Jay Wilson - VP IR John Hess - Chairman and CEO John O’Connor - President, Worldwide Exploration and Production

Doug Terreson – Morgan Stanley Steve Enger - Petrie Parkman & Co. Doug Leggate – Citigroup Paul Sankey – Deutsche Bank Arjun Murti – Goldman Sachs Jennifer Rowland – J.P. Morgan John Herrlin – Merrill Lynch Mark Gilman – Benchmark Company Paul Cheng – Lehman Brothers Nicole Decker – Bear Stearns Luis Olguin – ING Bruce Lanni - A. G. Edwards Robert Kessler – Simmons & Company

Good day, ladies and gentlemen, and welcome to the second quarter of 2006 Hess Corporation earnings conference call. (Operator instructions) I would now like to turn the call over to Mr. Jay Wilson, Vice President, Investor Relations. Please proceed, sir.

Thank you. Good morning, everyone, and thank you for participating in our second quarter earnings conference call. As usual, with me today are John Hess, Chairman and Chief Executive Officer, John O’Connor, President of Worldwide Exploration and Production and John Reilly, 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. As usual, I will make a few brief comments, after which John Reilly will review the financial results for the quarter. Turning to exploration and production, our second quarter results compared to a year ago benefited from strong oil prices offset partially by higher income taxes internationally. Production averaged 354 thousand barrels of oil equivalent per day, which was essentially flat with the second quarter of 2005. For 2006, our current production forecast is 360,000 to 370,000 barrels of oil equivalent per day, which is at the lower end of the range of our original guidance. Price effects from our production sharing contracts and asset sales account for the bulk of this revision. We continue to make excellent progress in advancing our field developments. The Okume complex, Pangkah and Phu Horn developments are all on schedule to commence production in early 2007. Also in the second quarter, the Shenzi Development in the deepwater Gulf of Mexico, where we have a 28% interest, was sanctioned by the operator BHP Billiton. Major contracts have been committed and the project is scheduled to commence production in 2009. In the United Kingdom, production from the Atlantic and Cromarty fields commenced in June and averaged 13 million cubic feet per day for the second quarter. Net production from the fields is currently averaging about 80 million cubic feet per day. Regarding our exploration activities, during the second quarter we announced a discovery at our 100%-owned Pony prospect on Green Canyon block 468, in the deepwater Gulf of Mexico. The [row] was built to a total depth of 32,448 feet and encountered 475 feet of oil, saturated sandstones and Miocene-age reservoirs. After we complete data gathering, we will drill a sidetrack which is intended to evaluate the prospective section, 4,000 feet to the northeast of the discovery well. Also in the deepwater Gulf of Mexico we are drilling our Ouachita and Alsace prospects on Green Canyon 376 and Garden Banks 243, respectively, as well as the Tubular Bells appraisal well on Mississippi Canyon 682. These wells have not yet reached their targeted objectives. With regard to marketing and refining, refining was the major contributor to improved earnings in the second quarter versus the prior year period. The HOVENSA and Port Reading refineries both benefited from the strong margin environment. Similar to least year, retail marketing margins were squeezed during the second quarter as wholesale prices rose more quickly than pump prices. Our current estimate of 2006 capital and exploratory expenditures is $4.1 to $4.3 billion. This level of spending is up from our previous forecast of $4 billion. The increase largely reflects our success at Pony, which has resulted in the addition of a sidetrack well and an appraisal well into our 2006 program, the acquisition of new leases in the deepwater Gulf of Mexico, and accelerated development drilling at the Okume complex. I will now turn the call over to John Reilly.

