赫斯 (HES) 2011 Q2 法說會逐字稿

Good day, ladies and gentlemen and welcome to the second-quarter 2011 Hess Corporation earnings call. My name is Modesta and I will be your coordinator for today. At this time, all participants are in listen-only mode. Later, we will conduct a question-and-answer session. (Operator Instructions). As a reminder, this conference is being recorded for replay purposes. I would now like to turn the conference over to your host for today, Mr. Jay Wilson, Vice President, Investor Relations. Please proceed, sir.

Thank you, Modesta. Good morning, everyone and thank you for participating in our second-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 second-quarter conference call. I will make a few brief comments after which John Rielly will review our financials.

Net income for the second quarter of 2011 was $607 million versus $375 million a year ago. Our earnings were positively impacted by higher crude oil selling prices, which more than offset the impact of lower production volumes and weaker downstream results. Exploration and Production earned $747 million. Crude oil and natural gas production averaged 372,000 barrels of oil equivalent per day, which was 10% below the year-ago quarter.

Over the past six months, we have experienced several setbacks, most of which are short term, that have resulted in production below the year-ago period and our forecast for this year. With regard to the Bakken, harsh winter weather and severe flooding this spring in North Dakota resulted in a backlog of well completions. Net production from the Bakken averaged 25,000 barrels of oil equivalent per day in the second quarter, which was flat with the first quarter.

With improved weather conditions and our recent change to a 38-stage frac design, we expect to close the gap against our production plans over the next six to nine months. As of yesterday, our net Bakken production was 34,000 barrels of oil equivalent per day.

In terms of the shut-in Llano Number 3 well in the Deepwater Gulf of Mexico, the operator plans to perform a workover and restore production in the first quarter of 2012.

Regarding Libya, no estimate as to the timing of the resumption of production can be made until the Civil War is resolved and stability returns to the country.

Lastly, a recent fire at the Valhall Field offshore Norway has shut in a net 30,000 barrels of oil equivalent per day. The government and operator of the field are both conducting an investigation so that lessons can be learned and a recovery plan can be put in place to restore production.

As a consequence of these various factors, we now forecast 2011 production for our Company to average between 375,000 and 385,000 barrels of oil equivalent per day versus our previous forecast of between 385,000 and 395,000 barrels of oil equivalent per day.

With regard to deepwater exploration, we confirmed in May a discovery at our Paradise prospect in Ghana. The well, drilled on our 90% owned Deepwater Tano/Cape Three Points block, encounter 490 feet of net pay. Preliminary reservoir formation testing confirms that the fluid types comprise oil and gas condensate. We plan to begin appraisal drilling in early 2012, subject to government approvals and rig availability.

In Indonesia, we spud the Andalan well on the Semai V block on July 12. Hess has a 100% working interest in the block. In Brunei, the operator of block CA-1, in which Hess has a 13.5% interest, intends to commence exploration drilling later in the third quarter.

This morning, we announced that we, along with our partner, Petroceltic International, signed production-sharing contracts with the Kurdistan Regional Government of Iraq for the Dinarta and Shakrok exploration blocks. Hess will have an 80% paying interest and be the operator of the blocks, which have a combined area of more than 670 square miles.

Under the terms of the contract, we will acquire 2D seismic and drill at least one well on each of the blocks over the three-year license period. Based on the anticipated work programs, Hess's total financial commitment is expected to be approximately $288 million.

Turning to Marketing and Refining, we reported a loss of $39 million for the second quarter of 2011. Financial results at our HOVENSA joint-venture refinery were below the year-ago quarter. While the new refinery configuration has started to make a positive contribution to financial performance, it was more than offset by higher fuel costs. Marketing earnings were above the second quarter last year.

Retail marketing benefited from improved margins in May and June. Gasoline volumes on a per-site basis were down approximately 2% and total convenience store sales were down by 4%, both reflecting the weak economy. Our energy marketing business delivered strong results, helped by higher year-over-year natural gas and electricity sales volumes.

Capital and exploratory expenditures in the first half of 2011 were approximately $2.7 billion, substantially all of which were related to exploration and production. For the full year 2011, our capital and exploratory expenditures forecast has been increased to $6.2 billion from $5.6 billion. Additional investments in the Bakken and Eagle Ford, as well as the recently announced Kurdistan exploration agreement, account for the increase.

