Suncor Energy Inc (SU) 2003 Q3 法說會逐字稿

Ladies and gentlemen, thank you for standing by. Welcome to the Petro-Canada third quarter earnings results conference call. (Operator instructions) I would now like to turn the conference over to Mr. Gordon Ritchie, Senior Director of Investor Relations.

Good afternoon, everyone and thank you for joining us on this busy day. With me today are Ron Brenneman, Petro-Canada's CEO, and Harry Roberts, the company's CFO.

During the course of today’s conference call, we will be discussing reserves, and some forward-looking information, so I would refer you to the cautions appearing in our press release and in our annual report MDNA. We will take the standard approach to the call today. Ron will provide his remarks on the quarter, and then before opening up the lines for questions, Harry will explain in greater detail some of the non-operating factors that you’ll need to have in hand for the quarter. Ron.

Thanks, Gord. I’m pleased to report on another solid quarter at Petro-Canada. The financial results pretty much speak for themselves. When the stars align with prices and margins where they are, you have to take advantage of it, and for the most part, we’re doing just that. I am particularly pleased with our strategic progress in the quarter. We took a big step forward in the downstream to improve long-term profitability. We also took a number of smaller steps internationally that advanced the long term plan and capitalized on the opportunities brought forward by our international business unit.

I’ll just take a few minutes to share with you the progress we are making in each core business, beginning this time with the downstream. Reconfiguring our Eastern Canadian supply operations is an important strategic move to improve the long-term profitability of our downstream. There’s more to this than just shutting a refinery. By completely rethinking the rack back business in the East, Petro-Canada will shift from a refining focused operation there with middle-of-the-pack performance to a supply and logistics center function where best in class performance is achievable. The move will close a half to one percent of the remaining gap to our targeted 12 percent mid-cycle return on capital employed.

I’m also glad to report that lubricants is in the process of ramping back up to full production. An upset during start-up after the August black out forced us to shut down about half the plant. Most importantly, we’ve been able to keep all of our customers whole and will soon be delivering on-spec tri-margin product to market. We will continue to work on plant reliability, because there is clearly an opportunity for improvement there.

With the exception of the lubricants incident, the downstream sector had quite an outstanding quarter, $110m before the Oakville charge to operating earnings. We’ve been working on the fundamentals of the business and the results are showing. These quarterly earnings were the downstream’s third highest on record, with strong contributions from both the refining and marketing sides.

Moving onto the upstream, I will start on the international front where we continue to move forward on the strategy I outlined last quarter. First and most importantly, we are successfully leveraging our current portfolio. In the Dutch sector of the North Sea, we saw initial production from the L5-B development just last week, well ahead of schedule. L5-B will add about 12mcfd of natural gas production. We have another discovery called [DeReuter] which could initially add 10,000bpd as early as 2006.

In the U.K. sector, [Clampen] remains on schedule to start up early in 2004, and the [Greeve] development is slated for 2005. So our strategy to extend profitable production in the North Sea is working.

In Venezuela, [Menevesa] has approved an agreement at the [Menseva] project, allowing us to move forward with the evaluation of this 180m barrel discovery in the Lake [Maracivoy] region. The second component of the international strategy is to add new areas of operation. We’re pursuing long-life assets like LNG, Venezuela heavies, and low cost Middle East oil. In Kuwait we’ve taken a 10 percent working interest in one of three consortiums that will bid on the redevelopment of the country’s northern oil fields.

The third element of the strategy is to develop a balanced exploration program. In this quarter we acquired a majority interest in the 845,000 acre [Melita] block in Tunisia. We plan to undertake an $18m exploration program there, shooting seismic and drilling two wells. As I mentioned earlier this month, we’re in discussions in both Syria and Libya for exploration opportunities there. So we’re heading in the right direction. I’m pleased with the capability of our international team as they continue to build on that critical platform.

Coming back to Canada, the East Coast oil business continues to delivery exceptional profitability. In August we successfully completed Terra Nova’s planned maintenance shutdown. The FTSO is back up and running, averaging 140,000 bpd in October. Strategically, our thrust is to extend Terra Nova’s plateau period with the development in the far east block. We drilled a third delineation well in the quarter and this winter we will put the well data together with some seismic we’re reprocessing. By spring, we’ll have a more complete picture of the potential there.

