赫斯 (HES) 2010 Q3 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the third-quarter 2010 Hess Corporation earnings conference call. My name is Noelia, and I will be your coordinator for today. At this time, all participants are in a listen-only mode. We will be facilitating a question-and-answer session towards the end of this conference. (Operator Instructions). As a reminder, this conference is being recorded for replay purposes.

I would now like to turn the presentation over to your host for today's call, Mr. Jay Wilson, Vice President, Investor Relations. Please proceed.

Good morning, everyone, and thank you for participating in our third-quarter earnings conference call. Our earnings release was issued this morning and appears on our website, www.hess.com.

Today's conference call contains projections and other forward-looking statements within the meaning of the federal securities laws. These statements are subject to known and unknown risks and uncertainties that may cause actual results to differ from those expressed or implied in such statements.

With me today are John Hess, Chairman of the Board and Chief Executive Officer; Greg Hill, President Worldwide Exploration and Production; and John Rielly, Senior Vice President and Chief Financial Officer. I will now turn the call over to John Hess.

Thank you, Jay, and welcome to our third-quarter conference call. I will make a few brief comments, after which John Rielly will review our financial results.

Net income for the third quarter of 2010 was $1.154 billion versus $341 million a year ago. Our third-quarter operating results were positively impacted by higher crude oil and natural gas selling prices and sales volumes compared to the year ago quarter.

This quarters' results also included an after-tax gain of $1.072 billion associated with our strategic asset trade with Shell, which closed in September, as well as an after-tax charge of $347 million to write off the West Med Block 1 concession offshore Egypt. Excluding these nonrecurring items, Exploration and Production earned $552 million.

Crude oil and natural gas production averaged 413,000 barrels of oil equivalent per day, which was 2% below the year ago period. Lower year-over-year production resulted primarily from natural field declines at the Ceiba Field in Equatorial Guinea, and planned down time at the Valhall Field in Norway, which was partially offset by higher production from our Bakken program in North Dakota.

Current net production from the Bakken is approximately 18,000 barrels of oil equivalent per day with nine rigs working. We plan to add one additional rig in November and expect to exit this year with net production of about 20,000 barrels of oil equivalent per day.

Our acquisition of American Oil & Gas is progressing through the regulatory process and is expected to close by the end of the year.

In September, we closed on both the strategic asset trade with Shell and the acquisition of Total's interest in the Valhall and the Hod fields in Norway, which together raised our interest in these fields to 64.5% and 62.5% respectively.

Also in September, we announced the acquisition of an additional 20% interest in the Tubular Bells oil and gas field in the Gulf of Mexico from BP for $40 million. Following regulatory approval, Hess will have a 40% working interest and become the operator.

In the United Kingdom, the sale of non-core North Sea natural gas assets is now expected to close in the fourth quarter. These assets have net production of 16,000 barrels of oil equivalent per day and year-end 2009 proved reserves of 29 million barrels of oil equivalent.

With regard to exploration, we drilled two wells on our 100% owned permit WA-390-P in the Northwest shelf of Australia, resulting in two discoveries. We have now completed our 16 commitment wells on the block with 13 discoveries. We have initiated an appraisal program that will continue through the middle of next year and include additional drilling and flow testing of several wells. Commercial discussions with potential partners regarding WA-390-P are ongoing.

In December, we expect to spud exploration wells on our 40% owned BMS-22 Block in Brazil, our 100% owned Tano/Cape Three Points Block in Ghana, and our 80% owned North Red Sea Block 1 concession in Egypt.

In the first quarter of 2011, we plan to drill our 100% owned Semai 5 Block in Indonesia. In terms of unconventional resources, we plan to start drilling in the Eagle Ford in Texas in November and in the Paris Basin in France in the first quarter of 2011.

Turning to Marketing and Refining, we reported a loss for the third quarter of $38 million. Refining margins weakened from last year's third quarter primarily due to lower gasoline and residual fuel oil crack spreads and higher fuel costs at our HOVENSA joint venture refinery and lower gasoline crack spreads at our Port Reading, New Jersey facility.

Marketing results were better than the year ago quarter principally due to improved margins in our energy marketing business. Retail gasoline volumes on a per site basis were up 1% while convenience store sales rose nearly 3%. In energy marketing, natural gas sales were higher year-over-year while fuel oil and electricity sales were lower.