We remain committed to sustaining the profitable growth of our reserves in production and ensuring we have the financial strength to fund our future investment opportunities. I will now turn the call over to John Rielly.

Thank you, John. Hello, everyone. In my remarks today, I will compare second-quarter 2011 results to the first quarter. The Corporation generated consolidated net income of $607 million in the second quarter of 2011 compared with net income of $929 million in the first quarter. First-quarter 2011 results included an after-tax gain of $310 million related to the sale of the Corporation's interest in certain natural gas-producing assets in the United Kingdom North Sea.

Turning to Exploration and Production, Exploration and Production had income of $747 million in the second quarter of 2011 compared with income of $979 million in the first quarter. First-quarter results included the after-tax gain of $310 million related to the previously mentioned asset sales. Excluding this item, the changes in the after-tax components of the earnings are as follows. Higher selling prices increased earnings by $165 million. Lower sales volumes decreased earnings by $63 million. Lower exploration expense increased earnings by $32 million. Higher operating costs decreased income by $52 million. All other items net to a decrease in earnings of $4 million for an overall increase in second-quarter adjusted earnings of $78 million.

Our E&P operations were overlifted in the quarter compared with production, resulting in increased after-tax income of approximately $20 million. The E&P effective income tax rate for the second quarter of 2011 was 38%. In July 2011, the United Kingdom enacted an additional 12% supplementary tax on petroleum operations with an effective date of March 24, 2011. As a result, we expect to record a charge of approximately $50 million in the third quarter. This charge includes a provision of approximately $20 million, representing the incremental tax on earnings from the effective date to the end of the second quarter and a charge of approximately $30 million to increase our deferred tax liability in the United Kingdom.

For the full year of 2011, we expect our normalized E&P effective tax rate will be in the range of 38% to 42%. The forecast includes the impact of the additional 12% supplementary tax on 2011 earnings and is based on the assumption that our Libyan production will be shut in for the remainder of the year.

Turning to Marketing and Refining, Marketing and Refining generated a loss of $39 million in the second quarter of 2011 compared with income of $39 million in the first quarter. Refining operations incurred a loss of $44 million in the second quarter of 2011 compared with a loss of $48 million in the first quarter. The Corporation's losses from its equity investment in HOVENSA were $49 million in the second quarter of 2011 compared with $48 million in the first quarter.

The Corporation's share of HOVENSA's results included income from LIFO inventory liquidations of approximately $14 million in the second quarter of 2011 and $40 million in the first quarter of 2011. The inventory liquidations were initiated as a result of the reconfiguration of the refinery.

Port Reading reported earnings of $5 million in the second quarter of 2011, up from $2 million in the first quarter. Marketing earnings were $28 million in the second quarter of 2011 compared with $68 million in the first quarter, principally reflecting seasonally lower margins and sales volumes in energy marketing, partially offset by improved retail gasoline margins. Trading activities generated a loss of $23 million in the second quarter of 2011 compared with income of $19 million in the first quarter.

Turning to corporate and interest, net corporate expenses were $42 million in the second quarter of 2011 compared with $28 million in the first quarter, reflecting higher insurance and employee-related costs. After-tax interest expense was $59 million in the second quarter of 2011 compared with $61 million in the first quarter.

Turning to cash flow, net cash provided by operating activities in the second quarter, including an increase of $308 million from changes in working capital, was $1.689 billion. Capital expenditures were $1.375 billion. All other items amounted to a decrease in cash of $88 million, resulting in a net increase in cash and cash equivalents in the second quarter of $226 million.

We had $2.194 billion of cash and cash equivalents at June 30, 2011 and $1.608 billion at December 31, 2010. In April, we entered into a new five-year revolving credit agreement, which increased the capacity under our credit facility to $4 billion from $3 billion. Total debt was $5.541 billion at June 30, 2011 and $5.583 billion at December 31, 2010. The Corporation's debt to capitalization ratio at June 30, 2011 was 22.7%, compared with 24.9% at the end of 2010. This concludes my remarks. We will be happy to answer any questions. I will now turn the call over to the operator.

(Operator Instructions). Ed Westlake, Credit Suisse.