Hibernia continues to be a real success story. Production has averaged over 200,000 bpd this year, well ahead of the original estimated production rate of 135,000 bpd when the project was conceived. Reservoir performance is exceeding expectations with the rate of increase in gas/oil ratio and water/oil ratio lower than expected. The platform is operating at Q1 reliability and cost levels.

The White Rose project is progressing well, and step out drilling in the quarter provides some upside potential for the reserves estimate for the field. So we continue to see East Coast oil as an excellent business going forward.

In oil sands, the strategy work we’ve been doing confirms that integration makes sense, although the value chain is tight all the way through. So we are targeting a solution that will better utilize our existing asset. We expect to be able to share some of the results of this work by year end.

At McKay River, our understanding of how to operate the facility is growing. We took advantage of the shutdown in July to address the plant’s reliability by investing $10m in additional equipment. We’ve also strengthened the operating team and revamped procedures. Production is now steadily rising, albeit more slowly than originally expected, but we are learning as we go.

We now have good water handling procedures in place and as I’ve said before, the reservoir continues to perform very well. We should see better production at McKay, although starting up the co-gen unit in the next few months will add its own challenges.

Reliability will continue to be a critical focus here in the coming months. Syncrude had a strong quarter, averaging over 240,000 bpd, although news of the coker shutdown a few weeks ago was disappointing. Last quarter’s guidance of 26,000 bpd net to Petro-Canada for the year remains achievable, but I’d have to say it now has some stretch in it.

Turning to North America gas, we are very pleased with the ongoing excellent performance in this business. Western Canada is just where we want it to be, consistently delivering on the strategy. Refining and development costs have been industry leading, and the business unit is delivering 30 percent of the corporation’s cash flow this year.

Our Western Canada team continues to successfully find deep gas pools in complex formations in the foothills region. Our natural gas marketing team is also delivering first quartile performance, beating the median price of our peer group by 58 cents an mcf in the first half of the year. That represents $73m in additional sales, another example of how we focus on all controllable aspects of this business.

In the Mackenzie Delta, we’re well positioned to take advantage of future pipeline development. We’ve drilled four exploration wells to-date, and we have one discovery. We’ve secured our most prospective acreage for future exploration, and we’ve nominated initial volumes into the proposed pipeline. The disciplined thing to do now is to take a breather and wait for pipeline developments to catch up. So we won’t be active there this winter and we will reevaluate our program next year as events unfold. All told, we’re in great shape in the natural gas business, delivering exceptional profitability today from Western Canada and positioned for longer term opportunities.

Overall it was a good quarter. We advanced our international strategy and we are making good progress on our steps to improve the fundamental profitability of our base business. But reliability is still an issue, particularly in the downstream and in oil sands. So that will continue to be an important area of focus for us. We’ll also continue with our disciplined approach to capital investment. I see these as two of the keys to creating long-term shareholder value at Petro-Canada. Thanks for your attention, and I will pass the microphone over to Harry.

Thanks, Ron. Good afternoon, everyone. I would like to take a few minutes to go over a number of the non-operating items that affected results in the quarter. On the earnings side, the busy quarter generated a couple of one-time impacts, both on the negative side and on the positive.

First in the downstream, the reconfiguration of our Eastern Canada supply operations lowered operating earnings by $136m after tax and a $16m after tax loss on disposals of assets reflected the ongoing rationalization of our Eastern Canada marketing network.

Second, in international, earnings from operations benefited from $45m in one-time positive adjustments. These are related to clarification of production rights and to a tax provision associated with the former operation. Adjusting for these two impacts, earnings from operations were $402m, or $1.52 per share.

On the cash flow side, tax deferrals resulting from our upstream partnership increased cash flow by approximately $5m in the quarter, compared to a decrease of $10m in the third quarter of 2002. A FIFO effect in the downstream raised cash flow by about $7m, compared to a reduction of $35m a year ago.

