赫斯 (HES) 2005 Q3 法說會逐字稿

Welcome to the third-quarter 2005 Amerada Hess earnings conference call. At this time all participants are in a listen-only mode. We will be conducting a question-and-answer session towards the end of this conference. (OPERATOR INSTRUCTIONS). I would now like to turn the presentation over to your host for today's call, Mr. Jay Wilson, Vice President Investor Relations.

Good morning, everyone, and thank you for joining us for our third-quarter 2005 conference call. As usual, with me today is John Hess, Chairman and Chief Executive Officer; John O’Connor, President of Worldwide Exploration & Production; and John Rielly, our Senior Vice President and Chief Financial Officer. I'll now turn the call over to John Hess.

Thank you, Jay, and welcome to our third-quarter conference call. I would like to make a few brief comments after which John O’Connor will provide an update of our exploration and production operations; then John Rielly will review the financial results for the quarter.

Turning first to exploration and production. Our third-quarter results benefited from record oil and natural gas prices. Production averaged 312,000 barrels of oil equivalent per day. Hurricane related downtime in the Gulf of Mexico and temporary facilities issues at several nonoperated fields in the North Sea resulted in production being 3% below the year ago quarter. As of today we have restored about 50% of our total Gulf of Mexico production of 51,000 barrels of oil equivalent per day impacted by the hurricanes. We expect to have over 85% of our production restored in November and more than 90% in December.

Despite these short-term production effects, our exploration and production business is progressing favorably. Our development projects are on schedule and on budget, and we will drill some key exploration wildcats over the next two quarters.

Two weeks ago we announced an agreement with Apache Corporation to acquire its 55% working interest in the deepwater section of the West Mediterranean Block 1 concession in Egypt for $413 million. In a separate transaction Apache will acquire, subject to the exercise of preferential rights, Amerada Hess' interest in eight fields located in the Permian Basin in West Texas and New Mexico for $404 million.

This West Med acquisition fits with our strategy to grow our international natural gas business and we believe that our deepwater and sub sea experience will be a significant advantage as we develop the existing gas discoveries. In addition, we see further exploration potential on the block which will enhance our global exploration portfolio.

Also in October our Russian venture, Samara-Nafta, acquired two additional leases in the Volga-Urals region bringing Amerada Hess' investment in Russia to approximately $230 million.

With regard to refining and marketing, our operations performed well during the third quarter. The Hovensa joint venture refinery benefited from a strong margin environment but operated at somewhat reduced throughput as a result of a scheduled turnaround of the number six crude unit. Our marketing activities were negatively impacted by lower margins during the quarter. I will now turn the call over to John O’Connor.

Thanks, John. Good morning, everybody. As with other operators in the Gulf of Mexico, we continue to make progress recovering from the effects of the two storms. Katrina destroyed our shore base at Venice, Louisiana and severely damaged production facilities in the Main Pass/Breton Sounds area which had been producing 4,000 barrels of oil equivalent per day. Hurricane Rita didn't harm our production facilities, but we've been impacted by the damage to downstream gathering and processing infrastructure. We're grateful, however, that none of our people were injured.

Overall the hurricane-related reduction to third-quarter production averaged 9,000 barrels of oil equivalent a day. Hurricane-related production effects will continue into the fourth quarter which may cause as much as an average of 17,000 barrels of oil equivalent per day to be deferred.

The third quarter is typically a period of intense maintenance activity in the North Sea and West of Shetlands. This year was no exception. However, several partner-operated turnarounds took longer than expected, the net effect of which was a deferral of some 5,000 barrels a day for the quarter. In addition, the buyer on BP's Schiehallion facility in July resulted in a deferral of some 4,000 barrels a day of production during the third quarter.

In the fourth quarter a major turnaround is now scheduled at the Schiehallion Field. This, together with a number of short-term facilities issues in the region, will likely lower production by an additional 10,000 barrels of oil equivalent per day.

At the Malaysia-Thailand JDA the buyers of the gas remain in the commissioning phase with their onshore gas plant. While the gas is contracted with take-or-pay agreements, thus keeping us whole economically, we're reducing our production forecast for the fourth quarter by 12,000 barrels of oil equivalent per day.

In consideration of these issues, we've revised our fourth-quarter production forecast to a range of 320,000 to 330,000 barrels of oil equivalent per day.

In addition to production, the hurricanes have impacted rig availability and thus the timing of our Gulf of Mexico wildcat program. Ouachita and Barossa are now scheduled to spud near year-end, and Turtle Lake is now moved to mid 2006. The Pony well, however, remains on schedule for a November spud and will take 100 to 120 days to reach total depth. I'll turn the call over now to John Rielly.