Good morning, everyone. Hope you are well. The first question I guess is on Ghana. I mean you have said appraisal is going to start in the first half of 2012. Could you be a little bit more specific around some of the other prospects? Is that rig going to go and appraise Paradise, [Beach], Hickory?

Thanks, Ed. I mean we are working those appraisal plans as we speak and we will have to get the approval of the government. So we haven't finalized the exact well sequence. We are going to do that in the coming quarter and then get the government to buy in to that as well.

And so just as a follow-on in terms of when you would expect to get the government's buy-in, it would be sort of a Q4 event, do you think?

Yes, most likely.

And then on the split between oil and gas condensate, obviously, in the prepared remarks, you have said it is both. But do you have a rough split as we sit here today from what you have analyzed in terms of Paradise in terms of how much is of the 490 feet or however you want to explain it is oil and how much is gas condensate?

No, I am not ready to do that yet. We are still waiting on a number of samples to get back from the lab, so it is just a little bit too early to be doing that and we only have one well, of course, at this point.

And so when do you think you might be able to give some of that information? Would we have to wait until after the appraisal is drilled in early 2012?

I think we would prefer to wait until the appraisal program to do that.

Okay. Maybe my second question, and I will give over to others, is just on the Bakken. You were at 34. Where do you expect to be at the year-end run rate?

We are not going to quote that yet. We are still digging out of all the weather and execution issues. So by the end of the year, we are going to give a complete revised outlook for the Bakken, including the five-year forecast.

Would you be able to give a range if there is some uncertainty or just no number?

No, I think we said our forecast for the year-end exit rate is between 30,000 and 35,000 barrels a day in 2011, the average. That is the full-year average.

Okay, thanks very much.

Doug Leggate, Merrill Lynch.

Thanks, good morning, everybody. Can I try a couple, please? I guess I should kick off with the Bakken. It sounds like things have rebounded pretty hard here, but could you give us an idea -- when are you going to give us a proper update on the potential capacity, production capacity of the entire asset?

Let me explain where I am going with this. You are running 18 rigs with more -- I guess more aggressive completion designs. My understanding is the IP rates from the American and the [Triker] acreage are even better than your legacy assets, but you still haven't addressed the 80,000 barrels a day within five years. So if you could really just give us some idea of when you are going to talk about that and where it could likely get to and I have got a follow-up please.

Yes, yes, thanks, Doug. As we have said in the past, we intend to provide an update just as soon as we drill enough additional wells and gather additional data on the acquired acreage. Now as John mentioned in his opening remarks, as a result of the severe weather in the first half of 2011, we are a few months behind schedule on gathering that data. So we will be in a position to provide a revised forecast before the end of the year. And as you mentioned in your question, the last thing I would say is that the IP rates from the wells drilled today down the acquired acreage have met or exceeded our expectations.

Okay. So basically -- is it fair to say that 80,000 barrels a day is probably out of date?

Oh yes, Doug, obviously. With the acquisitions, that is a low number.

Okay. My follow-up, I could maybe squeeze a couple on here back to back, but the Valhall -- clearly, you have 64%, I guess, more or less. Is there any likely change of operatorship here in light of what has happened? I know it is probably a little unfair to point the finger at this point, but if you could give a prognosis as to how -- when you would expect that to come back?

And finally, if Greg is able to, an update perhaps on the Eagle Ford and perhaps some commentary, Greg, about your recent entry into California into what I understand is the [Lower] Monterey, that would be great. Thank you.

Great. Let me take those one at a time, Doug. So on Valhall, as John said, an investigation is ongoing and until complete, it is going to be inappropriate to speculate as to the timing of the restart until we understand all the root causes. And as you can appreciate, I think both us and BP, safety is our number one priority here. So beyond that, we would refer you to the operator.

Regarding your question about operatorship of Valhall, our strategy is to work with BP, work with the operator to get that facility to capacity within five years. So that is our strategy to work with BP on doing that.

Your second question, relating to the Eagle Ford, I believe, let me just give you an update on the Eagle Ford. As you know, we have been building a position there in the Eagle Ford and currently have about 107,000 net acres. We plan to drill between 25 and 30 wells in 2011. 15 wells have been drilled so far and 3 wells have been completed and brought on production and these 3 wells have delivered on average 30-day IP rates of approximately 650 barrels of oil equivalent per day, of which 80% was liquids. So although it is still early days, the initial results from the wells drilled in the Eagle Ford are encouraging.