I’d also like to comment on the status of our pension plan. We filed an updated pension valuation with the regulators, and as a result we are increasing our 2003 cash contributions from our original estimate of $30m, which I shared with you in January, to about $75m for the year. As we mentioned in our quarterly report, there will be no impact on the pension expense for the year 2003.

In summary, we are in excellent shape financially. We’ve fulfilled our commitment to restore the balance sheet. We’ve repaid about $1b of the $2.1b of debt that we took on for the international acquisition, and we’ve restored our financial ratios to what they were prior to the acquisition. So we now have the financial capacity to continue to fund growth and also to take on new opportunities. Back to you, Gord.

Thank you, Harry. And operator, that now completes our presentation and we are ready to open up the phone lines to answer any questions.

Thank you. (Operator instructions) Our first question comes from the line of Andrew Fairbanks of Merrill Lynch.

Good afternoon, guys. I wondered if you could give us some schedule to look for in terms of announcements on the international side. There’s a lot going on there as we look out into 2004, there are some key dates or decision points that we should be aware of in Kuwait or Tunisian drilling, the Roffer is still out there, any thoughts on that? Or other sort of major strategic moves in one direction or another or one region or another for next year?

Hi, Andrew. The kind of things you are talking about are pretty hard to predict in advance. Our approach to this will be to basically make these announcements as they unfold. For example, you mentioned Tunisia. We need to shoot some seismic there, for example, before we do any drilling, so it will be some time before we see any results from that program.

I think you raised the question of the Roffer in Venezuela. The situation there is that we some time ago made a proposal jointly with -- we, by that I mean BP, because they are the owner of the asset still at this stage -- but BP made a proposal jointly with Exxon to [Pedavesa] for an alternate approach to resolving the right of first refusal and still haven’t heard back from [Pedavesa]. So that is still an item that we really can’t be very certain about in terms of timing.

I’m not sure what else you mentioned there.

Just Kuwait or Trinidad, future bidding grounds, or anything else that is really of substance.

Again, it’s pretty hard to predict the timing of those. I think we will be very timely in getting that information out to you as soon as we have something to announce, but it’s pretty tough to predict in advance.

Fair enough. Just one other, if I could. If you look out at the overall project planning process for the year and look at reconfiguring the oil sands development, what exchange rate are you guys using in your internal assumptions at this point, Canadian dollar, U.S. dollar?

I think the official number we’re using for calculations is 70 cents, but I wouldn’t attach too much meaning to that. That’s not a forecast of any kind, its probably a residual from where we were some time ago. This thing has moved pretty quickly and we don’t tend to adjust this on a very current basis.

Sounds good. Thanks.

Our next question comes from Martin Lanoveau; First Energy Capital Corp.

Good afternoon, gentlemen. I guess what we’re looking at, you spent $652m in Q3, that takes the annual capital expenditures up to $1.67b over nine months to reach your kind of official 2003 capex, Q4 has got to be a pretty substantial number. Any thoughts on what we should be looking at with Q4, if you took the published numbers and netted them together, what you’d think?

Hi, Martin. Does the number that we put out -- in fact, we just had a look with our nine plus three information, or where we thought we might come out for the year, and it looks like we are going to come in a little more than $100m under the number that we put out after our six plus six which, Harry, would have been with our July results?

With July results, that’s right.

So you are quite correct in pointing that out. There’s a number of puts and takes there. With the change in strategy in the oil sands, we are considerably under what we would have put in the window for the oil sands. We have successfully made some acquisitions in the international area, particularly in the North Seas, so those expenditures are up, and we are up a little bit in the Western Canada basin, again because these are modest acquisitions like $25m, $30m but there is one of those that we are looking at as well.

So a few puts and takes, but it looks like we will under spend that number that you would have last seen.

And one final question. We heard from Suncor this morning and the other integrateds that refine and marketing margins are looking fairly decent right now. What is Borris and his team thinking going into this winter, here?

