赫斯 (HES) 2008 Q2 法說會逐字稿

Good day, ladies and gentlemen and welcome to the second-quarter 2008 Hess Corporation earnings conference call. My name is Catena and I will be your coordinator for today. At this time, all participants are in a listen-only mode. We will conduct 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 our host for today's call, Mr. Jay Wilson, Vice President of Investor Relations. Sir, please proceed.

Thank you, Catena. 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; John O'Connor, President of 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 financial results.

Net income for the second quarter of 2008 was $900 million, up from $557 million a year ago. Our results benefited from higher crude oil and natural gas selling prices and natural gas production volumes, which more than offset the impact of weaker refining margins compared to those in the year-ago quarter.

For the second quarter of 2008, Exploration and Production earned $1.025 billion. Crude oil and natural gas production averaged 393,000 barrels of oil equivalent per day, which was 4% above the year-ago period. Contributing to higher year-over-year production volumes were strong performance from the Okume Complex in Equatorial Guinea and higher natural gas production volumes from the Cromarty Field in the UK North Sea, the Ujang Pangkah Field in Indonesia and the Malaysia-Thailand JDA.

Our full-year 2008 production forecast remains 380,000 to 390,000 barrels of oil equivalent per day.

With regard to our field developments, we've continued to make good progress. Production from JDA Phase 2 will commence upon completion of the buyer's 42-inch export pipeline. Upon commissioning, net volumes from the JDA are expected to increase to approximately 250 million cubic feet per day. Hess has a 50% working interest in the Malaysia-Thailand JDA.

In the deepwater Gulf of Mexico, development of the Shenzi Field continues to move forward. The tension leg platform hull and topsides have been installed on location. Work on the subsea facilities is ongoing. Commissioning and first production are scheduled for the first half of 2009. Hess owns a 28% working interest in the Shenzi field.

In Indonesia, development of the oil leg of the Ujang Pangkah Field is continuing. Construction of the offshore platforms and onshore processing facilities is on schedule and oil production is expected to commence in the first half of 2009. Hess operates Ujang Pangkah with a 75% working interest.

In the Williston Basin of North Dakota, we have increased our net acreage position in the Bakken Play to approximately 500,000 acres. We currently have seven rigs operating in the Bakken and will add one additional rig in the fourth quarter.

With regard to exploration, on June 5, we announced the successful result of our Pony #2 sidetrack well on Green Canyon Block 468. Based on drilling results to date, the estimated recoverable reserves from the field are approximately 200 million barrels of oil equivalent. We are currently evaluating development options for Pony in which we own a 100% working interest.

On Permit WA-390-P in the North West Shelf of Australia, we recently announced two discoveries. On June 10, we announced that the Glencoe-1 exploration well encountered 92 feet of net gas pay and on July 20, we announced that the Briseis-1 exploration well encountered 151 feet of net gas pay. Results thus far are very encouraging. We plan to drill two additional wells on the Permit in 2008. The next well, Nimblefoot-1, will be drilled about 14 kilometers southwest of the Glencoe-1 discovery and should spud in August. Hess has a 100% interest in Permit WA-390-P.

In addition to the two remaining wells to be drilled in Australia, in the fourth quarter, we expect to spud deepwater wells on Block 54 in Libya, Cape Three Points in Ghana and BM-S-22 in Brazil. Hess has a 100% interest in Block 54 and Cape Three Points and a 40% interest in BM-S-22.

Turning to Marketing and Refining, we reported a loss of $52 million for the second quarter of 2008. Our results were below the year-ago quarter reflecting the difficult economic headwinds we are facing in the United States.

Refining margins at both our HOVENSA joint venture refining and our Port Reading New Jersey facility were lower than a year ago as a result of significantly lower gasoline crack spreads.

Marketing earnings were lower than the year-ago quarter as a result of supply costs rising faster than selling prices. Retail marketing fuel volumes on a per-site basis were down 4% while total convenience store sales were flat. In Energy Marketing, while fuel oil volumes were slightly lower, natural gas and electricity sales volumes continued to grow year-over-year.