Thank you, John. Hello everyone. Our earnings release was issued this morning and it appears on our web site. In my remarks today, I will compare second quarter 2006 results to the first quarter. Net income for the second quarter of 2006 was $565 million compared with $695 million in the first quarter. As indicated in the press release, second quarter earnings included a gain of $50 million from the sale of Gulf Coast assets and a charge of $18 million as a result of vacating leased office space. The pre-tax amount of the office charge is included in general and administrative expenses. First quarter earnings included a net gain of $186 million from the sale of certain producing properties in the Permian Basin. Turning to exploration and production, income from exploration and production operations was $501 million in the second quarter of 2006, including the Gulf Coast asset sale and office accrual. Income from exploration and production operations was $706 million in the first quarter of 2006, including the gain from the sale of the Permian assets. Excluding these items, E&P earnings were $469 million in the second quarter of 2006 compared with $520 million in the first quarter. The after-tax components of the decrease are as follows: higher average crude oil selling prices increased earnings by $70 million; lower average natural gas selling prices decreased earnings by $51 million; a higher effective income tax rate, primarily due to Libyan operations, reduced earnings by $85 million. All other items net to an increase in earnings of $15 million, for an overall decrease in second quarter adjusted income of $51 million. As indicated in the press release, production volumes amounted to 354,000 barrels of oil equivalent per day in the second quarter of 2006, compared with 361,000 barrels per day in the first quarter. This decrease primarily reflects seasonally lower natural gas production and maintenance activities in the North Sea. Our E&P operations were underlifted compared with production in the second quarter, resulting in decreased income in the quarter of approximately $20 million. The effective income tax rate for exploration and production earnings in the first half of 2006, excluding special items, was 46%. In July 2006, the United Kingdom enacted an additional 10% supplementary tax on petroleum operations with an effective date of January 1, 2006. As a result, we will record a charge in the third quarter of approximately $105 million. This charge includes a provision of approximately $60 million representing the incremental tax on earnings for the first half of the year and a charge of approximately $45 million to adjust the deferred tax liability in the U.K. Excluding this special charge for the change in U.K. supplementary tax, we expect the E&P effective rate for the year to be in the range of 50% to 53%. The after-tax impact of crude oil hedges reduced second quarter 2006 earnings by $83 million, compared with a cost of $65 million in the first quarter. Outstanding hedges on the remainder of 2006 production amount to 30,000 barrels per day. The press release provides details on future production that is hedged and the related contract prices. The after-tax deferred hedge loss included in accumulated other comprehensive income at June 30, 2006 amounted to $1.7 billion. Turning to marketing and refining, marketing and refining earnings were $121 million in the second quarter of 2006 compared with $49 million in the first quarter. Refining earnings were $107 million in the second quarter of 2006 compared with $21 million in the first quarter. The corporation’s share of HOVENSA’s results after income taxes was income of $63 million in the second quarter of 2006, compared with a loss of $1 million in the first quarter. The improvement in the second quarter was due to higher refining margins and increased utilization of the Fluid Catalytic Cracking Unit. Port Reading earnings amounted to $40 million in the second quarter of 2006 compared with $19 million in the first quarter, reflecting higher margins. The balance of the PDVSA note at June 30 was $182 million, and principal and interest payments are current. Marketing operations had income of $15 million in the second quarter of 2006 compared with income of $12 million in the first quarter. After-tax trading amounted to a loss of $1 million in the second quarter of 2006 compared with income of $16 million in the first quarter. Turning to corporate, net corporate expenses amounted to $29 million in the second quarter of 2006 compared with $23 million in the first quarter. Full-year corporate expenses are expected to be within the range of our earlier guidance of $105 to $115 million. Turning to cash flow, net cash provided by operating activities in the second quarter, including a decrease of $79 million from changes in working capital, was $686 million. The principal use of cash was capital expenditures of $759 million. Proceeds from asset sales and other items amounted to an increase in cash of $55 million, resulting in a net decrease in cash and cash equivalents in the second quarter of $18 million. At June 30, 2006 we had $486 million of cash and cash equivalents. Our available revolving credit capacity was $2.138 billion at quarter end. The corporation’s debt to capitalization ratio at June 30, 2006 was 34.5% compared with 37.6% at the end of 2005. Total debt was $3.774 billion at June 30, 2006 and $3.785 billion at December 31, 2005. In May 2006, the corporation amended its revolving credit facility to increase available capacity to $3 billion and extend the term to May 2011. The corporation has long-term debt maturities of $1 million over the remainder of 2006 and $29 million in 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) Your first question comes from the line of Doug Terreson of Morgan Stanley. Doug Terreson – Morgan Stanley: Yes, congratulations on your record results.

Thank you, Doug. Doug Terreson – Morgan Stanley: You’re welcome. My question is not exploration and production but instead, refining and marketing and specifically in refining. While the results were obviously strong, the capture rate for margins seemed to be a little bit lower than we were expecting and so I wanted to see if you could provide some color as it relates to a few of the factors that might help to explain that issue, meaning were crude oil or refined product differentials or operating costs different than was the case in prior periods and, if so, any quantification that you could provide would be helpful.

Yeah, Doug, fair question and you’re absolutely right. The second quarter was hurt by some unexpected downtime in our HOVENSA joint venture refinery. We had at the beginning of the quarter some downtime because of a problem we had with the cat cracker, which was since corrected. Doug Terreson – Morgan Stanley: Okay.