On the Monterey, as we have mentioned before, we are building an unconventional position and opportunities both in the US and in internationally. And at the appropriate time, we will provide information about any new areas or opportunities that we are entering.

Thanks, Greg. May I push you on the counties in the Eagle Ford? Are you prepared to give us that information yet or still --?

No, Doug, I am not. Things are still very competitive down there and we are just really trying to consolidate our position at this point and so we prefer not to disclose where our acreage is yet.

All right. I will leave it there. Thank you very much.

Paul Sankey, Deutsche Bank.

Hi, good morning, gentlemen. On Ghana, would it be fair to characterize that as a major oil discovery that you are delighted with?

I would say it is fair to characterize it as a major hydrocarbon discovery.

And you are delighted?

We are pleased with the initial results and the test of the well, but we have got to go into appraisal mode to figure out exactly what we have. There is a lot of potential on the blocks. We have got several wells to drill yet to assess the block.

Greg, could you talk a little bit more about the geology and obviously the neighborhood. There is other major stuff there that we all know about that is being developed. How do you see it fitting in?

Well, I think, as we have said on the call last time, we did see a major cenomanian section, opens up a new play concept in that part of the world. And in addition to that, we see a deeper structure below that. So there is multiple play types on the block, which is why our appraisal program really needs to look at all those different opportunities and assess what we have there, but there is multiple opportunities.

So the best guess would be you will be appraising throughout 2012?

We will and of course, we haven't drilled that deeper prospect yet. But that is the plans in 2012 to tap into that as well.

I understand. What is the latest on Pony please?

Pony, again, just not much to update from the last call. The partnership is working on the joint operating agreements, continue to do that. We hope to sanction Pony in 2012. So the partners have signed a letter of agreement, a confidentiality agreement and just working on all the various agreements as well. But again, we are targeting 2012 for sanction, first production likely to occur approximately four years after that.

Thank you. The fact of the Valhall case, I believe it was a compressor fire that burned, and forgive me, this is information that was given to me on the day of the fire, so that is why I wanted to update it. It was a compressor fire that burned for about half an hour and the prognosis may be that allowing for the regulator and all the other uncertainties, this may not be a long-term outage.

Again, Paul, it is hard to say because the investigation report is not complete and so until we understand all the root causes, you are right, it was a vent line on a compressor that was the source of the fire. And again, beyond that, we would refer you to the operator, but we are waiting, just like everyone, for the outcome of the report to see what next steps are.

Thanks, Greg. I appreciate your candidness.

Evan Calio, Morgan Stanley.

Hey, good morning, guys. On the Bakken, I was hoping for an update on your unit train and associated trains loading capacity. How should we think about the planned unit train kind of 1 to 9 with up to -- I think it was max 120,000 barrels a day of capacity? I know you initially go 50,000 to 55,000 into St. James. I guess I am just wondering is whether you see an ability to bring on all capacity that would exceed your evacuation needs that could provide you a nice arbitrage if there is a -- the [LSS] Bakken kind of differential in 2012 that actually we expect there to be?

Yes, if I could, just -- thanks for that -- if I could just kind of review again what our export capacity is out of the Bakken. So existing infrastructure and agreements with Tesoro are for 30,000 barrels a day and that is sufficient in the immediate term. We have also secured pipeline and rail options to export the balance of our production as the production begins to ramp up in the longer term.

The first piece of that is Enbridge, which is 30,000 to 40,000 barrels a day capacity on that and then rail, as you mentioned, is our flex. And we have -- we will have the capacity to go all the way up to 150,000 barrels a day. That facility will be done in the first quarter of 2012. So really we have got plenty of capacity to get our crude to whatever markets we choose. Right now, we have got crude slated to go to St. James refinery.

And the unit trains, I mean all nine unit trains will be delivered in the first quarter of 2012?

Yes. So we have nine train sets that are currently being constructed right now and that is good for about 55,000 barrels a day from those nine train sets. We will add additional trains as needed to match our capacity.

Okay. What is the current time from order to delivery on the rail side, the train side that you are seeing now? We have been hearing like almost a year now.