Capital and exploratory expenditures in the first half of 2008 were $2.2 billion of which just over $2.1 billion was related to Exploration and Production activities. For the full year 2008, our capital and exploratory expenditures are forecast to be approximately $5 billion, up $600 million from our guidance in January. The increase primarily reflects our success at Central Gulf Lease Sale 206 where we were the high bidder on 25 deepwater blocks and the acquisition of additional leases and increased activity levels in the Bakken Play in the Williston Basin of North Dakota. I will now turn the call over to John Rielly.

Thanks, John. Hello, everyone. In my remarks today, I will compare second-quarter 2008 results to the first quarter.

Net income for the second quarter of 2008 was $900 million compared with $759 million in the first quarter.

Turning to Exploration and Production, income from Exploration and Production operations in the second quarter of 2008 was $1.025 billion compared with $824 million in the first quarter. The after-tax components of the increase are as follows. Higher selling prices increased earnings by $340 million. The impact of sales volumes reduced earnings by $27 million. Higher costs decreased income by $81 million. All other items net to a decrease in earnings of $31 million for an overall increase in second-quarter income of $201 million.

Turning to Marketing and Refining, the results of Marketing and Refining operations amounted to a loss of $52 million in the second quarter of 2008 compared with income of $16 million in the first quarter. Results of refining operations amounted to income of $3 million in the second quarter of 2008 compared with a loss of $3 million in the first quarter. The Corporation's share of HOVENSA's results after income taxes amounted to a loss of $12 million in the second quarter compared with a loss of $6 million in the first quarter, primarily reflecting lower margins. During the second quarter, the Corporation received a distribution from HOVENSA of $25 million.

Port Reading earnings were $14 million in the second quarter of 2008 compared with $2 million in the first quarter. Marketing results amounted to a loss of $40 million in the second quarter of 2008 compared with income of $32 million in the first quarter. Second-quarter 2008 marketing results include seasonally lower margins and sales volumes of natural gas. Trading activities generated losses of $15 million and $13 million in the second and first quarters of 2008 respectively.

Turning to corporate, net corporate expenses amounted to $33 million in the second quarter of 2008 compared with $39 million in the first quarter.

Our after-tax interest expense was $40 million in the second quarter compared with $42 million in the first quarter, principally reflecting lower average debt.

Turning to cash flow, net cash provided by operating activities in the second quarter, including an increase of $294 million from changes in working capital, was $1.691 billion. The principal use of cash was capital expenditures of $1.156 billion. All other items amounted to an increase in cash flow of $42 million resulting in a net increase in cash and cash equivalents in the second quarter of $577 million.

At June 30, 2008, we had $1.479 billion of cash and cash equivalents. Our available revolving credit capacity was $2.718 billion at quarter-end. Total debt was $3.945 billion at June 30, 2008 and $3.980 billion at December 31, 2007. The Corporation's debt-to-capitalization ratio at June 30, 2008 was 26.2% compared with 28.9% at the end of 2007. This concludes my remarks. We will be happy to answer any questions. I will now turn the call over to the operator.

(OPERATOR INSTRUCTIONS). Doug Leggate, Quadrum Capital.

Thanks, hi, guys. I guess I am a little surprised to be on first, but a couple of questions please. The tax rate, John, John Rielly, was a little I guess light. And I am wondering how much of that is production effects and if you could give us some idea as to how that changes over the balance of the year, particularly with the JDA. I think you said last quarter that was like a 0% tax rate. If you could just outline that, that would be great.

Sure, Doug. In the second quarter, the E&P effective rate was approximately 46% and there is nothing unusual in the effective rate. What it had to do what, I think as you were inferring, it had to do with our mix of sales volumes. So while overall in the quarter we really didn't have a net under or overlift, it was the sales volumes approximated our production. Within our various assets, there are underlifts and overlifts. So in the quarter what we were was essentially underlifted in Libya a bit and then we were overlifted in some of the lower taxed countries. And so as a result basically of replacing the Libya sales volumes with other countries' volumes, the tax rate was just down a little bit low. But again, as we seek through the rest of the year, we expect that to balance out and therefore, we still have our guidance of 47% to 51% for our effective rate for the year.

