Jay Wilson - VP of IR John Hess - Chairman and CEO John Rielly - SVP and CFO John O'Connor - President of Worldwide Exploration and Production

Doug Leggate - Quadrum Capital Paul Sankey - Deutsche Bank Arjun Murti - Goldman Sachs Mark Gilman - The Benchmark Company Erik Mielke - Merrill Lynch Paul Cheng - Lehman Brothers

Good day, ladies and gentlemen, and welcome to the second quarter 2008 Hess Corporation's Earnings Call. My name is Katina, 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 play 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, Katina. Good morning, everyone, and thank you for participating in our second quarter earnings conference all. 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, Worldwide Exploration and Production; and John Rielly, Senior Vice President and Chief Financial Officer. I'll 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 Ujung 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 continue 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 deep water Gulf of Mexico, development of the Shenzi field continues to move forward. The tension-leg platform haul and top sides 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 at the Ujung 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 Ujung 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 we will add one additional rig in the fourth quarter. With regard to exploration, on June 5th, we announced the successful result of our Pony #2 sidetrack well on Green Canyon Block 468. Based on drilling results today, 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 10th, we announced that the Glencoe-1 exploration well encountered 92 feet of net gas pay. And on July 20th, we announced that the Briseis-1 exploration well encountered a 151 feet of net gas pay. Results, thus far, are very encouraging. We planned 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 is 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 deep water wells on Block 54 in Libya, Cape Three Points in Ghana and BMS-22 in Brazil. Hess has a 100% interest in Block 54 and Cape Three Points and a 40% interest in BMS-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 refinery 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 convenient 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 forecasted to be approximately $5 billion, up $600 million from our guidance in January. The increase primarily reflects our success at Central GOM Lease Sale 206 where we were the high bidder on 25 deep water 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 $1.25 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 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 increasing 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 million 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.

Thank you. (Operator Instructions). Your first question comes from the line of Doug Leggate representing Quadrum Capital. Please proceed. Doug Leggate - Quadrum Capital: Well, thanks. Hi guys. I guess I'm a little surprised to be on first, but a couple of questions please. The tax rate John Rielly was a little, I guess, light. And I'm 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 could you 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 with, 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 on 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 tax countries, and so as a result basically 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 the balance out, and therefore we still have our guidance of 47% to 51% for effective rate for the year. Doug Leggate - Quadrum Capital: Great. As the JDA comes on John, does skew it to the lower end of that range?

Well, the JDA will have a lower rate, so yes, whet that does come out, that production will help to lower our effective rate. Doug Leggate - Quadrum Capital: Okay. Just two other real quick ones. Production cost in the US, again if you could just lay out, how much of that is oil price related in terms of severance taxes and so on as far as any other issues in there? And the final one from me is, 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 cost on the production side, so just from an overall context point, we actually see our cost pretty much coming in line with as we expected and then 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 sale 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 cost being up in the range of a $1 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 know you look, 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 quarter, especially in the third quarter we have our maintenance season in the North Sea. There will be a lot more workovers and maintenance costs 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. Doug Leggate - Quadrum Capital: Great. Thanks a lot.

The next question comes from the line of Paul Sankey representing Deutsche Bank. Please proceed. Paul Sankey - Deutsche Bank: Yeah. Hi, good morning, guys.

Good Morning Paul Sankey - Deutsche Bank: It just amounts to 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 on the cost side. Is there anything to say on volumes in terms of guidance? And can you confirm perhaps the production costs will come in a bit higher? Thanks.

From the volume standpoint, as John has said in his remarks earlier, we do expect to be in the range of 380 to 390. 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 it go down, I mean you can look at last year too where the second half unit costs are always above our first half with lower volumes. The fixed costs going on lower volumes that increases our unit costs. Also from a maintenance standpoint, we have the higher workovers and 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, we actually our costs are coming in right in line, right as we expected really from the cash cross standpoint. So our group is doing a nice job on that. But as it relates to the price, obviously the severance taxes and the middle of obstruction taxes in Russia go up as the prices haven been increased. So from our guidance at the beginning of the year, yes I would say there is a $1 or so increase related to our cash costs and that's all related just to the production taxes. Paul Sankey - Deutsche Bank: I've got you. And then a very quick little additional question was the PSC factor this quarter, could you quantify that?