Well, we got in early on the queue. We did see that coming, so we secured those train sets, so we don't see any bottlenecks for us.

Right. But you see -- you will have excess capacity if you potentially could arbitrage other people's barrels. That is something that would clearly make sense to you, right?

Our first priority is going to be taking care of our own production because of the timing difference next year when Enbridge will come on. The majority of the excess crude that we have after Tesoro will go on the trains. So our first priority is to take care of our own production. If there are other business opportunities after that, that is something we will consider, but that is certainly a second priority at this time.

That is wonderful. One more question, if I may and maybe I missed it on Ghana. Did you say how many rigs you will have there in early 2012?

No, we haven't yet because we just haven't finished the wells we are going to drill or the appraisal program, the order of the wells, how many wells. Again, that is something we have to discuss with the government before we talk about it publicly.

Ideally there could be multiple rigs there, would be pretty reasonable, obviously conditional on government acquiescence, etc.?

Yes, just too early to speculate because, again, we just don't have the appraisal plan lined out yet, but one, maybe two rigs is kind of directionally what we are thinking.

Wonderful. I will leave it there for others and thanks for taking my call.

Mark Gilman, The Benchmark Company.

Hi, guys. Good morning. I have a couple of things. John, can you give me an idea how that $600 million in additional capital budget this year is going to be allocated in terms of the areas you cited?

Sure. We will give you, on a general basis, Mark. What we are doing is in the Bakken I think as John and both Greg had talked about that we have increased activity there. We are moving to the 38-stage frac design. We are increasing the number of frac crews and we are also increasing our commitment to non-operated JV drilling in the Bakken.

And then in the Eagle Ford, we have also moved to a 15 to 21 stage frac design. We have also increased the number of wells from our original budget and we have acquired additional acreage, I think as Greg had mentioned. Then with Kurdistan, the financial commitment that John Hess mentioned, a good part of that is coming in 2011 as well. So that is basically how it is allocated.

Okay, regarding Kurdistan, is the front-end payment, which, if you could say what it is, please do, included in the $288 million?

It is included in the 288, but it is sensitive information. We are not going to go into the specifics of that.

Okay. Although you are reluctant to talk about the location of the Eagle Ford acreage, can you give me a rough idea of what the average cost of entry has been?

No, Mark, we are still -- we are acquiring acreage, right, so average about 3,000 or so. That was the early entry cost for us.

About 3000, Greg?

Yes.

Okay. If I could just shift to Ghana for a sec, did you test for the campanian at all in the Paradise well?

No, we did not.

So you did not expect it to be productive?

No, we didn't -- that was not our objective. The campanian was not our objective in that block, in that well.

Okay. Can you give me an idea of what the pay distribution is between the cenomanian or the turonian?

We are not going to give that out yet, Mark. We are just -- again, we are just in the middle of trying to figure out our appraisal program and we are just not going to give out a lot of details because we have got a lot of details to work with the government.

Okay. For John Hess, regarding the HOVENSA reconfiguration, John, I guess I am struggling a little bit in terms of trying to get a handle on the ultimate economic contribution. You referenced in your remarks the negative impact of the offsetting increase in fuel cost year-over-year. Can you put a number on that for me?

No, but I will say this. The reconfiguration allows us to both improve our margin per barrel and lower our operating costs and capital expenditures and also improve our liquidity position by decreasing inventory. So overall, the reconfiguration is economically and financially a strengthening move.

I will also say, notwithstanding the fact that, because of the higher oil prices in the second quarter, a lot of that benefit was given back because of the higher fuel costs. But I think the important thing to note is currently HOVENSA is profitable.

Okay. And John, when you say that, as we speak today moment in time, all the benefits of the reconfiguration have been recognized as of today?

Well, on a going-forward basis, yes. We should be getting more of a recurring benefit from that.

Okay. And just the final thing from me, a capital cost number for the rail project all in?

Mark, we don't give that kind of granularity on the specifics. So I mean you know we are spending in the Bakken obviously a significant amount, so infrastructure and drilling. So we are not going to go into specifics on that.

Any idea what you expect the transportation cost with appropriate return to be at St. James?

Mark, we don't go into those numbers.

Okay, thanks, guys.

Paul Cheng, Barclays Capital.