In conclusion, we are pleased with the recent transactions that we believe strengthen our global portfolio and will contribute to our Company's future reserve and production growth.

I will now turn the call over to John Rielly.

Thanks, John. Hello, everyone. In my remarks today, I will compare third-quarter 2010 results to the second quarter.

The Corporation generated consolidated net income of $1.154 billion in the third quarter of 2010, including after-tax income of $725 million from items affecting comparability of earnings between periods compared with $375 million in the second quarter.

Turning to Exploration and Production, Exploration and Production operations had income of $1.277 billion in the third quarter of 2010 compared with $488 million in the second quarter. The third-quarter results included an after-tax gain of $1.072 billion relating to the exchange of the Corporation's interest in Gabon and the Clair Field in the United Kingdom for additional interest in the Valhall and Hod Fields in Norway.

The results also included an after-tax charge totaling $347 million to write off our investments in the West Med Block located offshore Egypt. The impairment resulted from the third-quarter decision by Hess and the other concession partners to cease future exploration activities and to relinquish a significant portion of the block. Excluding the effect of these matters, the changes in the after-tax components of the results are as follows.

Higher sales volumes increase earnings by $127 million. Increased production expenses reduced earnings by $25 million. Increased exploration expenses reduced earnings by $16 million. Increased depreciation reduced earnings by $13 million. Lower selling prices decreased earnings by $6 million. All other items net to a decrease in earnings of $3 million for an overall increase in third-quarter adjusted earnings of $64 million.

The previously mentioned exchange of the Corporation's interest in Gabon and the Clair Field increased our interest in the Valhall Field by 28.1% and the Hod Field by 25%. This was accounted for at fair value and resulted in a gain in the quarter.

In September 2010, the Corporation also completed the acquisition of a 7.85% interest in Valhall and a 12.5 interest in Hod for cash of $507 million. After the completion of these acquisitions, the Corporation has total interest of 64.05% in the Valhall Field and 62.5% in the Hod Field.

In the third quarter of 2010, our E&P operations were over lifted compared with production, resulting in increased after-tax income in the quarter of approximately $60 million. The E&P effective income tax rate was 44% in the quarter and year to date in 2010.

Turning to Marketing and Refining, Marketing and Refining operations generated losses of $38 million in the third quarter of 2010 compared with $19 million in the second quarter. Refining operations had losses of $50 million in the third quarter and $31 million in the previous quarter. The Corporation share of HOVENSA's results after income taxes was a loss of $52 million in the third quarter compared with $4 million in the second quarter, reflecting lower refining margins in the third quarter.

Port Reading reported income of $2 million in the third quarter compared to a loss of $27 million in the second quarter. During the second quarter, this refining facility was shut down for 41 days for a planned turnaround. The turnaround expenses recorded in the second quarter totaled approximately $27 million after income taxes.

Marketing earnings were $40 million in the third quarter of 2010 compared with $17 million in the prior quarter, principally reflecting higher electricity margins and sales volumes. Trading activities generated a loss of $28 million in the third quarter compared with $5 million in the second quarter.

Turning to Corporate, net Corporate expenses were $26 million in the third quarter of 2010 compared with $42 million in the second quarter. Net Corporate expenses were lower in the third quarter primarily reflecting lower bank facility fees and other general and administrative expenses.

After-tax interest expense was $59 million in the third quarter compared with $52 million in the second quarter. In August 2010, the Corporation issued $1.25 billion of 30-year unsecured notes with a coupon of 5.6%.

Turning to cash flow, net cash provided by operating activities in the third quarter including an increase of $136 million from changes in working capital was $1.246 billion. Net proceeds from the bond offering were $1.241 billion. Capital expenditures were $1.462 billion. All other items amounted to a decrease in cash of $35 million resulting in a net increase in cash and cash equivalents in the third quarter of $990 million.

We had $2.353 billion of cash and cash equivalents at September 30, 2010, and $1.362 billion at December 31, 2009. Our available revolving credit capacity was $3 billion at September 30, 2010. Total debt was $5.584 billion at September 30, 2010, and $4.467 billion at December 31, 2009. The Corporation's debt to capitalization ratio at September 30, 2010, was 26.1% compared with 24.8% at the end of 2009.

This concludes my remarks. We will be happy to answer any questions. I will now turn the call over to the operator.

(Operator Instructions) Edward Westlake, Credit Suisse.