Then in June, I believe, we did some extra work on one of our crude units to basically defer a coker and block turnaround at the refinery that was planned for this year to divert it in probably the second quarter of next year. So we took some more downtime in June which meant lower crude rates and therefore lower capture rates on those margins you talked about, in essence to run the coker a longer time period before the turnaround next year instead of this year. Doug Terreson – Morgan Stanley: Great. Thanks a lot and congratulations on your record results.

Thank you.

Your next question comes from the line of Steve Enger of Petrie Parkman. Steve Enger - Petrie Parkman & Co.: Good morning.

Morning. Steve Enger - Petrie Parkman & Co.: Just a couple of things on the Gulf, please. On Pony, assuming your first well was, you know, more or less on top of that structure, what do you expect to find in the step out? Do you think you’re going to see a similar amount of net pay? Would you expect you’re going to see some thinning? What can you tell us, obviously based on only a gross interpretation at this point?

I wish I could tell you, Steve, but the purpose of drilling the sidetrack is to determine whether the section remains at the same thickness, whether there’s thinning or indeed, whether there’s thickening as we come off the press. So I’m afraid we’re going to have to wait until we get the [PD] with the sidetrack done so [inaudible]. Steve Enger - Petrie Parkman & Co.: Okay. So it looks like it will be structurally a bit lower, John, and you’ll just have to see on net pay? Is that a fair assessment?

At this stage I would think that that’s right. I mean, we located the first well [inaudible] pretty much but it depends on how much dip we’re going to see on the structure. Steve Enger - Petrie Parkman & Co.: Okay, and just to confirm in the net pay count on that first well, that’s essentially all oil and you did not see any free gas?

Yeah, we did not see any free gas to my knowledge. The samples we’ve taken have been all oil with the MVT. But let me just clarify what you said. What we’re reporting is [settled] hydrocarbons encountered in all of the [inaudible]. Steve Enger - Petrie Parkman & Co.: Okay, and then can you give us an update on kind of drilling schedule for additional Gulf exploration prospects? [Andro Sea], Jack Hays, I think are on your schedule?

Yes, they are and to be honest with you, on the schedule they’re shown as late July, early August. But I think the thing’s moving backwards, depending on the activities of the rigs that are scheduled to drill those locations. So at this stage, I’d push back a month, probably, towards the back end of August. Steve Enger - Petrie Parkman & Co.: Okay.

For both of those. Steve Enger - Petrie Parkman & Co.: Still well within third quarter?

Yeah. Steve Enger - Petrie Parkman & Co.: Okay. Thank you.

Thank you.

Your next question comes from the line of Doug Leggate of Citigroup. Doug Leggate - Citigroup: Thank you. Good morning, guys.

Good morning. Doug Leggate - Citigroup: A couple of things from me, if I may. First of all, I think there’s been a little bit of consternation about your gas realizations in the North Sea this quarter. I’ve got you down in line with the IPE kind of quotes, but can you just confirm what your spot contract price is, or your spot contract volumes rather, versus any long-term contracts you’ve got and your exposure to the spot price moves, in other words.

Sure. In Europe, so it’s in the Europe gas production that you see there, approximately 56% of our production is on the spot market and then the rest are on term contracts. Some of them will flow, really, into oil-type indices but for the most part for the spot market, for overall Europe, it’s just around 56%. Doug Leggate - Citigroup: Okay, but nothing unusual in the realizations?

No. Nothing unusual at all. It’s just market base coming off from the strong first quarter pricing for the second quarter. Doug Leggate - Citigroup: Great. I guess the second thing I have is actually for John O’Connor and it’s on Shenzi. When Repsol obviously acquired this [dig] from BP, they gave some additional color on their view of recoverable reserves and what they thought was going on in the northern flank. Can you just maybe give us your opinion on the same kind of issues and also can you confirm whether or not you were offered any pre emption or not and, if so, why did you choose not to move ahead with a larger stake in Shenzi? John O’Connor: Let me answer the second question first. Both we and BHP Billiton had preferential rights with respect to BP’s interest once they sold it. We evaluated it and we did not think that it necessarily was an outstanding fit for our portfolio and for our trajectory of growth plan. As far as the northern flank is concerned, the intention is to drill a couple of wells on those blocks and I think it would be smart to await the outcome of the drilling without speculating what might be there. Obviously, we’re committing to drilling the wells and we’re optimistic that they will be prospective. Doug Leggate - Citigroup: Okay, John. I’ll leave it there. Thanks. John O’Connor: All right, Doug. Thank you.

Your next question comes from Paul Sankey of Deutsche Bank. Paul Sankey – Deutsche Bank: Hi. Good morning, everyone.