It's basically again right in line with the guidance that we talked about. We are impacted by the higher oil prices with our PSCs and will continue to be throughout the year. But I guess the important thing, as John has said, in his script earlier, we are sticking with our full year forecast of 380,000 barrels 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 got, our portfolio is performing well and is overcoming any impacts from price on the PSCs. Paul Sankey - Deutsche Bank: Great. And just the final the 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 that it was beyond your expectations, is it right even so to still consider that to essentially be gas that is in an LGN queue? Thanks. John O'Connor: Let me start with the LNG question, second. I think that it's very premature to decide how and if we would commercialize the resources, Block 390-P. Obviously, we were very pleased to have two successes out of the first two wells. We've got another two underway. As a matter of fact, the rig is pulling anchors today. It moved to the next location over the next 3 or 4 days. So we'll 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 maybe 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 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 on the other side of the lease lot, then that's 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 active economically. Paul Sankey - Deutsche Bank: When could we hope to see first oil from that, John? John O'Connor: I wish I had a crystal ball, Paul. We are working diligently on a number of development options, as John has said, but I think that it's going to take most of the next 12 months to come up with a viable development concept. Paul Sankey - Deutsche Bank: Sure, thanks. I am sure there is a thousand witty things I could say about being called Doug but I will leave it. Thank a lot. John O'Connor: Okay. I appreciate that.

The next quarter comes from the line of Arjun Murti representing Goldman Sachs. Please proceed. Arjun Murti - Goldman Sachs: Thank you. Just on the Bakken, it looks like you've 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 are optimistic about the prospects there in terms, per well recovery rates, how you see things now versus what they look like year ago, two years ago when you last gave an update in the Bakken? John O'Connor: I think that we are obviously more confident in the commercial attractiveness of the Bakken and we have manifested that Arjun by acquiring additional acreage of 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 will probably kick off in 2009. But at this stage, we would typically model a well as saying an average production of 250, 300 barrels a day. We think 2-P reserves have 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 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 had 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 oil equivalent. Arjun Murti - Goldman Sachs: That is very helpful, John. Just a follow-up on the JDA commentary, I believe you are waiting for the company buying the gas to finish pipe, their portion of it, is that expected by the end of this year or we should be are you thinking early 2009? John O'Connor: No, thanks for your 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 A-18 in the Joint Development Area between Malaysia-Thailand. Then there are buyers in Thailand and Malaysia who buy the gas from us at the rate of the production facility. The buyers have laid a 170 kilometers of 42-inch pipeline to take the next tranche of gas in Thailand. They have laid that through the center of the Gulf of Thailand to another production facility at a facility called [Ortif]. From [Ortif], there is an existing line that moves to gas into the market in Thailand. The buyers have laid the line, they have dehydrated it and they pressured tested it and they are in the process of tying it into a 42 inch valve at the [Ortif] facility. This has caused them some problems. And they are struggling with it. In particular they need to get hold of a heavy lift vessels as we understand it. If 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 out line to their facility or rather their line coming from our facility to their other facility, to be precise, with depend on when it starts up. At this stage, I am looking to December, but the monsoon may impact it. And all we could 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. Arjun Murti - Goldman Sachs: Yeah, that's great. We've actually got it ramping up over the course of '09, so that sounds like that conservative assumption is probably still good. John O'Connor: Yeah. The other I should obviously add with respect to that is that while it affects our production volumes and forecast, it doesn't affect us economically because the buyers have got a take-or-pay contract with us and so take-a-pay is accumulating as we speak. Arjun Murti - Goldman Sachs: Good point. If I could trouble you for one thing, you've been so helpful so far thank you. Do you have approximate spud dates for 54, Ghana and the BMS block? John O'Connor: I am hopeful that Block 54 will be spudding earlier of the two and that's probably at the beginning of the fourth quarter. I think that Ghana is probably likely to be November. Arjun Murti - Goldman Sachs: And Brazil? John O'Connor: Brazil will spud, according to the operator's latest guidance to us right at the end of September. The drill ship 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. Arjun Murti - Goldman Sachs: That's fantastic. Thank you so much, John. John O'Connor: Sure. Welcome, Arjun.