Good afternoon, good morning. Great results. I guess the overlift will be a big contributor to them. I actually have two questions. One is on the Eagle Ford. Effectively, can you talk through your strategy there? And I think on Q2, you spoke of further acquisitions in other nonconventional. So perhaps a broader comment on the nonconventional strategy.

And then the second one is around refining. You're still obviously losing net income. Perhaps some decisions around profit improvements or any plans on disposal. Thanks.

Thanks, Ed. This is Greg Hill. Let me talk about the Eagle Ford and then I will talk a little bit broader about unconventional strategy. So yes, we are building and have been building the position in the Eagle Ford. We have about 75,000 net acres as we speak under a contract and our plans are to begin drilling in November in the Eagle Ford. And if we can get additional acreage, we will expand that position further.

Regarding kind of broader unconventionals, as we said before, we are really focused domestically in the US in our Bakken position and the Eagle Ford and we have our position in the Marcellus. We continue to look for other opportunities but we are also focusing internationally. Of course we have our Paris Basin position of about one million acres or so with our partner, Toreador. And we have -- we have signed a memorandum of understanding and an agreement with PetroChina to look at unconventional possibilities in Daqing Field in China.

Thank you.

In terms of refining, specifically HOVENSA, we are disappointed with the operating performance of the facility as well as the financial performance and we are working with our partners to find ways to improve both.

Is there anything -- any specific plans or an announcement that you can make or is this just ongoing?

It is ongoing.

Okay, thank you.

Paul Sankey, Deutsche Bank.

Good morning, gentlemen. I guess if we could talk a little bit more about the Bakken, please. Could you just update us at a high-level firstly, I guess there is an implicit increase to your production target there once you've completed American Oil & Gas certainly. And I wondered if there may be also upward pressure from the kind of performance you are getting out of your activities there?

If you could kind of address the high-level question also talk more about all the technical things that you are doing and the progress that you are making there, that would be [kind]. Thank you.

Thanks, Paul. This is Greg. First of all, let me say we are on track in the Bakken. We continue to make significant progress. We are on track to exit the year at a net production rate of about 20,000 barrels a day. As we said, we are marching our way toward 80,000 barrels a day in our existing position in the Bakken.

Regarding the American Oil & Gas position, of course we have not yet acquired that. We are optimistic that that will close but it's early days. We would like to get a few wells in the ground before we issue any additional production guidance associated with that. But obviously we are excited about the acreage, otherwise we wouldn't have acquired it.

Just briefly on well costs are coming in at about $11 million each for dual lateral. EUR is about 1 million barrels per dual and our 30-day average IP rates are on the order of 400 to 500 barrels per day per lateral from 18 stage fracs. So that gives you kind of an overall update of the Bakken.

Great, thanks. One more from me. The West Med write-down, I was a bit surprised by that. Could you just explain what that was about? Thanks.

Sure, while we did have several natural gas discoveries on the block based on the technical work and working with our partners, the quantities of gas found are not sufficient to pursue a commercial development at this time. So during the quarter actually late in the quarter, the partners decided to cease future exploration activities on the block. Again, just from the risks of some of the plays and the ability to make it commercial. And actually now have decided to relinquish a significant portion of the block.

So as a result of that decision by the partnership group just following the GAAP accounting standards, we had to take an impairment in this quarter.

Right, is there any other Egyptian updates to give us?

The only thing from -- in the North Red Sea, John Hess had mentioned that we will be drilling an exploration well there in the North Red Sea and so that is coming up right now in the fourth quarter but outside of that, nothing else.

Finally from me, can you give us a sense of the prospect there?

Yes, so in the Northern Red Sea, this is Block 1 where we have an 80% working interest and we are the operator. It is a cretaceous sandstone play. It's in about 710 meters of water. It's going to take about 90 days to drill and it's an oil prospect that we're looking for oil.

Thank you.

Doug Leggate, Bank of America Merrill Lynch.

Thank you. Good morning, gentlemen. A couple of things from me. Going to the exploration program, 100% in Ghana, 100% in Semai, 80% in Egypt, and a whole bunch of gas in Australia that doesn't have a home yet. Can you just talk about strategically how you might think about perhaps cross-border asset swaps? And perhaps in light of your recent commentary that you may not drill some of these wells with such high interest in the future. That was my first and I have a follow-up please.