Good morning. Paul Sankey – Deutsche Bank: Just firstly, on that [sort of tighter] range of guidance for production, can we assume that, given that you’ve moved down about 10,000 barrels a day that that was the entirety of the asset sales and the [PFC] effects, and if you could split out the share of those two that would be helpful. Thanks. John O’Connor: Hi, Paul. It’s not entirely due to that. We had some heavier than expected or programmed contributions from maintenance in the North Sea and also in Southeast Asia, frankly. I think there were lingering effects from the hurricane, impact on production which we had assumed would be remedied sooner than was actually the case, and we had also anticipated that Atlantic/Cromarty would likely come on production sooner than it actually did as a result of some bottlenecks that the outside operator experienced in bringing the production facilities up. So I’d say it’s a raft of things. In terms of the production sharing agreements, about 3,000 barrels a day on an annualized basis. In terms of asset sales over and above the Permian, it’s between 2,000 and 3,000 barrels a day on a full-year basis. So the things we reported would get you back to about 370 and then you add on top of that the [inaudible] start-up on Atlantic/Cromarty and have you an expected maintenance piece, [you’re right bang in the middle of the number]. Paul Sankey – Deutsche Bank: Sure, and the implied acceleration in the second half, what do we need to look for there, John? Atlantic/Cromarty is an obvious one. Could you highlight some of the other start-ups, or [drivers]? John O’Connor: Yeah. With respect to Atlantic/Cromarty, you know, they are still bringing the facilities up. We have had three wells on stream. Currently, we’re flowing through as, again, we [see] bottleneck production facilities are [handling] the weight of the far greater volumes of liquids. I think by middle of August we’ll be up to design capacity on Atlantic/Cromarty and hopefully we’ll [inaudible] for the rest of the year. There are no other new field start-ups planned for this year. There is a major downtime, however, if you take into account all the JDA facility. There are 40 days of downtime planned for brownfield activities on the production platforms to get ready for Phase 2 volumes and also to tie in the main pipeline results of Thailand [inaudible] Thailand. Paul Sankey – Deutsche Bank: Great. That’s very helpful. Thanks, and so how do I get my acceleration based on what you just said that, you know, the implied acceleration that you need in the second half to get up to the 360 to 370? John O’Connor: Pretty much what you’re going to see in the second half is restoration of the volumes lost during the maintenance period, particularly in the fourth quarter and full run rates for Atlantic/Cromarty. So I’d say it’s gaps. So for the downtime due to maintenance, which is really quite substantial, and also [inaudible] full run rates at Atlantic/Cromarty. Paul Sankey – Deutsche Bank: That’s very helpful. Thank you very much. John O’Connor: Okay.

Your next question comes from the line of Arjun Murti of Goldman Sachs. Arjun Murti – Goldman Sachs: Thank you. One follow-up question on volumes. Any comments on how [Seba’s] doing? I don’t know if you quite put the volumes out like you used to, and just curious on that one. John O’Connor: Pretty much right on stable plateau, Arjun. Nothing surprising. It’s not down versus plan; it’s right on. It might be at 500 barrels a day, plus or minus. Arjun Murti – Goldman Sachs: Plus or minus? John O’Connor: [Inaudible] Arjun Murti – Goldman Sachs: Plus or minus 30,000 barrels a day net [to you]? John O’Connor: Exactly. Arjun Murti – Goldman Sachs: That’s great, and just to follow up on the Shenzi comment, it looks like you didn’t see the need to counter that price. Any temptation to sell your interest in the [inaudible]? John O’Connor: There were. We had comps on both sides of that issue, Arjun. Arjun Murti – Goldman Sachs: Yep. Yep. In all seriousness, do you see that as an alternative going down the road, not necessarily Shenzi but as you’ve made Pony and some other discoveries, monetizing this or is really the plan, is it going to be, like, if you feel, you know, it’s going to be poor base production for many years into the future, we’re not really looking to sell these assets. John O’Connor: What I would say, Arjun, is that we keep the totality of the portfolio under review at all times. We’re always trying to rebalance it and upgrade it, which is why we had the Gulf Coast sales in the first half of the year and why we constantly look at other sales. Nothing is sacred. Nothing is off the agenda, but for the time being at least, I think that the position in the Gulf of Mexico is one we like very much. We’d certainly like to add to it. But as the portfolio evolves, you know, there’s potential for selling, trading or realigning the interests we have depending on how they turn out. Arjun Murti – Goldman Sachs: That’s helpful. Thank you so much.