The next question comes from the line of Mark Gilman representing The Benchmark Company. Please proceed. 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? John O'Connor: That's a good question. That's true. It's a structure. Mark Gilman - The Benchmark Company: Even though Jubilee is stratigraphic? John O'Connor: You're trying to make me draw a comparison between the play types for an offset competitor and ours, they are not exactly the same place, Mark. Mark Gilman - The Benchmark Company: I wouldn't do that. John O'Connor: Okay. I thought you wouldn't. But I just gave a clue, they are not the same play. Mark Gilman - The Benchmark Company: Okay. On BMS-22, industry indications are that the well is going to be drilled up tip toward the crest relative to Carioca, do you concur with that? John O'Connor: Do I concur with the location, I concur with the location because we, the operator and Petrobras have all party to selecting the location. So, yes, we are aligned in terms of choosing the location. Mark Gilman - The Benchmark Company: Okay. Do you have commerciality threshold in mind for 390-P in terms of resource? John O'Connor: 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. Mark Gilman - The Benchmark Company: So does that mean a commerciality threshold, minimum 3 to 5 Ts? John O'Connor: 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 at better and better efficiencies then that really is the moving target and I think at the end of the day when we see what we'll have on block, we will decide what the commerciality requirement is. Mark Gilman - The Benchmark Company: 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's a small piece of our business. It's a 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's got good risk controls, good risk managements, smart people running it and they've had 10n years of a very good profitable track record and it's a small piece of the business, so no intent to change that market. Mark Gilman - The Benchmark Company: Okay. And just, one final one. I noticed that HOVENSA, the SEC utilization rate down in the quarter. Is that a voluntary cut back or was there a 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 cracker at a lower rate. Mark Gilman - The Benchmark Company: Okay, thanks a lot guys.

The next question comes from the line of Erik Mielke representing Merrill Lynch. Please proceed. Erik Mielke - Merrill Lynch: Yeah, hi. I have a couple of questions. First starting with the quarter, then getting back to exploration, and the liquids production in the quarters was somewhat better from Africa than we had expected. Was that just a full quarter of production from the expansion of the Okume Complex or whether some other gains taking place? John O'Connor: Actually, Erik the numbers 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 of production sharing contract. So yes, the Africa production is up on the back of very strong performance, both from Okume Complex and from Ceiba. The matter of fact, in the quarter it's the first time the gross production exceeded $110,000 barrels a day. Erik Mielke - Merrill Lynch: Very good, thanks. And then following up on Australia, you've had two discoveries already and the pre-drilled resource range was a very wide 2 Tcf to 15 Tcf and I gather from what you said earlier that you are not about to know that on this call. But can you give us some idea, 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? John O'Connor: I definitely would expect that we can narrow the range after the four wells have been drilled. There are two things at work. It's a very big block and while John has talked about the location of the next well being 13 or 14 kilometers from Glencoe, it's 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 for wells which will lead to extrapolate in order to get an understanding of the total resource, but, yes, the range will have narrowed. Furthermore, and more importantly, probably, in the fourth quarter we will receive processed 3D seismic over the block and that's 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'll be able to make much more accurate projections we think of the total resource on the block. So it's really towards the end of the year. Erik. Erik Mielke - Merrill Lynch: 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 and Kodiak. Any update on Tubular Bells for you? John O'Connor: No, I mean, at the present time, BP I think are proceeding to evaluate the number of different options, one of which is to look at it in the context of the offset discovery, Kodiak. We'll have views on that, but at the current time, we are working with BP to ensure that we get the SOP on the Tubular Bells leases. Once that's been secured, then we'll proceed from there to work with them to come up with the best solution. Erik Mielke - Merrill Lynch: That's great. That's all from me. Thanks. John O'Connor: Thank you.

(Operator Instructions). The next question comes from the line of Paul Cheng representing Lehman Brothers. Please proceed. Paul Cheng - Lehman Brothers: Hi, thank you. Good Morning, guys.