So as the JDA comes on, John, does that skew it to the lower end of that range?

Well, the JDA will have a lower rate. So yes, when that does come on, that production will help to lower our effective rate.

Okay. Just two other real quick ones. Production costs in the US -- again, if you could just kind of lay out how much of that is oil price-related in terms of severance taxes and so on, if there is any other issues in there. And final one from me is just if John Hess could give us an idea how marketing looks so far in Q3. That's it.

Sure. I will start on the cash costs on the production side. So just from an overall context point, we actually see our costs pretty much coming in line with as we expected and in line with our guidance except to your point with one category and that has to do with production taxes and severance taxes. So due to the increased sales prices, which obviously have increased our overall margins, it does drive up our severance taxes, our mineral extraction taxes in Russia and actually from our guidance at the beginning of the year, with prices staying at this level, we could see our production costs being up in the range of $1.00 just due to the production taxes and the effect on prices. So that is having an effect.

And then just from quarter-to-quarter, I think you spoke about the US. We will always have changes as it relates to workovers, so we had additional workovers and additional maintenance in the second quarter and it's typical for us as we go into the third and fourth quarters, especially in the third quarter where we have our maintenance season in the North Sea, there will be a lot more workovers and maintenance cost and that will affect unit costs at that time.

And Doug, in reference to marketing, obviously marketing margins were squeezed in the second quarter. Supply costs were rising faster than selling prices. Obviously, with the over $0.50 a gallon drop in wholesale prices of gasoline and other products since the end of the second quarter, that helps the supply cost pressure and now marketing is in a more profitable position.

Great. Thanks a lot.

Paul Sankey, Deutsche Bank.

Good morning, guys. Kind of amounts to a follow-up I guess. For full-year guidance, we have got you coming in here somewhere above our expectations on volumes, but as Doug was just referencing also somewhere above on costs. You seem to be hinting that we should think about an extra $1.00 on the cost side. Is there anything to say on the volumes in terms of guidance and can you confirm that perhaps production costs will come in a bit higher? Thanks.

From the volume standpoint, as John Hess said in his remarks earlier, we do expect to be in the range of 380,000 to 390,000. We are above that for the first half of the year, but as typical for our portfolio with the maintenance season coming up, our volumes will go down in the second half of the year.

So now as you are looking at costs just from volumes as they go down, you can look at last year too where the second-half unit costs were always above our first half. With lower volumes, the fixed costs going over lower volumes, that increases our unit costs. Also from a maintenance standpoint, we have the higher workovers in maintenance. So again, typically, our unit costs will be higher as it relates to that in the second half of the year.

Then just speaking about guidance, as I said, actually our costs are coming in right in line, right as we expected really from the cash cost standpoint. So our group is doing a nice job on that. But as it relates to the price, obviously, the severance taxes and the mineral extraction taxes in Russia go up as the prices have been increasing. So from our guidance at the beginning of the year, yes, I would say there is $1.00 or so increase related to our cash costs and that is all related just to the production taxes.

I got you. And then a very quick little additional question was the PSC effect this quarter. Could you quantify that?

It is basically again right in line with the guidance that we talked about. We are impacted by the higher oil prices with our PSCs and we will continue to be throughout the year. But I guess the important thing, as John Hess said in his script earlier, we are sticking with our full-year forecast of 380,000 to 390,000 barrels per day and what that is showing is there is some strong production coming out of EG. The Cromarty Field is being produced throughout the summer and so we have got -- our portfolio is performing well and is overcoming any impacts from price on the PSCs.

Great. Just a final one from me, on the two successes of the quarter, first, it seems like the size of Pony would suggest it won't be a standalone development. Could you comment on that? And secondly, on LNG in Australia, is it right given the success -- I think you said it was beyond your expectations. Is it right even so to still consider that to essentially be gas that is in an LNG queue? Thanks.