Well they seem to be holding up reasonably well. On the other hand I would say that much of the strength that we’ve seen coming through the summer months here has been because of relatively low inventories, and some of that was acerbated, for example, by the black out for three or four days. I guess it was probably close to a week by the time the refineries got back up and running there in August.

What we are seeing in the marketplace is inventories starting to come more into line, so I am not sure that we can look forward to the same sort of margins that we’ve been seeing recently, but again we are coming into the winter season, a lot of that depends on cold weather and heating oil demand. Again, one of those things that is pretty tough to predict, in my view.

Okay, thank you.

Our next question comes from Greg Pardy; Scotia Capital.

Hi, Ron. Two questions. Just on Alaska, how much gas have you actually nominated for the pipeline.

Hi Greg, actually you are talking about the Mackenzie Delta as opposed to Alaska, and out of that we have nominated, my recollection is 30m a day. I’d have to check and see whether that is joint with Devon or whether that is our share. I believe that that’s joint with Devon, but maybe Gord could get back to you on that, just to confirm that.

You touched on the LNG, can you give us a little more color there as to what you are thinking, long-term analogy?

Well LNG, first of all our interest in LNG is primarily in what I would call the Atlantic Basin, which would be supply aimed principally at the North America gas market, although it could alternatively in some cases end up in Europe.

The reason for that is that we know something about the North America gas market. We market upwards of 700mcfd today, and much of that goes into the US gas market, so we understand the distribution system, we understand the players, the pricing mechanism and that sort of thing. So we feel that we can bring something to the table there.

If you go to the other end, we have a small toehold I would say today with our position in Trinidad. We’d like to build on that. There is, I think I’ve mentioned this before, there is an exploration round coming up in Trinidad which we are quite interested in which will allow us to expand our presence there.

In between, we are also looking at whether it makes sense for us to participate in a regasification facility which, if we marry that up with our knowledge of the market we think may provide some opportunity openings if you like for accessing some of the upstream supply pieces of it.

So it’s one of these situations where we understand where we want to get to. We want to basically be a player in the whole value stream from upstream through to marketing, but in order to put the pieces together it may not be quite as orderly as you might like because you have to be opportunistic about what might be available and move when you have the chance. So that’s our thinking, basically Greg, on that one.

Okay, last one for me. Are we going to get oil sands clarification before Christmas, or is this something next year?

I’m hoping it will be before Christmas.

Thank you.

Our next question comes from Tom Evern; Tri Stone Capital.

Good afternoon. I wonder if you could give us some thought on your current tax situation going forward. With the partnership deferral in place, it seems that the majority of the revenues this year are going to be payable in cash taxes, operating income payable in cash taxes next year. Can you give us some guidance on what you might expect for that?

Harry, have you got some thoughts on that?

That’s actually very difficult to answer. The partnership, as you know, does move the tax from one year to the next, and the impact of that is really relevant depending on how the income you earn the subsequent year is relative to the tax you are paying on the prior year. But if we sort of step up to the higher level and you look at our tax rates going forward, the international will remain in that 60 percent to 65 percent range and clearly on the federal basis we will see some change there as the -- I’m supposing here that the new tax act will be passed. I mean, once that starts to click in, we’ll see Canadian operations see the benefit of that.

It’s hard to say right now on the provincial side what’s going to happen. I mean, certainly with Ontario talking about changing some of the proposed changes they were making, we could see some smaller changes there, but the combined federal/provincial rates for the company will move from the current about 40 percent we are seeing now, it could come down by a percentage point or two over 2004.

But it’s really hard to say with any sort of certainty exactly what the impact of the partnership -- the payable that we’re currently showing within 12 months that you will see on the balance sheet is about $160m.

Okay, that’s been accrued then for cash taxes in 2004?

That’s correct.

Great, thank you.

Our next question comes from Brian Dunton; UBS.

Good afternoon. I’ve got two questions, and both are on the downstream. First is for Edmonton, you outlined the plans earlier in the quarter for Eastern Canada operations regarding the desulphurization. Where do things stand at this point for Edmonton, and what do you think the costs might be to achieve the standards required?