Thank you. Hey, guys, good morning. Greg, in Ghana, I know you don't have a lot of information yet, but can you tell us how many prospects surrounding Paradise that you have already identified that you plan to drill over the next 20 months?

Thanks, Paul, but we have got a number of prospects and the reason I am being a little bit sensitive about this is we have got a lot of work to do in negotiation with the government. So I really don't want to go public on a lot of things until we are through our negotiation with the government on what the appraisal program is. But suffice it to say that there is a number of prospects on the block.

It seems that you initially announced the discovery in May. Should we -- or in late April, so should we assume that by May of 2013, whatever you didn't declare commercial will need to return to the government, so you basically have 20 months or 22 months there for you to finish all the drilling?

Yes, we have got basically our second license period. We have a couple years to get some drilling done on the block and then we are into another phase of development after that.

Okay. In Indonesia, have you guys got the rig from the Murphy [gang], so the rig is still drilling over there?

Yes, we did get the rig from Murphy. We spudded the well on July 12 on that Semai block. Just update on drilling, we are currently drilling at 9750 feet with a TD expected to be approximately 20,000 feet on that well.

Okay. And so you have another 10,000 feet to go. So it looks like that you probably have another 60, 70 days?

Yes, at least. Drilling takes longer the deeper you go.

Okay. In Eagle Ford, I know, Greg, you don't want to give too much information yet, but you talked about the IP. Can you tell us what is the development cost and also on the fee-producing well, what is the EUR that you are expecting? And also in terms of the time that now you are doing in terms of the drilling time (inaudible) that everywhere how long it take?

Yes, so let me just start with the EURs. We just don't have enough production under our belt to quote an EUR yet. Again, we have only got three wells on production. They are in their very early production phase, so I can't quote you an EUR yet. The well costs are about $10 million each. We expect that cost to come down with time because, again, we are early in the learning curve. That is with a 15 to 21 stage frac design in those wells.

Okay. And of the 25 to 30 wells you plan for this year, how many of them will be complete and in production before the year-end?

We are still working all that out. That is why we gave you a range of 25 to 30 wells. We are continuing to delineate the acreage, so some of those will be exploration wells, some of them might be vertical wells, others will be horizontal wells for completion. So that is why we gave you a range of 25 to 30 wells.

And have you encountered any (inaudible) in terms of water or manpower in Eagle Ford?

No, our partner in the Eagle Ford has been successful in acquiring the equipment and services that we need in a very tight market.

Okay. And in Bakken, can you tell us what is the current development cost, the EUR, the IP and the drilling time and the completion time?

As John mentioned, we have gone to a 38 stage frac design in the Bakken. So that is a combination design where we have 22 sliding sleeve and 16 plug and perf stages to get to that 38 stages. We have actually completed nine wells with that 38 fracture stage design. The initial results are encouraging. Average IPs are exceeding 1000 barrels a day for the 30 day IPs. Now, we are still assuming EURs of about 550,000 barrels per well. Again, we want to get more production data before we update any of our EURs. And the cost of those 38 stage wells is about $10 million. So with that much higher IP and early-time production, obviously the economics are very attractive.

And then we are working on a 38-stage sliding sleeve design, which then has the potential to reduce those costs even further and the time required to complete the well.

And when are -- [that is --] what, about 40, 45 days, including drilling and the completion?

We are drilling wells -- average drilling on these wells is about 34 days. So with the plug and perf, you can add another seven days or so to completion.

And in the 2011 production guidance, what is the assumption of the Waha production order, the Waha downtime, in the 375 to 385?

So as Greg had mentioned, we don't have a firm date when Valhall is coming back. So Waha, first of all, is not in the production at all. It is shut in for the rest of the year and the assumption. Valhall, we have some downtime associated with that in there. And then obviously, as John has mentioned, we have the Llano 3 well that is down for the full year, and then we have got the reduced production from the Bakken. So we think we have captured all those items in that (multiple speakers).

No, but, John, I understand that we don't have a firm, but I am just asking that, in that production guidance, can you share with us what is the assumption of Valhall in that production number or even a range?