Thanks, Doug. I think you know our strategy is to acquire opportunities at high working interest and then as we derisk the wells, then we make a separate decision on whether or not we're going to farm them down or not. I think in Ghana and Semai, we are in active discussions with a number of potential partners or farm-in offers. And I think assuming we get an acceptable deal, we will probably farm down both of those wells pre-drill.

You had mentioned Australia as well. I mean, obviously we are not going to build LNG plants in Australia, so we will likely take a partner on our 100% position in Australia as well linked to the liquefaction route.

Greg, should we expect that the farm down of Ghana, given that it's going to spud here pretty quickly might be related in some way to accelerating your place in the queue for LNG in Australia? Are the two linked or is it completely separate in terms of your partner negotiations?

No, I wouldn't say they are necessarily linked, Doug. Some of the partners we are talking to have positions in Australia and so we are talking to them about a number of potential cross-border deals or just a straight promote.

Would the same apply to Egypt? Would you expect to farm that down as well or will you drill 80%?

Well, we have already farmed 20% down to Premier and so I think we will continue to look for partners there as well.

Okay, two other quick ones from me, if I may. Just jumping back to the Eagle Ford, can you tell us where exactly your acreage is in terms of counties, oil/gas window, that kind of stuff? Basically what is your plan for the rig count there? You gave us a pretty clear signal as what you were going to do in the Bakken. But on the on the Eagle Ford, what is your drilling plan and potential ramp up that we should expect over the next year?

It's early days in the Eagle Ford. I guess what I will say is we are firmly in a condensate window and our plan is to drill six wells starting in November just to begin assessing the acreage. After that, then we will make a decision on how to expand and ramp up after we get those initial six wells drilled.

Great, and the last one from me, this one is maybe for Mr. Hess. The Bakken and the Valhall deals appear to give you a pretty good anchor on your 3% growth targets but that doesn't include obviously incremental interest in Tubular Bells, the potential pony development. Can you speak to how you are thinking about your production guidance or longer-term targets now that those deals are being done?

The question, Doug. Basically with our investment program in the Bakken, and now having captured a larger interest in Valhall that also has incremental production over the next five years, we feel pretty good that both of those assets will underpin a minimum of 3% production growth in oil over the next five years. So that's the way you think about our production guidance. But that really is a minimum.

And then as you rightly point out, as the Gulf of Mexico regulatory environment gets clarified, hopefully we will be able to sanction both the Pony and Tubular Bells developments. That would be incremental to our picture. As well as hopefully some success either in other unconventionals that Greg is talking about or some of the exploratory prospects that we have longer-term.

So we feel we acquired a lot of attractive growth options, some of them will not be successful, but hopefully some will and that will incremental to that minimum 3% production growth guidance.

Thanks. Would that also apply to the American Oil & Gas? Is that also additive?

I think the best way to look at American Oil & Gas that that's incremental but on the margin, so it's definitely supportive of that minimum 3% growth guidance.

I will leave it there. Thank you very much.

Mark Gilman, Benchmark Co.

Good morning. Greg, with respect to the parameters on the Bakken that you outlined before, give me and idea if you would whether that represents an average to date and what it looks like from a trend or most current standpoint.

I think on those well results that I quoted, that is an average to date based on the results that we've seen. And I think the only change that we are seeing in the short term is we are going to 22 stage fracs. That's our current design. The averages I quoted you were based on 18 stage fracs, so there will be a little uplift in those as we go to 22 stage.

Greg, while I have you, perhaps you could help me to understand the Tubular Bells transaction. I guess I don't quite understand the nominal consideration. I don't quite understand BP divesting a small portion of it but retaining an interest. A little bit hard for me to relate to exactly what's going on there and what your expectations are. Some comment would be appreciated.

Well, I think in terms of Tubular Bells, obviously BP is restructuring their business globally post Macondo. And so this presented us with an opportunity to increase our interest and become operator of the assets. So we like Tubular Bells. Our partner likes Tubular Bells. Obviously BP likes Tubular Bells because they wanted to retain an interest in it. I wouldn't say anything more than that. It's just them restructuring their portfolio.

The development history there, Greg, has been -- or the appraisal history I guess I should say has been a bit mixed. Has there been a downgrade in your mind in terms of the resource potential?

I think what we've said about Tubular Bells before is we see it to be in excess of 100 million barrels and we will provide some additional information post sanction on the volume side.