Still a little up in the air, Brian. The situation there is linked to some extent to what we would intend to do longer term in terms of adding some upgrading capacity. I think I’ve mentioned before, for example we are looking at expanding our coker. If we did that, we would be producing coker product which in term would require some hydro treating which in turn require a hydrogen plant and a sulfur plant, so the expenditure that we make to remove sulfur in distillate, which is the piece that is still up in the air a bit, depends on what we choose to do in the longer run on the upgrading side.

I see. And second question is on the marketing side of the downstream. Strong results again going from the second to third quarter. What is the picture like at this point on the non-petroleum product sales? Are you still seeing the same kind of year-over-year growth that you’ve been previously experiencing?

Well this year, I think I mentioned some numbers this year that are down a little from where they were last year, but still pretty substantial. Our year-over-year non-petroleum sales, this is mainly C-star income, is up 17 percent, and if you look at same-store sales its running in the 9 percent to 10 percent range. So it’s still pretty strong growth year over year and as I’ve said before, a big driver toward the profitability of our downstream.

That program, as I have indicated previously, so far is about 70 percent complete and we still have a ways to go. We’ll be spending -- I am guessing now, we haven’t finalized our budget for next year -- but I am guessing we will spend around about the same amount of money next year on our site conversion program.

Great, thank you.

Our next question comes from Paul Cheng; Lehman Brothers.

Hi guys. Several quick questions. The first one, one thing, Harry, if you could give us an estimated cost of the black out to your system. Secondly, maybe this is for Ron, if I am looking at your third quarter results and trying to analyze it and doing some math, it looked like the international EMP operation, when they need $20, $22 WTI price kind of range, in order to achieve a breakeven, I just don’t know if my calculation is too high, too low, and if you can make some comment. Because $20, $22 looked like it is a pretty high price net or required for breakeven. Maybe I did something wrong here.

Third, when we are looking at -- I know it is early, but can you give us an idea of what is the different approach that you are contemplating now versus previously that leads you to believe the oil sands integrate project remains a good, economic project from say the past several months ago?

Then finally, I am wondering if Gordon can give us a fully diluted share count?

Let’s start with the easy one first, Paul. I’ll ask Gord to give you the fully diluted share count number.

Thank you.

While he’s looking that up --

I’ve got it here. It is 267.7m shares.

Thank you. Just the U.S. based analysts, we always love that.

Okay.

Paul, I am going to go back to your second question about breakeven oil prices for the international business. I am not sure I can help you, because I don’t see your calculations there, but what I would suggest you do is go to the tables that we’ve provided, I think, Gord, they are in our year-end supplement?

Statistical supplement.

Statistical supplement, where we show you for different oil prices we show you the net backs for the different parts of the international business unit. That might be a better reference than trying to work with the third quarter results.

I can tell you that one of the things we’ve been doing in the international business unit, because there’s been some one-of puts and takes and some foreign exchange effects and some inventory effects from month to month in particular. We tend to follow that internally on what we call a normalized basis and I can assure you that the results that we are getting are very much in line with what we would have expected at today’s prices. So there shouldn’t be anything anomalous in there from our perspective.

With that in mind, Ron, can you share with us then what you think is the breakeven point for that business?

I don’t have that number Paul, but I’d suggest you go to those net back tables that I mentioned and you might be able to work that out.

We’ve got, you may remember, we’ve got in our statistical supplement what we’ve called a sensitivity table that show net backs at $16 WTI, $21 WTI and $26 WTI so it gives you some sense of how the profitability of each of those regions will be at those different price levels. I think I’d be happy to, if that’s a good place to start, maybe we can follow up there.

My recollection Paul is that at $16 I don’t recall seeing any negative numbers in those tables, so there must be something that needs fixing there.

Your other question about the oil sands being economic, the point that I was trying to make there is that where we might have seen a value change, before the big cost overruns, that might have been in the mid-teen kind of range, and I am talking about now starting from bichum in the ground to be able to get to a finished product value, which was the concept of our integrated scheme there.