Let me start with the LNG question second. I think that it is very premature to decide how and if we would commercialize the resources of Block 390-P. Obviously, we were very pleased to have two successes out of the first two wells. We have got another two underway. As a matter of fact, the rig is pulling anchors today to move to the next location over the next three or four days. So we will obviously put our heads together at the end of the four-well program and see what are the options for commercializing the discoveries assuming they may be commercialized.

I would not really visualize the Asian market as having queuing for LNG. I think there were a variety of competing alternatives to move LNG into a very healthy market. And if it turns out that 390-P offers an LNG development opportunity, I would expect it to be competitive into that market.

In terms of Pony, obviously, we would like to maximize the value created for stakeholders in the development of any resource. If Pony standalone creates more value for stakeholders than a joint development, the other side of the lease lot, then that is how we would go. But technically, as we see prices and volumes and costs, it is feasible for Pony as established from the drilling to date to be a standalone development and to be very attractive economically.

When could we see first oil from that, John?

I wish I had a crystal ball, Paul. We are working diligently on a number of development options, as John Hess said, but I think that it is going to take most of the next 12 months to come up with a viable development concept.

Sure, thanks.

Arjun Murti, Goldman Sachs.

Thank you. Just on the Bakken, it looks like you have meaningfully expanded your position. Can you talk at all about where production is, where you see it headed over the next few years? And just any -- clearly you're optimistic about the prospects there in terms of pro well recovery rates or how you see things now versus what they looked like a year ago or two years ago when you last gave an update, in the Bakken?

Well, I think that we are obviously more confident in the commercial attractiveness of the Bakken, and we have manifested that origin by acquiring additional acreage at the play. At this stage, and we tend to take a relatively conservative view of this, until we move to if you will sort of a final investment decision on a major scope of development, which we'll probably kick off in 2009. But at this stage we would typically model a well as saying an average production of 250 to 300 barrels a day.

We think 2P reserves on the order of 500,000 to 600,000 barrels of oil equivalent, well costs in the region of $5 million to $7 million, significantly attractive NPB and PVI, and we are very, very pleased with what we are seeing. I think the major advances that we have made since perhaps the last time we spoke fully about the Bakken is in the completion technology, the use of single extended horizontal wells and then pinpoint fracturing of those wells.

And that has made a big difference in terms of the completion rates and sustainability we are seeing from these wells. Current rate from the Bakken is around about 8000 barrels a day of oil equivalent.

That is very helpful, John. Just to follow up on the JDA commentary, I believe you are waiting for the company buying the gas to finish their portion of it. Is that expected by the end of this year, or we should be -- are you thinking early 2009?

Thanks for the question, Arjun, but let me just give a context for everybody else who may not be quite as familiar with it. We and our partners, PETRONAS, are 50/50 joint venture producers of gas from Block A18 in the joint development area between Malaysia and Thailand.

There are buyers in Thailand and Malaysia who buy the gas from us at the rate of the production facility. The buyers have laid 170 kilometers of a 42-inch pipeline to take the next tranche of gas in Thailand. They laid that through the center of the Gulf of Thailand to another production facility at a facility called Arthit. From Arthit, there is an existing line that moves the gas into the market in Thailand.

The line -- the buyers have laid the line. They have dehydrated it and they have pressure tested it and they are in the process of tying it into a 42-inch valve at the Arthit facility. This has caused them some problems and they are struggling with it and in particular, they need to get hold of a heavy lift vessel as we understand it. That heavy lift vessel is probably going to become available in November and so depending on the pace at which they make the tie-in of a spool that connects our line to their facility or rather their line coming from our facility to their other facility to be precise will depend on when it starts up.

At this stage, I am looking to December, but the monsoon may impact it. All we can go on is their advice. This is when they think they can get a lift vessel. This is when they can complete the work. Probably for modeling purposes, I would put it in at the beginning of '09.

That's great. We have actually got it ramping up over the course of '09, so that sounds like that conservative assumption is probably still good.

Yes, the other thing I should obviously add with respect to that is that while it affects our production volumes and forecast, just the fact it's economic because the buyers have a got a take-or-pay contract with us and so a take-or-pay is accumulating as we speak.

Good point. If I could trouble you for one thing, you have been so helpful so far, thank you. Do you have approximate spud dates for 54, Ghana and the BM-S block?