Your next question comes from the line of Jennifer Rowland of J.P. Morgan. Jennifer Rowland – J.P. Morgan: Thanks. I was wondering if you could provide more detail on the drilling activities in the Gulf, particularly where things stand on Ouachita versus your target stats. Same with Alsace. And if you could also comment on how the costs of those wells, particularly Ouachita, has risen over the past few months. John O’Connor: We don’t comment on the costs, Jennifer, of drilling wells. We hope they’ll be successful and end up as part of a development. In terms of Ouachita, we are currently drilling in a sidetrack hole at about 23,000 feet. In terms of Alsace, we’re preparing to sidetrack the well at about 7,000 feet and that well is going to go to 24,500 feet. Jennifer Rowland – J.P. Morgan: Do you have any - can you provide us any targets for when you think those wells will be down? John O’Connor: Not really. I would guess somewhere in the vicinity of plus or minus 60 days, [that would be for] both wells. Both are complex wells. Both are subsalt wells and I think we just have to see how they go. Jennifer Rowland – J.P. Morgan: Okay, great, and then just lastly, I noticed the foreign E&P, the G&A expense doubled versus last quarter. Is there something in particular going on there or is that the run rate we should expect going forward?

Jennifer, in my remarks earlier I talked about vacating the office and the charge associated with it. The pre-tax amount of that charge is $30 million and that’s in that international G&A line. Jennifer Rowland – J.P. Morgan: Okay, great. Thank you.

Your next question comes from the line of John Herrlin of Merrill Lynch. John Herrlin – Merrill Lynch: Yeah, pretty much everything has been asked. A couple of quick ones. Services costs in terms of inflation. John, are you seeing moderation in [inaudible] extracts, etc., [inaudible] inflation. John O’Connor: I would characterize it as stabilization at a very high level, quite frankly, versus the rates that we have contracted [inaudible] fortunately. But as we see rates coming up for renewal, we don’t see any moderating operation in price just yet. Say in oil field [inaudible] goods, cement, drilling fluids, probably year over year about a 10% rise in costs there. One thing to bear in mind – this is just a general observation of the industry – one thing to bear in mind, our projects, most of our costs have been contracted in and locked in so we’re not experiencing that type of inflation just yet. Obviously, for new projects going forward is where we’re going to [inaudible] that [picture] cost increase. John Herrlin – Merrill Lynch: Great. An unrelated one, which is on downstream. Refined product sales for resid were down a fair amount versus second quarter last year. Any reason other than price.

Well, the major reason there is quarter to quarter, the Venezuelans may or may not sell to Hess their share of production at HOVENSA and more recently they’ve been selling it on their own instead of selling it to Hess, and that’s just the market decision that they have made. So that’s the major driver and also, with lower gas prices, there is incremental, even though we’re out of the season, some substitution of natural gas sales which we have the benefit of in exchange for lower sales of residual fuel oil to our industrial commercial customers. But the major driver there is not having the resid available from HOVENSA. John Herrlin – Merrill Lynch: Okay. Thanks, John. Last one from me is on upstream volumes. So we should expect more of a backended fourth quarter surge in terms of the [gains]. Is that fair? John O’Connor: I’m not sure I’d want to characterize it as a surge, John. John Herrlin – Merrill Lynch: Well, higher. John O’Connor: I’d expect to see higher volumes in the fourth quarter for sure. John Herrlin – Merrill Lynch: Okay. Super. That’s it for me.

Your next question comes from the line of Mark Gilman of the Benchmark Company. Mark Gilman – Benchmark Company: All right, guys, good morning. I had a couple.

Good morning. Mark Gilman – Benchmark Company: I was wondering whether there has been any success to date in terms of modifying the gas contract on the West [Med]? John O’Connor: We haven’t actually made any initiatives to modify the gas contract, Mark. Mark Gilman – Benchmark Company: I guess I was under the impression that the pricing arrangements were not satisfactory to you, and that you might undertake such initiatives? John O’Connor: I don’t know where that might have emanated from. Obviously, you know, gas pricing contract terms, many discussions with government or government entities would be confidential. Mark Gilman – Benchmark Company: Okay. Let me try another one, if I could. On Pony, have you obtained the data from the [nicks] and Chevron? John O’Connor: Not as of yet. I do know that we are in discussions with respect to confidentiality agreements to facilitate the [inaudible] trade. Mark Gilman – Benchmark Company: So you hope to have it available? John O’Connor: Yeah, I think that’s the intent. Mark Gilman – Benchmark Company: Okay. Are there, in your mind, John, any reservoir energy issues with respect to Pony and do you have in mind any particular in place recovery rate on it? John O’Connor: The answer to both questions is no. I don’t know of any concern, nor do I have any sense of recovery rate. Until we get hole cores and do some more subsurface work, Mark, it’s way premature to be contemplating what recovery rates might apply. Mark Gilman – Benchmark Company: Okay. And if – just one final. Could you give us a little bit of an update on your LNG activities and particularly, apparently, your intent to get involved in building a terminal in Ireland?