Yes, Valhall is going to be shorter term in nature, as was discussed earlier. It is not going to be for the whole year. I mean that much we feel pretty good about saying now. How long it is going to be, that is in the hands of the government and the operator. We have got to give them a chance to figure that out. We were just in Norway last week, so we got a pretty good update on that.

Okay. A final one. On the upstream (inaudible) recently that they are talking about a development project in the south Malaysia that you guys are in. Can you give us any update?

Thanks, Paul. Don't really want to talk about the specifics of that, but we are in detailed and advanced discussions with our partner, Petronas, to expand upon our successful relationship and our position in Malaysia.

Okay. All right, thank you.

Pavel Molchanov, Raymond James.

Thanks for taking my question. First, on Ghana, recognizing that timeline depends on government approval and other factors, assuming everything went perfectly, when could be the first year that you would expect to see production from Ghana?

Gosh, Pavel, it is just too early to speculate. Again, we have got to get through our appraisal program and understand what we have before we can start planning the development.

Okay, okay, fair enough. Second one, on the Paris basin, have you guys kind of written that off completely or do you still see some hope for that play longer term?

Yes, so on the Paris basin, while the new law prohibits hydraulic fracturing, it does allow for an annual review of the subject. So our plan is to proceed with drilling some conventional vertical wells in 2010, understand what we have and while we believe it is going to take time to work through the issues with the French government, we are confident that the drilling and completion operations can be done safely and responsibly. And so we are going to remain actively engaged with local and national stakeholders to progress the appraisal of the licenses with our partner, Toreador.

How many conventional wells do you plan to drill later this year?

We plan to try and drill six.

Okay, with one rig?

Yes.

Okay, thanks very much.

(Operator Instructions). John Herrlin, Societe Generale.

Yes, hi. A bunch of quick ones. With Ghana, you have a very high working interest. Would it be something that you would consider selling down?

Yes, I think we have said before that we look at partnering on a case-by-case basis and if we could get an appropriate deal, we would be interested in farming the interest down there.

Have you had any inquiries thus far?

Yes, we have. We have had a number.

Okay. Regarding the deeper target in Ghana, are we talking a pre-salt-type target?

No, it is just a very large structure below the clastics.

Okay. Tubular Bells still on sanction for 2011?

Yes, it is. I mean the partner group has every intention of sanctioning that project by the end of the year.

Great. Australia, nothing was mentioned. Anything going on there?

Nothing really to update. I mean our appraisal program is ongoing. We've so far flow-tested four wells with results coming in as expected. We did get hurt a little bit by the heavy cyclone activity earlier this year. So that has resulted in some delays to our appraisal program. Commercial negotiations are progressing with the same potential liquefaction partners at Chevron, Woodside and the North West Shelf partnership and we will announce further details once we get that appraisal drilling done and finalize the liquefaction route.

Okay, great. With the Eagle Ford, overpressurized area pretty much, is that fair to say?

Again, I don't want to get into too many details on the Eagle Ford yet because we only have three wells on production.

Okay, it was worth a shot. Refining, why stay with it? We are seeing a lot of disintegration of late. Do you feel you have got the cost down now with HOVENSA, John?

Yes, that's a good question. Obviously, there have been some restructuring moves by other companies and as you know, John, we have done a lot of work over the last 10 years to restructure our own Company significantly to where we are E&P-led, 88% of our capital employed is E&P with only 12% to the marketing and refining and of that number, 10% is marketing, 2% is refining.

So in terms of how we shape our portfolio, we feel pretty good about where we are. Now there is always room for improvement and in terms of doing things to improve the portfolio further in terms of refining, we have and will continue to consider our strategic options. Obviously, in the current environment of the refining business, we have limited options right now even though we will consider them and we also have a joint venture partner that we would need to consult in any decision that we would make.

So the real thing is we are trying to reconfigure the refinery to improve its financial performance with the hand that we have, run it reliably and safely and get a better return out of what we have.

Last one from me, given the discussion on the Bakken marketing, should we expect a holiday train versus a truck? Just kidding.

It's a good idea and we will take it under consideration and I appreciate your thoughtfulness.

Thank you.

Faisel Khan, Citigroup.

Hi, good morning. On the your CapEx in the Bakken, how much would you say -- what percentage of your CapEx is related to kind of midstream and logistics operations, processing and evacuating your crude out of the basin?