That's a gross number, I assume?

Yes, gross.

Okay. Just one more from me. Regarding European gas, give me an idea if you could in rough terms how much you sell spot versus how much is under contract? And also any portion that may be specifically linked in one way shape or form to crude oil and/or petroleum product prices?

So basically you've got a mix when you are looking at Europe between UK, Norway, and Denmark, pretty much the majority of our production is coming out of the UK and that is being sold at spot prices. In Norway and Denmark, there you have contractual terms to it that does have some linkage then to the oil markets.

Thanks, John.

Evan Calio, Morgan Stanley.

Good morning, guys. Good quarter. Exciting exploration calendar into 2011. I guess I have two follow-up questions, one for Greg on the Red Sea. Any predrill range there or a description more of what the play type is? If you guys are doing a two-well program, are those back to back wells that you are thinking right now?

Again, Evan, the Northern Sea Block is a cretaceous sand stone play. That's the first well. We believe its in oil -- it will be an oil prospect and the prospect size is on the order of 100 million to 200 million barrels.

The second well is a bit dependent on the first well. We do plan to drill a second well but the location of that well really depends on what happens with the first well.

Okay, so it's the same play type, then?

Again, it depends on the results of the first well.

Understood, okay. And then a follow-up if I could also on a prior question on a farm down. Is it -- just to generally understand, I fully appreciate your assessing all the opportunities. But is the goal -- is Hess's goal in a potential swap to remain exploration neutral, if you want? Meaning to swap interest in other projects? Or is that incorrect to think about it that way?

No, I think that you shouldn't assume that as a general rule. It depends on the well, it depends on the technical and the commercial risk profile of the well. Sometimes we will take cash in the form of a promote and/or an international swap. It just really depends well by well.

Okay, good. That's it for me. Thanks, guys.

Arjun Murti, Goldman Sachs.

Thank you, just a couple of follow-ups. On the Australia commercial timing, can we think about that as first half of '11 or do you want to do some of the appraisal work first?

Thanks, Arjun. I think what we want to do is we want to do the appraisal work -- we need to get some critical well data during the appraisal phase. It's key for long-term development planning and pipeline design and those kinds of things. As we've said before, in parallel we are actually working the commercial side, the liquefaction route. So hopefully by the middle of 2011, we will be in a position to pick a route. We will have a significant part of our appraisal program done and then can make an informed decision around sanction.

And the options there are still floating LNG, which Woodside, Pluto 2, and I think Wheatstone are the three possibilities for you?

Yes, with the other possibility of the Northwest shelf.

Northwest shelf as well, great.

(inaudible) always it comes available sometime in the future.

Thank you. you mentioned in the prepared remarks -- it might have been John Hess -- the China, PetroChina memorandum of understanding. Can you just elaborate on what that opportunity is at Daqing in terms of pursuing presumably shale oil opportunities there?

Yes, we signed a joint study agreement with PetroChina and basically it's a tight oil zone in the Daqing Field that potentially by applying Bakken like technology you can unlock. So that's currently what we're looking at.

That's great and presumably the memorandum of understanding is for specifically that zone as opposed to an overall interest in the field or anything greater than that?

Yes, it is. It's specific to the title (inaudible) in the Daqing Field.

That's great and just a final question in terms of what you think is a realistic timing to getting back to exploration in the Gulf of Mexico given the lifting of the moratorium but obviously there are permitting questions and so forth.

Good question, Arjun. I think everyone in the industry is asking that. You know, there's still a lot of uncertainty both regulatory and legislatively as to what's coming at us. So even though the moratorium has been lifted, we are still kind of midcycle I guess in terms of regulatory and legislative understanding of what's going to happen.

I think for planning purposes, we're hoping to get back to work in the Gulf of Mexico in the middle of 2011 sometime, but that's just a planning assumption at this point.

That's great. Thank you so much. I appreciate it.

Paul Chang, Barclays Capital.

Good morning. A number of quick questions hopefully. Greg, based on what you said, presumably that the (inaudible) appraisal well is not going to be drilled in December. And in terms of the process of the unitization with Knotty Head, do you guys have to wait until you finish the last appraisal well and they finish there? Or that you can still go ahead and try to unitize and maybe have a cost that after the last appraisal well make an adjustment. How does that process work?