I am hopeful that Block 54 will be spudding earlier of the two and that'll probably be at the beginning of the fourth quarter. I think that Ghana is probably likely to be November.

And Brazil?

Brazil will spud, according to the operator's latest guidance to us, right at the end of September. The drillship that will be used to drill at the West Polaris is actually en route and has left the construction facility in Brazil. I think it may be in Singapore right now. Then they do some work there, then it moves on to Mauritius, change crews and then move on to Brazil.

That's fantastic. Thank you so much, John.

Sure. You are welcome.

Mark Gilman, The Benchmark Company.

Good morning, guys. A couple of things. First, for John O'Connor. John, Cape Three Points, is that a structure or a stratigraphic type trap?

That's a good question. It is a structure.

Even though Jubilee is stratigraphic?

You are trying to make me draw a comparison between the play types for an offset competitor and ours. They are not exactly the same plays, Mark.

I wouldn't do that.

Okay, I thought you wouldn't. But I gave you a clue. They are not the same play.

Okay. On BM-S-22, industry indications are that the well is going to be drilled uptip toward the crest relative to Carioca. Do you concur with that?

Do I concur with the location? I concur with the location because we, the operator and Petrobras, all parties who are selecting the location, so yes, we are aligned in terms of choosing the location.

Okay, do you have a commerciality threshold in mind for 390-P in terms of resource?

No, and I am careful not to get myself ahead of the drilling results, but I would say that, in my experience and I think it is borne out by other manufacturers of LNG, you get benefits of scale when you have more than one train.

So does that mean a commerciality threshold minimum three to five Ts?

I would really rather wait until we see what the market is, what the costs of the technology are and what is the optimal development. But it is sizable obviously. As industry has pushed forward with getting bigger and bigger trains to drive better and better efficiencies, then that really is a moving target and I think at the end of the day when we see what we will have on block, we will decide what commerciality requirement is.

Okay, and then just finally, two quick ones for John Hess if I could. John, we see three straight quarters of double-digit trading losses. Any reconsideration of the merits of this particular activity?

No, it is a small piece of our business. It has had 10 years of profitability. The year isn't over yet. Let's see where they end up at the end of the year before we declare it to be a year where it's losses. But no, it has got good risk controls, good risk management, smart people running it and they have had 10 years of a very good profitable track record and it is a small piece of the business. So no intent to change that, Mark.

Okay. And just one final one, I noticed that HOVENSA, the FCC utilization rate down in the quarter. Was that a voluntary cutback or was there downtime involved?

No, the majority of that had to do with the fact that gasoline margins were so poor and it made economic sense to run the [cat] cracker at the lower rate.

Thanks a lot, guys.

Erik Mielke, Merrill Lynch.

Yes, hi. I have a couple of questions, firstly, starting with the quarter and then getting back to exploration. The production, liquids production in the quarter was somewhat better from Africa than what we had expected. Was that just a full quarter of production from the expansion of the Okume Complex or were there some other gains taking place?

Actually the numbers have failed to do justice to Equatorial Guinea quite frankly because we also experienced a reduction in Algeria I think as a result of the operation or production sharing contract. So yes, the Africa production is up on the back of a very strong performance, both from Okume Complex and from Ceiba. As a matter of fact, in the quarter, it is the first time the gross production exceeded 110,000 barrels a day.

Very good. Thanks. And then following up on Australia, you have had two discoveries already and the pre-drilled resource range was a very wide 2 to 15 Tcf and I gather from what you said earlier that you are not about to narrow that on this call. But can you give us some idea of when you think you might be able to do that? After the third and fourth well, would you be able to come up with a more specific range at that point?

I definitely would expect that we can narrow the range after the four wells have been drilled. There are two things at work. It is a very big block and while John has talked about the location of the next well being 13 or 14 kilometers from Glencoe, it is actually 25 kilometers from Briseis, which is the current well. So it gives you a sense of how big this block is. We will have the results from four wells, which we will lead to extrapolate in order to get an understanding of the total resource. But yes, the range will have narrowed.

