead.

Can you talk about what your expectations are for the impact of west Canada turnaround, turnover, MacKay and Syncrude et cetera and secondarily, what your expectations are for EBITDA contribution on the Edmonton conversion?

On the last one first, there, Ross, we have indicated in our I.R.

material that the after tax cash flow contribution that we expect from the refinery conversion project, if you just put it into today's margin or light heavy environment is in the order of $350 million a year.

The other questions you are asking, we are coming into a number of turn arounds that I think we highlighted in our release.

But those have all been accommodated.

And our guidance for the r remainder of the year, for the full year.

So what you should expect, barring some unforeseen event is that even after we get through those turn arounds, we'll come in somewhere in our guidance range.

Right.

One final question on the Montreal cocker.

Any update there on your thoughts?

Well I mention in my remarks that we are now running about a couple months behind on our site preparation work because of the lockout situation that we are in there.

And so we have essentially put that site prep work on hold until we get the labor situation resolved.

We are continuing with the engineering, which we can do, obviously, in the engineering houses offsite.

But in essence, we are now looking at a start up, assuming that we go ahead with the project, some time in 2010 as opposed to late 2009, which we would have expected five or six months ago, I guess.

But you are anticipating to move forward with that, correct?

Well, again, we need to get this labor situation resolved.

We are not intending to invest that kind of capital unless we've got a pretty firm foundation on which to build it.

So, and the labor situation is part of that.

So we need to get through this labor situation first and see where we stand.

Can you comment on what some of the primary hurdles are there and expectations on timing of that?

I don't really want to get into that, Ross.

I think we should leave that to the folks at the bargaining table, so for the same reason I can't also speculate on what the timing might be.

Okay.

All right.

Thanks, guys.

The following question is from [Iru Sen from Equinox Partners].

Please go ahead.

Hi, Ron.

A question on permitting for the Fort Hills Project.

I know that because of the engineering, et cetera, it's been delayed a bit.

The question is, would the government at any point enforce you or tell you to put that into production before you are ready?

Because I know that coke pulled away sometime back because they didn't want to put that into production during the government time line.

Well, first of all, we are not delayed.

I'm not sure what you were referring to there in terms of the timetable.

Right now we are in the front end engineering and design phase for the Fort Hills project and we are still on track to see that completed sometime in the third quarter of this year.

So we are not really behind on a schedule point of view.

And I think what you may be referring to is a requirement to have the mine on stream by certain date and the schedule that we have, which we still fully expect to meet, actually meets that requirement.

So I don't see any issue with the permit for the mine.

The mine would come online at what time line?

Or what time now?

Late 2011.

Thank you.

This concludes today's analyst question investor session.

We'll now take questions from the media.

(OPERATOR INSTRUCTIONS).

Our first question is from Scott Haggett with Reuters, go ahead.

Can you detail just what volumes you expect coming out of the Edmonton refinery during the shutdown?

We will, Scott.

We will be supplying our total branded outlet requirement from the refinery from purchases and through some time swap supply arrangements that we have made.

As I indicated in my remarks, when you put all that together, we would expect that the margin on what we are pulling through the refinery would be about 40% of what it might be normally.

But the volume would essentially be maintained through these supply arrangements and purchases.

Thank you.

The following question is from Ian McKinnon from Bloomberg News.

Please go ahead.

Two small questions, on the Coker for the engineering work have you guys got any different price in the estimate of Canadian $1 billion?

No we are still looking at that sort of number, Ian.

Secondly, on the LNG in Artic, you said there were hurdles.

Can you be more specific?

Price or regulatory or something else?

First of all there is no governing fiscal regime for projects in the territories.

There are obviously some environmental assessment work that needs to be done.

There are some design aspects that we need to look at costing.

Essentially you are starting with a green field grass roots project.

And in front of that, you've got the fiscal terms and the regulatory process that you need to work your way through.

So that's what I was referring to.

Okay.

Thank you.

Thank you.

The following question is from Hugh Young Lee from Dow Jones.

Please go ahead.

Good morning.

Just talking about the energy project in previous calls, you said that the potential supply from [Gazprom] was the only anchor supply that you had in Trinidad and other places would only be a top half.

Things have changed in this call saying that it could come from the Arctic, could come from Trinidad.

Is that the because the nature of these projects has changed, or because you're being to forced to look at these more seriously as the Gazprom supply disappeared?

These projects have always been in the works for us over the course of the I guess three some odd years that we were negotiating with Gazprom, these other projects have advanced somewhat.

So this is just a normal course of business for us.

I didn't say, though, that these were necessarily locked into the Kakuna regasification site.

From our point of view, this is gas that could move into other regas terminals or it could move into Kakuna but it's not the same circumstance it that we saw with the gas problem volumes.

Okay.

They are capable of being an anchor supply but you don't know if you are going to be locking them in for Kakuna or other places?

That's right, yes.

Great.

Thank you.

Thank you.

(OPERATOR INSTRUCTIONS) The following question is from Moira Baird from the Telegram.

Please go ahead.

Good morning.

I was wondering if you could narrow down the number of months you are away from locking down the fiscal terms on Hebron?

I really can't.

It takes both sides to make progress and reach an agreement.

I am encouraged we are making progress on the critical issues on both of those projects.

So that's really what we are working on and looking forward to at this point.

I'm guessing the fiscal terms that includes royalty, equity, is there anything else in that fiscal bracket?

You may recall the structure for the Hebron project was actually agreed on in an MOU several months ago.

Sometime in 2007.

So the basic structure of the fiscal terms for Hebron are agreed to.

But there are some other aspects that details that need to get sorted out.

And in the case of Hibernia south, we still need to agree the fiscal terms that would apply.

Given the other two projects, the White Rose extension in Hebron and the province's energy plan, at least there's a framework that exist if we see those fiscal terms fit into.

That is part of the progress that I was mentioning.

You also mentioned that Hibernia south is more complicated than Hebron.

Is that because of the structure of the partners or what would the reason be for that?

Well, first of all there are two or three different licenses involved involved in the Hibernia south extension.

One of those is a production license.

One or two of them are exploration licenses so there are different terms governing.

One of the licenses actually has different ownership than the main Hibernia field.

so those are the kind of complications that need to get sorted out as part of this agreement.

Thank you.

There are no further questions registered at this time.

I'd like to turn the meeting back over to Mr.

Hall.

Thank you, operator.

Any further investor questions can be forwarded to me or my colleague, Lisa McMahon.

Media are welcome to contact Andrea Ranson.

Also, I just want to remind everyone that we will be holding our annual meeting later this morning.

You can listen to the proceedings live on our website start being at 1:00 p.m.

eastern time.

Once again we are glad you could join us and thank you for your interest in Petro-Canada.