Yeah. Hess LNG, as you know Mark, was awarded by the Shannon Development Authority the rights to develop a site in Shannon for an LNG terminal. It’s early days there and we’re starting to do some site work, so it would be premature to put dates out there but it’s obviously an opportunity that we are enthusiastic about. At the same time, we continue to move on with the permitting process at our Fall River site, but we have the PERC certificate to move forward in Massachusetts for another LNG terminal as Hess LNG. Mark Gilman – Benchmark Company: Okay, guys. Thanks very much.

Thank you.

Your next question comes from the line of Paul Cheng of Lehman Brothers. Paul Cheng – Lehman Brothers: Thank you. I have several, hopefully pretty strong questions, I think. Two of them are for John Reilly. John, maybe I’m slow here. Can you go back into your reconciliation on the E&P earnings from one quarter, the first quarter to the second quarter? In there, you indicate that the higher [FS inaudible] price increased earnings by $17 million, but the higher effective tax rate, primarily due to Libya, reduced earnings by 85. So, if those math work, that suggests that Libya is actually a loss in the operation?

No Paul Cheng – Lehman Brothers: Because all your other operation, that the earning, I mean, just trying to imagine that, if [all your] costs increased by $3 year over year [in the] organization, we have no Libya, your earnings go up. Now that you add Libya, now all of sudden all the increase in earning is being [inaudible] all that accurate, more than offset so you have a net loss.

No, actually – Paul Cheng – Lehman Brothers: [Inaudible] understand.

Yeah, we actually had a good bit of discussion, Paul, of how we were going to do this variance here for this quarter and the first thing I have to say is the Libyan operations are profitable. We did lift our production, but basically in line with our production. We’re still underlifted overall because in the first quarter we didn’t lift any barrels at that time. So the Libyan production is profitable. What we have here is, when you’re doing a variance analysis like that and you apply your average effective rate over your overall portfolio, that’s what happens with this volume variance and the way you’re looking at it. So, again, we could have done this variance excluding Libya and then add Libya on as being profitable from that standpoint. So – Paul Cheng – Lehman Brothers: In other words, in the sense that you understate improvement in the [FS] or a price increase to your earning.

Yes. That’s exactly right. In some other ways, in other parts, even volume a little bit and in price, that’s what happens with that. Paul Cheng – Lehman Brothers: Okay. Second question on the, you’re talking about the special item in the third quarter. There’s two components to the tax, one is the retroactive and the other one is the deferred. I understand the deferred is a one time non cash so will be considered as a special item. Why the retroactive for this first six months, which is part of this year’s result, where we can see that as a special item?

It’s all where you want to put it in our analysis, Paul. Why we’re calling it as a special is because we’re going to pick up the whole first half’s increase in the third quarter. Paul Cheng – Lehman Brothers: I understand that, but for the full year that that’s part of the operation.

Exactly. That additional $60 million really, if you were starting from Day 1 and you had the higher tax rate, that would have been right in our effective rate. So it’s just going to be special because we’re taking all the first six months in the third quarter. But if you’re looking at it for a year, you’re right on your analysis. Paul Cheng – Lehman Brothers: Yeah. I can’t imagine how you can treat that as a special item when you’re looking at it from a full-year standpoint.

Sure, from a full year. But in the third quarter, when we report it, it’ll show up, if you want to call it an out of [inaudible] – Paul Cheng – Lehman Brothers: Sure, I understand that but I mean that you’re going to carry it over into the rest of the year.