Furthermore, more importantly probably, in the fourth quarter, we will receive processed 3D seismic over the block and that is really going to help us pin down the resource estimate because what we have seen from the first two wells, which were drilled on the basis of 2D seismic, is that the post-drill outcome is conforming very much to the pre-drill estimate on the basis of seismic. So this is really encouraging, which means that once we have the 3D seismic in hand at the end of the year, we will be able to make much more accurate projections we think of the total resource on the block. So it is really towards the end of the year.

Very clear. And finally on Tubular Bells, which you didn't mention in your run-through, BP yesterday on their conference call talked about a shared infrastructure for Tubular Bells in Kodiak. Any update on Tubular Bells for you?

No, I mean at the present time, BP I think are proceeding to evaluate a number of different options. One of which is to look at it in the context of the offset discovery at Kodiak. We will have views on that, but at the current time, we are working with BP to ensure that we get the SOP on the Tubular Bell leases. Once that has been secured, then we will proceed from there to work with them to come up with the best solution.

That's great. That's all for me. Thanks.

(OPERATOR INSTRUCTIONS). Paul Cheng, Lehman Brothers.

Hi, thank you. Good morning, guys. John, any rough estimate, what is the 2009 capital spending in the production may look like?

At this time, we don't forecast what our 2009 plan is. I mean we will be going through the budget process. There is obviously, as you know, a lot of things going on with our exploration program at the end of this year. So right after our fourth-quarter conference call -- I mean at that call, we will give guidance next year on our production and our capital spend.

Okay. I think this is for O'Connor. John, you had talked about EG is doing about 110,000 barrels per day. I suppose that that would suggest that Okume is about in the 70,000, which is higher than what I think was the original design expectation. Is the 70,000 barrels per day sustainable at all?

Sorry, just repeat the last part, Paul.

Yes, 70,000 barrels per day that I presume Okume is currently producing, is that sustainable?

It is indeed sustainable as a function of the number of production wells that may be drilled. Right now by comparison with well densities that are more typical in the United States, Okume is relatively underdrilled. And so one can sustain the plateau for a number of years by continuing to drill. We expect to see that happen by the way.

Right. If that is the case then, I'm a little bit surprised you did not raise the full-year production target. I understand the third quarter, you're going to have the downtime from the maintenance work, but at the same time that in the fourth quarter you also have the seasonal uptick of the North Sea gas supply, so net net, I can't see why the second half is going to be lower than the first half.

Well, I am not sure that --

Are you being just very conservative or --

Seasonally, Paul, the third quarter is going to be low like it has been every other year because of North Sea maintenance. And then we'll pick back up again in the fourth quarter. So it may run about the same as the first two quarters, but there are a number of negatives.

In the third quarter, Ceiba volumes will be reduced net to us as a result of the functioning of the production sharing contract. In the fourth quarter, I am happy to say in a way that Okume Complex will also have net reduction to us even though the gross volumes will be up because of the functioning of the production sharing agreement. So those are two major impacts on us. And we have said earlier that we now no longer believe that it is likely that Phase 2 of the JDA, which is roughly net 20,000 barrels a day to us from the point in time when it starts up, will be included in this year's volumes, but will be included in next year's.

So the JDA gas volume then you would expect for the second half of the year similar to the second-quarter level?

Yes, exactly. Of course, second quarter is up on comparison with what we used to call Phase 1 because there are some additional volumes, which are flowing to a power plant in southern Thailand. So the old 390 number is probably running at about 475 right now gross basis, dry gas.

But you don't expect that it is going to see any additional increase in the second half?

No, because the buyers can't take the volume and so the markets for the gas are now getting the gas that the markets need. What we need is the pipeline to be connected by the buyers so that they can catch up with their take obligations.

And John, is there anything you can share with us about the characteristic of the Australian gas in terms of is there any CO2 or solid gas in that? And you talked a bucket that you drill, how big is that and what kind of permeability that you are seeing?

The gas samples from the second well have not been back from analysis yet so I can't speak to that. The first well was a Jurassic discovery, so working in two different horizons, which will likely have two different gas properties. But in the Jurassic, there was minimal CO2, fairly typical for the Jurassic in the basin.