Let me give you a quick update, Paul, on just where we are. So we continue to make significant progress toward sanction of Pony, so we just signed a letter of agreement, a confidentiality agreement and a data trade agreement with the Knotty Head partners. So the next step now is to negotiate the JOA, which should be completed early next year.

Obviously the timing of the sanction is uncertain due to the permitting delays but specifically due to the Pony 3 well. We intend to get back to Pony 3 as soon as we can obtain a permit from the BOEM and we are in the process of filing all that paperwork as we speak. And so really just for planning assumption, we are assuming that we can get back to Pony 3 sometime in the second half of 2011. That doesn't mean we are still not pursuing doing all the design work, the feed work, progressing the JOA with partners, all those things to move Pony forward.

Right. So in other words, we should not assume that just because you couldn't drill on that last appraisal well that you are in a holding pattern. You are still moving forward and there is a possibility that you may be able to finalize in that, much of that even before the last appraisal well.

Absolutely. We are moving forward, so all of that stuff happens in parallel.

Okay, and in the -- normally you guys don't give any guidance on the next year production and CapEx until after you report the fourth quarter. Is there any kind of rough direction that you can give us in terms of up, down, flat?

No, Paul, I think you said it. We are still in the process of going through all that now and looking at the program for next year and so we will update the guidance in our January call.

Okay and for 2010 production given the strong results in the third quarter, should we assume there's going to be closer to the high-end of the range instead of the middle of the range?

Yes, given the results to date and actually a somewhat later than expected timing of the closing of our UK North Sea natural gas asset sale, we will be at the upper end of our range.

Okay. After you complete the acquisition of the American Oil & Gas, in theory, you had 13 rigs. Are you guys going to stick to the 13 rigs or are you scaling back down to the 10 rigs and just stick with that $1 billion a year kind of capital spending program?

Paul, the American Oil & Gas will be incremental. We plan to develop that with a three rig program, so we will be up to a 13 rig program, so we won't dial back to 10.

The quality -- I know that it's a little bit premature. Can we somewhat using a prorated think that if you are looking for adding about 15,000 barrels per day using a 10 rig program a year when you use that 13 rig rates that that would be closer to 20,000 barrels per day increase?

In other words that the quality of the American Oil & Gas, should we assume that it would be somewhat similar to the area that you are working on today?

Yes, Paul, I think it's real early to figure out what American Oil & Gas is going to provide or whether it is -- you can scale it or whatever. So let's get a few wells down and then we will provide a formal update on what that's going to deliver for us.

Okay, a final question on Bakken. With the Alberta Creeper and the Keystone is up and running, it seems like we have more pipeline capacity than the Canadian heavy oil that is currently available. Is there any opportunity for you guys to ship or to utilize those pipes for Bakken so that narrow the Bakken discount?

Paul, a couple of dimensions there. First, we have our traditional marketing agreements, number one with pipelines in the area. Number two, we are putting in a rail facility which will give us a lot of flex. Number three, we are working with Enbridge on this new pipeline expansion that they have. So those are the sort of the three options that we are doing that should be able to accommodate the production growth that we envision over the next five, six years.

Thank you.

Blake Fernandez, Howard Weil.

Good morning, guys. Thanks for taking my question. Had a question for you on the Paris Basin. Originally I guess I was thinking the testing would begin in the fourth quarter. It sounds like you mentioned the first quarter of '11 you would begin drilling. Any sense of when we might have a kind of final determination on whether that play is going to be economical or not?

Yes, I think what we can say at this point is sometime in 2011 because we will start drilling our first wells in early 2011. And we will certainly have some indication of the commerciality of the play in 2011.

Okay, back to the Bakken. I know there's been some discussion whether the dual completions are the way to go or not. It sounds, Greg, to me like you are still comfortable with that and confident that that is the way that Hess is going to continue to pursue the play, right?

Yes, we are.

Okay, then the final one from me is on the cost in Eagle Ford. I am just curious if you're providing any costs on what you are paying per acre out there?

No, we are not. Obviously that's fairly competitively sensitive.

Sure. Okay. Well, figured I'd ask. Thanks.

Pavel Molchanov, Raymond James.

Thanks for taking my question, guys. First on pre-drill reserve estimates, I appreciate you sharing that for the Red Sea. I wanted to see if I can get you to give those numbers also for the next BMS-22 prospect and/or for Ghana?

No, we typically don't do that. So no, I'm not going to give you those estimates.