Exactly. Paul Cheng – Lehman Brothers: Okay. The other question is for John O’Connor. John, with Nigeria talking about the windfall tax and also maybe changing the equity ownership in some of their partner or that they’re [reporting] in the country, what kind of impact that, do you guys have any kind of information you can share? What kind of impact on your operation, maybe? John O’Connor: This is with respect to the Algerian initiative, Paul, is that right? Paul Cheng – Lehman Brothers: That’s correct. Yes, sir. John O’Connor: We obviously have not seen a law promulgated or regulations promulgated so all we know is what we read in the media, the [substance] of which basically is that Sonatrach should have a majority equity in these joint ventures and in our case, in El Gassi, El Agreb, our operation there Sonatrach already has 51% working interest in the block. So at this stage I don’t see a major impact for us in what the minister’s discussing in the media. Paul Cheng – Lehman Brothers: How about the windfall tax, though? They have contacted you guys to discuss what is really what they mean? John O’Connor: It’s difficult to know what they mean, Paul, because we’re just taking up media reports, as I said. We’ve not seen anything formal just yet so at this stage, we’re not asking to see anything. We’re not particularly concerned. I think we’re in good stead in the country and in the joint venture and, you know, the commercial terms, I think, are perfectly satisfactory, both to the government of Algeria and for ourselves and for Sonatrach, our partner. So until we hear something different formally, I think that’s how we view it. Paul Cheng – Lehman Brothers: I see. Okay. The last question is for John Hess. John, [inaudible] has been relooking at, I think, their international refining portfolio and earlier there was talk about wanting to sell their Citgo and [Lyondell] refinery interests and now that seems like they may think about selling it to [inaudible]. Have any kind of discussions in that similar nature occurred between you and them on the same [inaudible]?

No. Paul Cheng – Lehman Brothers: So then it would be continue on the status quo on that?

Yes. It’s a good relationship. We’re happy with the partnership and, from what they tell us, my impression and our impression is that they’re happy with the relationship as well. Paul Cheng – Lehman Brothers: Okay. Very good. Thank you.

Your next question comes from the line of [Nikki] Decker of Bear Stearns. Nicole Decker – Bear Stearns: Good morning. Just coming back to Pony, the estimated resource range is still very wide, 100 to 600. Just wondering if you have encountered any data that would make you lean towards one end of the range or the other? John O’Connor: No, Nikki, surprisingly, I suppose the good news is that the initial well on the block is exactly as expected and therefore has not served to narrow the range. Nothing [going forward] has happened, nor has it, for example, been double the thickness we might have expected, which might have increased the range. The real encouragement is that we found what we hoped to find and we have additional drilling to do which will help to narrow the gap. Nicole Decker – Bear Stearns: So that resource range, though, that would cover your acreage. Is that right? John O’Connor: That’s correct. That is on our acreage. Nicole Decker – Bear Stearns: Well, when do you think you will be able to narrow that range? Is there, you know, is there a milestone that we should look for? John O’Connor: I think that I would not expect to narrow the range with the sidetrack well. I think the planned appraisal well, which will follow on from the sidetrack and which might [inaudible], you know, in the middle of the fourth quarter but probably won’t reach TD until sometime next year, would contribute to narrowing the range. But at this stage, it’s very difficult to say and I would refer you back to some of the questions earlier in the call who talked about Shenzi, for example. You see that Repsol, in purchasing their equity in Shenzi, describes a significant range in the potential reserves of Shenzi. Nicole Decker – Bear Stearns: Okay. John O’Connor: And this is after significant drilling has occurred on the field. Nicole Decker – Bear Stearns: On Ouachita and Alsace, what is your exposure on exploration expense there? John O’Connor: In Alsace we are straight up, 60% equity with [inaudible], 40% equity. On – Ouachita’s more complicated because we farmed out to partners who took a disproportionate equity. Nicole Decker – Bear Stearns: So, I mean, I’m looking for a dollar amount on exploration expense potentially. John O’Connor: Yeah. Why don’t I ask John Reilly to comment on exploration expense, Nikki?

And unfortunately, Nikki, I can’t give you a real great – I know you’re looking for your model purposes, but the point is, I mean, it really does matter one, on timing and on the success of the wells. So at this point, you know, I really can’t give you too much guidance as it relates to exploration expense. Nicole Decker – Bear Stearns: Okay, and just finally on operating costs, you know, I know that you got hit on a unit basis by lower production but could you just comment on the role that inflationary factors are going to play and how you think unit operating costs might look in the remainder of the year?

Sure. At the beginning of the year we had talked about our unit costs being in the range of $17 to $19 and as you can see, in this quarter here we had an $18.94 unit cost and it’s $18.08 for the first six months. I’d guide you to the higher end of this range. We’ve got the higher prices that are out there. We have transportation contracts linked to prices. We have production taxes that are much higher as a result of these prices. We have the maintenance activities that John O’Connor spoke about earlier and we’re going into the maintenance season. So, for the year, we will end up clearly at the high end of that range, that’s at $19. And then obviously, to get there in the third quarter, specifically with the maintenance activities, we’ll be above that $19. And with these high prices and the stabilization of the service costs at this high level that John O’Connor spoke about, you know, that’s where we see it ending up at. Nicole Decker – Bear Stearns: Thanks. That’s helpful.