Okay, so that means that the development costs, that should be pretty typical. You don't have any complication on that?

No complications, but I would not necessarily say it was typical because some of the developments in the basin do have high CO2 and they have to include costs to cope with that. If we have better gas with less contaminants than the competitors, then I would say the gas development costs would be atypically lower.

Right. That's what I was referring to. So far then you haven't seen a high CO2 or solid gas complication in there yet.

Right.

And what is the size of the pre-drill target on those buckets?

We have a variety of pre-drill targets and it is sort of meaningless to talk about it in that context, Paul, quite frankly. What I would say is, as we have reported, that the net pay thicknesses are consistent with the net pay thicknesses on the pre-drill.

Well, then let me ask you in another way, by the end of the year after you finish all the four well program, would that provide you sufficient information to decide whether you have enough gas or not?

We hope that would be the case. We certainly hope that will be the case.

Okay. And I think that this one is for John Hess. John, in HOVENSA, I think that you guys indicated that earnings is actually sequentially down, but it looked like all the benchmarks indicators that we track or anyone tracks sequentially margin is up. So is there anything unique about HOVENSA in the second quarter that leads them to be sequentially lower in earnings?

You are right to ask the question. On a gross basis, margins were sequentially up, but on a net basis, there are three factors that took it lower versus what the benchmarks would have said. One is the timing of some ships and we are on a LIFO basis, so that is a timing issue. Two, with $140 barrel crude oil -- with a $140 barrel crude oil, fuel cost was exceptionally high and you know it is an island refinery, so we need crude oil as the source of our cost of fuel. And third, there were some one-off expense items that just hit us in the quarter. So there were quarterly issues that had to do with the second quarter that took it marginally down.

John, when you say timing of the shipping, is that crew or product?

Products.

Products. Okay. And finally that is for John Rielly, I think you had indicated that the unit cash operating costs now maybe $15, $16 for the year. Any update about the DD&A? Are we still looking at 12.5 to 13.5 or that has been changed also?

We are not changing it. I would guide you towards the high end of the range and it has to do -- I'm following on with what John O'Connor, what we talked about our production earlier where we do have some PSC impacts going on, but from a gross standpoint, the EG volumes that were higher than our guidance earlier in the year, so on the EG field, they are just higher DD&A fields. The same with Cromarty. It was producing through the summer. From a portfolio standpoint, Cromarty is a higher DD&A field. So just from the mix again, it is coming in as expected with our fields, but from the mix standpoint, I would guide you to the high end of the range on the DD&A.

Very good. Thank you.

Mark Gilman, The Benchmark Company.

If I could, for John Rielly, the working capital liquidation you referred to, John, in the quarter, I guess in a rising price environment, I don't quite expect that. Is that likely to reverse over the balance of the year?

Yes, and again, typically, what happens with us, if you look at the second quarter last year, we had an increase in our cash flow from working capital of $270 million. So again, with the buildup from the winter in the first quarter and then the depletion in the receivables coming back in, we usually get a pick-up in the second quarter. And yes, I mean it is very difficult to forecast where the working capital -- typically, it will reverse and then obviously, in the fourth quarter when you're building to LIFO inventory layers and things like that, you will end up having some inventory builds back up in the fourth quarter.

Okay, and if I could, just one final one for John O'Connor. The PSC effect, John, you referred to on Okume a moment ago, is that the same as the dollar cost recovery limit effect on Ceiba or were you talking about some other feature?

If you don't mind, Mark, I will answer that. Yes, I mean that is exactly what it is. It has to deal with the cost recovery if you want to call it when the saturation points hit on cost recovery on Ceiba and Okume as well.

So same on both, John?

Correct. They both have -- again, from the PSC standpoint, they both will hit cost saturation in the second half of the year.

Okay, guys. Thank you.

Ladies and gentlemen, this concludes our question-and-answer session. Thank you for your participation in today's second-quarter 2008 Hess Corporation earnings conference call. This concludes the presentation. You may now disconnect. Good day.