Okay, no problem. And then another follow-on on the Paris Basin. If you move to full-scale development down the road, are there any infrastructure kind of offtake capacity issues that would potentially slow you down? I guess I am trying to get a sense of when production there could begin to move the needle for you guys.

I think on the Paris Basin, it's still early days. We've got to drill our first well to even see if there's a commercial development there. There is existing capacity in the basin. There's a refinery near by and so obviously before we entered the play, we looked at those things and don't see them as a significant constraint at this point.

Very good, I appreciate it.

Mark Gilman, Benchmark.

John, I wonder, could you provide some volume number to that overlift and give me a rough idea where?

Sure, Mark. It was a 2.1 million barrel overlift in the quarter. It was primarily EG, about 1.1 million barrels. And then the UK and Gabone, both at around 500,000.

Okay. And just one other one for Greg. Greg, it was my recollection that upon the completion of the 16-well program on your 100% block on the northwestern shelf you would be in a position to give us some kind of resource indication. Can you help us out in that regard?

Yes, Mark, I think I would rather wait until I get my appraisal program done to do that.

Okay, we will wait with interest. Thanks.

Kate Minyard, JPMorgan.

Good morning. Just a quick question on Brunei. Just given your interest in Block Ca1, I was wondering if you could give us any color on just timing? It looks like the operator is eager to start drilling in a short period of time. Was just wondering if you had any insight into whether that was early 2011 or is it a bit too early to tell? Thanks.

Obviously (inaudible) a little context about Brunei first. We are really excited about the prospectivity of that block and as you mentioned, the partnership is in the process of developing a work plan and we expect drilling on the block to begin in mid-2011.

Okay, great. Thank you very much.

Ed Westlake, Credit Suisse.

Yes, just probably a very early number and you probably actually can't answer this, but if you were thinking about just the sort of resource potential of the Paris Basin or Daqing, what kind of order of magnitude if there's modest success or risked outcome do you think the reserves could be?

Ed, it's just too early. We need to get a few wells in the ground and complete our joint study with PetroChina before we can give any kind of estimate to that.

And in the Paris Basin?

The same. We don't even have a well in the ground yet, so let's wait until we get some wells in the ground.

Okay, thank you.

Paul Cheng, Barclays Capital.

John, when you're talking about the (inaudible). At the end of September, are we neutral or still underlift or overlift in the inventory?

Let's just first talk about for the year we actually still are in an underlift position of 1.2 million barrels in the year. So we had some significant underlifts in the first and second quarter. But some of that again was just a catch up. So if I am again looking at the inventories, I think we are fairly balanced at this point right now.

So we should not assume that any meaningful [untending] of [overlift] in the fourth quarter unless the schedule change?

No, I would not assume any. Obviously the scheduling, the timing at quarter end, things could change, but I would not assume anything in here.

Okay, Greg, maybe I missed it. You are saying that -- obviously you guys are not going to build the LNG plant yourself. Is that -- when you are looking at trying to monetize the discovery over there, is that the preferred way that whatever is the option you choose, you're going to be that have a proportion equity ownership in the LNG [train]? Or that you want to just to be a strict long-term supply contract with no equity in the LNG train?

Yes, I wouldn't make the assumption that we will necessarily have equity in the LNG plant. It could be a tariffing arrangement or whatever, so that is all part of the commercial (multiple speakers)

Right, but I mean from the Company's standpoint, is there one that's more preferable than the other?

It really just depends upon the commercial deal that we strike.

Okay, and then a final one on the BMS-22 in Ghana. How important is the next exploration well to determine whether you are going to stick to the [broad] and continue to do additional drilling in the future or that to the demand that if that turns out to be dry, that means that you guys the interest in those probably would be substantially reduced.

So I'm trying to understand that you already map our additional prospect that you could be interested with Ghana on the success or not on the next well.

Let me talk about, since you mentioned both. So in Ghana, it is a large block. We see multiple play sites on the block, both structural and stratigraphic. Therefore I think the outcome of one well will not be conclusive to the block. So I think you can assume that we will probably drill at least one more well on Ghana.

Regarding Brazil, I think we just have to see the results of the well and then figure out where we go from there.

Okay, very good. Thank you.

Ladies and gentlemen, this concludes the question-and-answer session for today's conference. This concludes your presentation and you may all disconnect. Have a great day.