Thanks, John. Hello, everyone. Our earnings release was issued this morning and it appears on our website. In my remarks today I will compare third-quarter 2005 results to the second quarter.

Net income for the third quarter of 2005 was $272 million compared with $299 million in the second quarter. Included in the third quarter 2005 earnings are charges of $31 million related to the repatriation of foreign earnings under the American Jobs Creation Act of 2004 and $14 million related to hurricane activity in the Gulf of Mexico.

Turning to exploration and production, income from exploration and production operations was $235 million in the third quarter of 2005 including the $14 million hurricane-related charge compared with $263 million in the second quarter. Second-quarter earnings included income tax benefits of $11 million reflecting a tax rate reduction in Denmark and a tax settlement in the United Kingdom. Excluding these items E&P earnings were $249 million in the third quarter of 2005 compared with $252 million in the second quarter.

The after tax components of the decrease are as follows -- average crude oil and natural gas selling prices increased by $67 million; crude oil and natural gas sales were lower by $65 million; all other items net to a decrease in earnings of $5 million for an overall decrease in third-quarter adjusted income of $3 million.

The Corporation incurred incremental third-quarter expenses related to the hurricanes of $14 million after income taxes. The pretax amount of this charge is $21 million and is recorded in production expenses in the income statement. It is estimated that future hurricane-related repair costs will be approximately $10 million before income taxes and will be expensed as incurred. As indicated in the press release, lost production amounted to 9,000 barrels of oil equivalent per day which is estimated to have reduced earnings in the third quarter by approximately $25 million.

The effective income tax rate on exploration and production earnings for the first nine months of 2005 was 42%. The full-year 2005 effective income tax rate is expected to be 43 to 45%. The after tax impact of crude oil hedges reduced third-quarter 2005 earnings by $294 million compared with a cost of $231 million in the second quarter. The press release provides details on the portion of our future production that is hedged and the related contract prices. The after tax deferred hedge loss included in accumulated other comprehensive income at September 30, 2005 amounted to $1.7 billion. Of this amount $45 million was realized.

Turning to refining and marketing. Refining and marketing earnings were $125 million in the third quarter of 2005 compared with $98 million in the second quarter. Refining earnings consisting of Hovensa and Port Reading operations, interest income on the PDVSA note and other miscellaneous items were $144 million in the third quarter of 2005 compared with $77 million in the second quarter.

The Corporation's share of Hovensa's income after income taxes of $58 million was $93 million in the third quarter compared with $66 million in the second quarter. Port Reading earnings increased significantly in the third quarter of 2005 compared with the second quarter. After-tax interest income on the PDVSA note amounted to $3 million in both the third and second quarters. The balance of the PDVSA note at September 30th was $212 million and principal and interest payments are current.

Marketing operations principally consisting of retail and energy marketing activities had a loss of $22 million in the third quarter of 2005 compared with income of $14 million in the second quarter. The decrease was primarily due to lower margins reflecting the higher cost of post-hurricane product supply. After-tax trading results amounted to income of $3 million in the third quarter of 2005 compared with income of $7 million in the second quarter.

Turning to corporate. Net corporate expenses amounted to $54 million in the third quarter of 2005. The third-quarter results include an income tax provision of $31 million relating to the repatriation of foreign earnings to the United States under the American Jobs Creation Act of 2004. The Corporation's Board of Directors has now approved repatriation plans at the maximum level permitted under the Act. No further tax provisions for the Act are required.

By the end of the third quarter, $1,655,000,000 was repatriated under the Act. Second-quarter net corporate expenses were $28 million including $7 million after-tax for premiums on bond repurchases. Excluding the tax charge and bond repurchase premiums, net corporate expenses were $23 million in the third quarter of 2005 and $21 million in the second quarter.

Turning to cash flow, net cash prodded by operating activities in the third quarter, including a decrease of $80 million from changes in working capital, was $484 million. The principal use of cash was capital expenditures of $657 million. All other items resulted in a net increase in cash of $15 million. We had a net decrease in cash and short-term investments in the third quarter of $158 million.

At September 30, 2005 we had $760 million of cash and short-term investments. Our available revolving credit capacity was approximately $2.1 billion at quarter end. The Corporation had debt maturities of only $1 million during the remainder of 2005 and $78 million in 2006.

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

(OPERATOR INSTRUCTIONS). Arjun Murti, Goldman Sachs.