Just from a general standpoint, the projects that we have that I will call our midstream and transportation, is approximately $400 million of our capital in the Bakken.

And that is for the entire five-year plan you guys laid out?

No, no, no. It's basically this year and into next year, right.

And that is just logistics alone?

Correct. Logistics, midstream, right, gas plant expansion, those type of things, not the drilling for the Bakken wells.

A lot of those logistical expenditures, including the Tioga gas plant are really this year and next year.

Okay. So that number kind of floats off next year?

Over the next two years, exactly.

Okay, got you. And if I am looking at your US total upstream CapEx of kind of $1.3 billion for the year, what percentage of that is associated with the Bakken?

The majority of our CapEx right now in the US is focused in the Bakken at this point.

Fair enough. And if I am looking at your refining results, and I think I may have missed this in your prepared remarks, but it sounds like the loss was related to the expenses associated with reconfiguring the plan. So in theory, if I take those expenses out, would the losses have been more narrow or less in nature?

And again, as John Hess had mentioned, so we began to get some of the benefits of reconfiguration just at the tail end of the second quarter. So we are beginning to see, in July, that, as John said, we are currently profitable in July. So there were some costs, but the real big thing that we were hit with was the higher fuel costs in the second quarter. So yes, I would say from a reliability and running at the full 350 case, that is where we are going to get the benefit from it and we will start to see that in the third quarter.

Okay. And then last question from me, the trading results, negative $23 million in the quarter, can you discuss what drove that loss?

No, we don't get into the individual trading strategies. Again, the trading operations, they have been profitable 13 out of the last 14 years. So again, the first quarter, basically we had almost $20 million of earnings there. We had a $23 million loss this quarter. So we are around breakeven right now, but we don't get into specifics on the portfolio.

Okay, is that more of a mark-to-market number that moves around? Is that why you see a loss from time to time?

The trading is -- the trading activities are mark-to-market.

Okay, great. Thank you.

Katherine Minyard, JPMorgan.

Hi, good morning. Just a couple of quick questions. Can I just clarify one of the responses from Greg Hill on some of the Bakken data? Did you say 550,000 barrels EUR per well or is that per lateral?

Yes, that is per lateral.

Okay, sorry, great. And then just a quick question on marketing. It looks like it's the first profitable second quarter in a number of years. I am just curious as to whether that is an anomaly or is there a business mix shift or are we seeing a smoothing of some of the seasonal cyclicality that we have seen over the last several years?

Our energy marketing business has been strong and it continues to be strong on a quarter-to-quarter basis. As John mentioned, our natural gas and electricity volumes were up on energy marketing. Now as he also did mention in the quarter, we did benefit from improved retail margins in the quarter. So retail marketing had a strong quarter.

Okay, great. And then just quickly on the Gulf of Mexico, any update on the exploration outlook, any timing that you guys are thinking about as you look at your Gulf of Mexico portfolio?

I think on the Gulf of Mexico, we have applied for a couple of permits in the Gulf of Mexico. That's [Nesdeep] and [Huron]. We have joined obviously both the Helix and the Marine Well containment company to gain the required spill response capabilities and we plan to resume exploratory activities in the deepwater as soon as practicable subject to our receiving permits and rig availability.

All right, great. Thank you very much.

Ed Westlake, Credit Suisse.

Yes, just a very quick follow-up. Obviously, it has been a volatile year with a number of unforeseen events; a lot of it outside your control. I am just wondering if there is any updates to -- normally you give full-year guidance for sort of cash costs, DD&A and total costs.

Yes, good question. Thanks for asking that. We are not changing our guidance on our unit costs. So the guidance that I gave out on the prior call, which was for cash costs were at $18 to $19 per barrel. We are right now for half of the year at $18.47. So that guidance remains the same. Our DD&A rate for the first half was $15.62 per barrel and our guidance remains $15.50 to $16.50 per barrel.

Thanks very much.

Mark Gilman, The Benchmark Company.

John Rielly, what was the volumetric overlift in the second quarter per the earnings impact you cited?

Sure. It was approximately 750,000 barrels and the countries that, for the most part, contributed to that were the UK, Norway, and EG.

Thank you, John.

Ladies and gentlemen, that concludes today's conference. Thank you for your participation and you may now disconnect. Have a great day.