With the kind of cost overruns that we’ve seen, which we think are realistic expectations, I mean that’s what you need to count on going forward, that mid-teens has shrunk to become very close to cost of capital. Even to get cost of capital returns, you have to have a lot of things going for you. By that I mean you have to have starting right on the front end you’ve got to have good quality reservoir and a location that is logistically accessible so that you are not paying the large transportation costs to move it around. Then, as you start to move downstream from that, you need to have selected the right technology and again be able to put that into the right location, preferably within infrastructure that already exists so that you are not dealing with a green site.

So my only point is that there are still economics there, but its extremely tight and rather than being able to expect mid-teen returns you need to be looking more at cost of capital returns. Even to get there you need to have a lot of things going for you.

Paul, I know you asked about the cost of the black out to the system, well we don’t have that number. I guess the most obvious upset we had was the [Delups] plant and what I can tell you there is that the impact to Q3 was small. We are happy to say at this point that we are back up and running. As Ron mentioned in his remarks, we should be in a position shortly to be moving the on-spec, high margin product back into the markets.

If I could have just a quick follow up question. Ron, [Pan Mexnada] you start to selecting people to be on their natural gas board in Mexico. Is that a country or an area that you guys would be interested?

We went down and had a look at that Paul, and concluded that we weren’t particularly interested. The terms are pretty tight, from our perspective. And when we looked at that combined with the geology, it just didn’t stack up with opportunities that we see elsewhere internationally, so we passed on it.

Thank you.

Our next question comes from Leslie LaFave of Ontario Teachers Pension Plan.

Just a quick question on the pension fund contribution. I think it was $75m, you said? Is that an after-tax figure?

That’s a cash figure. The implication of that, of course, is next year that will be one of the factors that we will be using to calculate the pension expense for 2004. There are a whole bunch of puts and takes that go into that calculation. The $75m right now is a cash contribution.

So the contribution is non-tax deductible.

The expense is tax deductible.

No change to the expense, you said.

When it comes into the expense, that’s right.

And after that contribution, what level of funding will the plan be at?

I think you could look next year for about the same level. We filed this year, and I think as you know, on a regulatory basis you must file every three years. Having now filed at least for next year, we will be in a position where that is where the contribution will be for next year as well.

Okay. And sorry if I am asking you to repeat something you may have already talked about, because I missed the first few minutes, but is there any indication yet on capex budget for 2004?

Leslie, we normally put that out in early December after we’ve gone through our business plan. November is the month we go through our business plan, and at the end of November we review that with our board. Following that we put out a press release on our capex.

Thank you.

Our next question comes from Allan Steppa; Sawman Partners.

Yes, based on the first nine months of 2003, do you have any preliminary estimates of where you think F&D costs for 2003 are going to shake out, both for Canada and international? And failing that, maybe potentially what the percent reserve replacement for 2003, Canada and international will be?

Allan, F&D costs for this year are going to be up over what they were last year. Last year we were in the $1.55 range, I believe. I think this year we are probably, and of course there is still a couple of months of drilling left, so we don’t have anywhere close to a definitive number, but we are clearly going to be above that $1.55 number. I think I may have indicated previously that we were budgeting about $1.65 this year, and I think we are going to come in above that even.

That’s Canada, international, a total number?

No, that’s only Western Canada and we haven’t actually tried to track an international number because our exploration program is still pretty sparse, so it’s not very meaningful.

Noticing you have on cash, short-term investments of $588m. I know in Toronto you talked about maybe the potential for dividend increases, any further insights that you can provide us regarding that?

In Toronto what I indicated that as part of our annual business plan we do look at our dividend level and it’s competitiveness. That’s exactly what we’ll be doing again this November. So we basically held, you may have noticed that we held our dividend constant at 10 cents this quarter and we will be looking at it between now and the next quarter.

Fair enough, thank you.

Our next question comes from Robert Plexman, CIBC World Markets.

Hello, Ron. I have two questions regarding the international part of the business. First of all, as far as the [LaFava] development goes, you mentioned that [Petavesa] has given approval. So can you give us a little bit more data on that? You mentioned the reserve potential there, but in terms of timing, as far as the production rates as well? And, whether you could see that oil getting as far as the refinery in Montreal, if you even want to do that.