Good Morning. Paul Cheng - Lehman Brothers: John, any rough estimate what 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. Paul Cheng - Lehman Brothers: Okay. I think this is for O'Connor. John, you talked about EG is doing about 110,000 barrel per day, I suppose that that would suggest that Okume is about in the 70,000, which was higher than what I think the original design expectations. Is the 70,000 barrel per day sustainable at all? John O'Connor: Sorry, just repeat the last part, Paul? Paul Cheng - Lehman Brothers: Yes, the 70,000 barrel per day, that I presume Okume is currently producing, is that sustainable? John O'Connor: It is 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 United States, Okume is relatively under-drilled, and so one can sustain the plateau for a number of years by continuing to drill. Paul Cheng - Lehman Brothers: Okay. John O'Connor: And we expect to see that happen by the way. Paul Cheng - Lehman Brothers: Right. If that's the case then I'm little bit surprised you did not raise the full year production target. I understand the third quarter you are 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 from 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. John O'Connor: Well, I am not sure. Paul Cheng - Lehman Brothers: Am I not being just very conservative or? John O'Connor: 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 will 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 contact. 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 function of the production sharing agreement. So those are the two major impacts on us and we've said earlier that it is likely that Phase 2 of 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. Paul Cheng - Lehman Brothers: So the JDA gas (inaudible) you would expense for the second half of the year similar to the second quarter levels? John O'Connor: Yes, exactly. And of course, second quarter is up on a 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 at gross basis, dry gas. Paul Cheng - Lehman Brothers: Right. But you don't expect that is going to see any additional increase in the second half? John O'Connor: 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. Paul Cheng - Lehman Brothers: And John, is there anything you can share with us about characteristic of the Australian gas in terms of, is there any CO2 or solid gas in that? And you talked the bucket that you drilled, I mean how big is that and what kind of permeability that we are seeing? John O'Connor: The gas samples from the second well have not been back from analysis yes, so I can't speak to that. 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. Paul Cheng - Lehman Brothers: Okay. So that means that the development costs that should be pretty typical. You don't have any complication on that? John O'Connor: Yeah, no complications, but I would not necessary say it was typical because some of the developments in the basin do have 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 typically lower. Paul Cheng - Lehman Brothers: Right. That's what I was referring to that so far that you haven't seen a high CO2 or solid gas complication as yet. And what is the size of the pre-drill target on those buckets? John O'Connor: We have a variety of pre-drill targets and it's meaningless to talk about it in that context Paul quite frankly, but 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. Paul Cheng - Lehman Brothers: Well, then let me ask you in another way. I mean by the end of the year after you finished all the four well program would that provide you sufficient information to decide whether you have enough gas or not? John O'Connor: We hope that will be the case. We certainly hope that will be the case. Paul Cheng - Lehman Brothers: Okay. And I think that this one is for, John Hess. John in the HOVENSA I think that you guys indicated earnings are actually sequentially down but it looked like all the benchmark indicators that we track or anyone track sequentially margin is up. So, is there anything you need about HOVENSA in the second quarter that leads them to be sequentially lower in earnings?

Yeah. You're right to ask the question. On a gross basis, margins were sequentially up, but, on a net basis, there is three factors that took it a lower versus what the benchmarks would have said. One is the timing of some ships and we are on a LIFO basis, though that's the timing issue. Two, with a $140 a barrel crude oil, fuel cost was exceptionally high and it's 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. Paul Cheng - Lehman Brothers: Right. John, when you say timing of the shipping, you said crude or product?

Products. Paul Cheng - Lehman Brothers: Products. Okay. And finally this is for John Rielly. I think you had indicated that the unit cash operating cost now may be $15, $16 for a year, any update about the DD&A, are we still looking at 12.5 or 13.5 or that has been changed also?

Not, we are not changing it. I would guide you towards the high end of the range and it has to do kind of, I am following on with John O'Connor when we talked about our production earlier where we do have some PSC impacts going on, but from a gross standpoint, the EG volumes were higher than our guidance earlier in the year. So, on the EG field, there are just higher DD&A fields. The same with Cromarty, it was producing through the summer. From a portfolio standpoint, Cromarty is higher DD&A field. So just from the mix again, it's coming in as expected with our fields, but from the mix standpoint, I guide you to the high end of the range on the DD&A. Paul Cheng - Lehman Brothers: Very good. Thank you.

Your final question will come as a follow-up from the line of Mark Gilman representing The Benchmark Company. Please proceed. Mark Gilman - The Benchmark Company: If I could for John Rielly, the working capital liquidation you refer 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?

I mean, 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, $270 million. So again with the build up from the winter in the first quarter, and then the depletion and the receivables coming back and we usually get a pick up in the second quarter. And yes, I mean, it's very difficult to forecast where the working capital would typically reverse and then obviously in the fourth quarter, when you are building to LIFO inventory layers and things like that, you will end up having some inventory builds back up in the fourth quarter. Mark Gilman - The Benchmark Company: Okay. And If I could, just one final one for John O'Connor. The PSC effect, John you refer 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. Yeah, I mean, that's exactly what it is. It has to deal with the cost recovery if you are going to call it when the saturation point hit on cost recovery on Ceiba and Okume as well. Mark Gilman - The Benchmark Company: So same both John?

Correct. Again from the PSC standpoint, they both will hit cost saturation in the second half of the year. Mark Gilman - The Benchmark Company: Okay, guys. Thank you.

You are welcome. John O'Connor: Thank you.

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