Your next question comes from the line of Luis Olguin of ING. Luis Olguin - ING: Good morning, gentlemen. I’m trying to get a better feel for your production sharing contracts. Can you give us some color on what percentage of production you would say is under this type of contract and maybe some guidance on how sensitive production is to much higher prices?

As John O’Connor spoke about earlier, we’re seeing about a 3,000 barrel a day impact from the PSC. I think what we generally have from a PSC standpoint is somewhere in the 25ish – I’m looking at the numbers, quick here – about a 25% range of production related to PSC, and so again, in this year, with these higher prices, we’re about 3,000 barrels a day from the beginning of the year. Luis Olguin - ING: Okay, and nothing on, you know, maybe let’s say prices go to $80 a barrel, how much would that change your production?

I mean, as you can see, we’ve had a decent increase from the beginning of the year and we’re not that sensitive. You know, it’s about 3,000 barrels since the beginning of the year so, even if it goes up to $80, that’s not going to be a big number. Luis Olguin - ING: All right. Fair enough. Thank you.

Your next question comes from the line of Bruce Lanni of A. G. Edwards. Bruce Lanni - A. G. Edwards: Yeah, actually my question has been answered regarding the operating costs but I do want to kind of focus back on the Capex and see if you have any other indications that you’re getting inflationary pressures similar to other companies that are going forward, say into 07 and 08?

As John O’Connor mentioned, we clearly are seeing the stabilization at these higher level of the service costs and the ancillary services that go along with the rigs. Right now from our Capex program, like on our production and development purposes, we’re pretty much coming in on our budget that we spoke about at the beginning of the year because we did have those contracts in place, were able to forecast it and so we were able to get some of those contracts in before some of these increases. And again, some of the – I mean, you see on the rigs here, you’re seeing almost close to 50% type increases and so, no question, that will impact in the developments that we have going forward.

But since in the past, you know, we secured for the needs that we had, especially in the deepwater Gulf and also locked in our costs for the Seba and Okume complex, we’re somewhat insulated, as John O’Connor pointed out earlier. Bruce Lanni - A. G. Edwards: And just anecdotally, can you kind of provide some comments or some color on the downstream refining and marketing? Gasoline sales, they were flat year over year. Are you seeing any – are you hearing anything, or seeing anything from your retail outlets about what’s going on with the gasoline sales?

Yeah, our sales, same store sales, on the outside are about, up 2% year on year and on the inside, the C stores that we have, you know, we own and operate 85% of our [site], again, it’s up about 2%. So we’re still getting our fair share of the market. Bruce Lanni - A. G. Edwards: Okay. So you haven’t seen anything indicating that there is a significant slowdown?

Not in our case. Bruce Lanni - A. G. Edwards: Okay. Great. Thank you very much.

Your next question comes from the line of Robert Kessler of Simmons & Company. Robert Kessler – Simmons & Company: Good morning. Wanted to see if I could follow up on Ouachita here again. Just to clarify, I thought you had said earlier in the call that you’re now at around 23,000 feet. I also seem to recall that in May, you were at roughly 20,000 feet with more or less 2,000 feet to go before hitting pay. Are those numbers accurate and can you confirm where you are in the well now relative to target zone? John O’Connor: Yeah, sure, Robert. We’re currently at about 22,700 feet in a sidetrack hole. We have been deeper. We have experienced down hole pressure containment issues. As the pumps [inaudible], we’ve sidetracked to modify the design to go forward again. But we have some drilling ahead of us before we get to the objective section. Robert Kessler – Simmons & Company: Okay. So you’ve not tested any objective zones. John O’Connor: Correct. Robert Kessler – Simmons & Company: Okay.

The final next question will come from the line of Doug Leggate of Citigroup. Doug Leggate – Citigroup: Sorry for the follow up, fellows. The refining and marketing, again. John, John Hess, I wonder if you could give a little bit more color on the lost opportunity costs and perhaps the impact of maintenance on the [inaudible] in this quarter?

As far as the – what happened is early on, from the first quarter, our [SEC] was down, again for unexpected maintenance. That probably was in the range of $5 million and that’s gross, so about $2.5 million, our share, at HOVENSA. Then the coker and the repairs to the crude unit and the work we were doing on the coker itself extended turnaround. I’m thinking again, it’s gross about 20 so we’re looking about 10 coming to us. So something in that range of $12ish to $15 million in the quarter. Doug Leggate – Citigroup: Okay, great. Thanks.

Okay.

Thank you all for attending our call and we look forward to updating you on our progress next fall. Thank you very much.

Ladies and gentlemen, thank you for your participation in today’s conference. This concludes the presentation and you may now disconnect. Have a good day.