Happy to do that, Robert. You’re a little ahead of us, actually. The approval that we got from [Petavesa] is for a longer term production test. One of the uncertainties in this reservoir is the longer term producibility of the wells. So what we want to do is take one or two of the wells that have been drilled and connect them up so that we can actually produce them over an extended period of time, and determine from that what we think the overall development scheme might look like, or should look like.

So we need to get through that step before we can say too much about overall production levels and where the crude might end up.

So do you think you would be able to make that decision in 2004 then?

I would think toward the end of 2004 we should have some information on that.

If I can ask you another short one on the international side, just as far as how the reserves are holding up. You know, you’ve had these assets now for I guess it’s over a year. Decline rates, any surprises there? I am thinking more about Syria and declining production than I am about Libya or the U.K. right now.

We are certainly seeing some decline in Syria and this wasn’t a surprise to us. This is fairly mature production and the program that we and our partners have had in place there for some time, and I am talking even pre-acquisition days, has been to try to sustain that in the 300,000 bpd range gross, of which we are about one-third. We’ve just this year started to fall a little below that, and I think that is the pattern that I would expect to see there as we go into the future. But again, it’s the sort of thing that we will be looking at in our business plan this year and try to get a better handle on.

Okay, and if I could ask you one last one about reserves, off shore of the East Coast with a third well into the far east block at Terra Nova and with the positive news out of White Rose and the high productivity at Hibernia, should we expect to see some reserve adds from the East Coast this year?

Well we did, of course, on Hibernia I think it was early this year we did mark up the proved and probable there from 730 to 835, which was mostly reflecting better recovery in the Avalon formation. There is still a lot of moving parts out there. We’ve got two rigs drilling on Hibernia, we still have the one rig on Terra Nova, so a lot of information yet to come in on both of those fields that will see those numbers move around. We tend to not want to do that more often than we actually have something significant to make a change on, Robert, so when we get something significant, you’ll be the first to know.

Thanks, Ron.

Our next question comes from Terry Peters; CanAccord Capital.

Thank you. I’d like to talk a little bit more, you mentioned that Libya was one area you were in discussions with on exploration opportunities, and I am just wondering, do you feel you are at a competitive advantage given your production there, and also, would you look for a partner? Now that the UN sanctions are off I don’t know what the status is of the U.S. position, it’s probably not resolved but could be resolved. Are you at an advantage in your position and would you take on a partner or would you do something at a higher percent?

Well, the advantage we have is that we are there and relationships in that part of the world are quite important, so I would say yes, relative to those that aren’t there, we have a clear advantage.

As far as partners go, we are not particularly driven. These are production sharing contracts that are quite manageable because of that from an upfront capital point of view, particularly at the exploration stage. So it’s not particularly part of our strategy.

I guess the other thing is, it’s not clear when the American companies, if you were thinking of American companies, might be invited back into Libya, or allowed back into Libya. It’s true that -- the UN sanctions were actually lifted back in the late 1990’s and have been officially confirmed since. The U.S. sanctions still exist, even though the conditions that were associated with them, that all had to do with reparations for the Lockerby incident, have basically been satisfied, the sanctions themselves have not been lifted. So its unclear when that might happen, every once in a while we read that it is imminent, but so far they are hanging in there.

Would you be clear to proceed with a new contract, and is Libya actively looking to expand the exploration side of its business?

Well, we are talking to them about some specific concessions. They are not the only concessions in Libya. So if others were to come into the country, there are other concessions that could be made available, I’m sure. It’s not as though we have an exclusive for the whole country here, it’s just that we are in some discussions on particular concessions.

Thanks very much, Ron.

(Operator instructions) Mr. Ritchie, I see no questions at this time, I will turn the call back to you.

Thank you, operator. Once again, everyone, thank you for joining us on what is a very busy day for all of you. We appreciate your time and interest. As always, Derek, Dillion and myself are available for any follow up questions this afternoon or tomorrow. Thanks very much, and have a nice day.

Ladies and gentlemen, that concludes our conference call for today. We thank you very much for joining and ask that you please disconnect your line.