Just on some of the production variances. It looks like third quarter, the variance -- you have the hurricanes and the North Sea downtime and in the fourth quarter same thing plus I guess the JDA effect. It seems to us adjusting for that the production in all your other areas seems to be on track and doing fine. But maybe you can provide some comments on base production ex these impacted areas? And then just secondly, if you had any color or comments on the West Med development -- how you're thinking about development costs and timing of start up and that kind of stuff.

Okay, Arjun, let me take that. I think you're right, we don't see any underlying unexpected declines or sub surface issues at all in any of the fields we've talked about. A little bit surprised perhaps at the extended duration of some of the turnarounds in the North Sea, but this is all surface equipment issues which can be obviously put right and we expect to see that. The pacing with which we bring back production in the Gulf of Mexico is also dependent on activities by others.

And so we're being a little bit cautious as to the timing with which we can recover that production. But I think the most important take away is we're not seeing any impacts in the fundamental base production business. I would also, while I'm at it at the same time point to 2006 and remind everybody that we do have new production coming out with that property. That project is in the commissioning phase right now. The wells have been drilled, facilities installed and commissioning is occurring at the safe gas plant. Also of course the contract quantities for the JDA from January 1, 2006 will be 390 million cubic feet a day gross.

As to West Med, obviously we're very pleased to have the opportunity to have the characteristics that that project will bring to our portfolio. Until the transaction is closed, and we expect closing to occur in the first quarter, I'd be remiss to comment on any specific detail on that. But I would point out again for modeling purposes, remember that we have traded current production in the Permian of some 6,000 barrels a day to access that long-term opportunity in West Med.

That's great. Then just to confirm I guess, the hurricane impacts I think we can all see and we appreciate that those are clearly out of your control. Schiechallion we should probably get back next year, the JDA cranks up, we'll lose some Permian production, we'll get Atlantic Cromarty -- that's plus or minus how we should be thinking about '06?

Yes, exactly right.

Thank you.

Doug Terreson, Morgan Stanley.

Good morning, guys; congratulations on solid results. My question has to do with refining and marketing. Specifically in marketing between higher stations and flat gasoline volume per station, it appears that gasoline volumes in Q3 were probably pretty similar to that of Q2 of 2005. And so my question regards monthly trends in demand during the quarter, specifically the trend in consumption on a same-store sales basis during July, August and September if you have it. And any quarter to date information for Q4 2005 would be appreciated as well.

That's a good question. Actually our sales were up for our Company operated stations somewhere between 5 and 10% same-store gallon per site per month. In terms of the c-stores themselves I'd say that was sort of flat because the hurricanes definitely have impacted operations in some areas. So at the end of the day I'd say trending up we get our fair share of the business. When things like this go on we try to stay open later and open earlier and as a consequence of that I'd say they're trending up. There's no major trend there I'd say because of the higher prices.

And John, those are quarter-over-quarter figures?

Yes.

Great, thanks a lot.

Year-to-date is similar to that, by the way.

Great, thanks a lot.

Doug Leggate, Citigroup.

A couple of questions. First, to John Hess, just a similar question on the retail. Can you give us some feel as to how your pricing policy worked during the quarter? Was this negative swing on the marketing earn predominantly you guys holding your prices flat? Is that a fair assumption?

I think the best way to say it is we always try to make supply available at a price that is a lower cost than our competitors. So we try to price slightly below our competitors and have the supply available. And as you know, as the colonial pipeline was prorated and certain areas had supply problems we went to a lot of efforts -- and I'm very proud of all the efforts of all our supply and terminal and marketing people in this -- to keep our stations full while others were running out.

So that's one of the reasons I think for the increase in sales quarter-to-quarter if you will versus last year and the improvement. And yet at the same time we want to make sure we price lower than the competition. So a combination of those factors I think are the reason the revenues were what they were. And I think it's important to know that on an arm's length basis the retail was profitable in the third quarter.

But what happens is our supply operations -- there were times when both hurricane Rita and hurricane Katrina were going on where the Gulf Coast let's say would be $3 and the posting at the racks would be $2.30 a gallon. And there were those periods and that's the reason you see the marketing margin erosion that we show in the third quarter.

Is that bouncing back in the fourth quarter so far, John?

Yes.

Second question is to John Rielly if I may on the balance sheet. John, I just want some clarity on what happens at the end of this year when the hedges essentially roll off significantly to the other comprehensive income line. Can you just tell us what the dynamics of that is going to be and the impact on your equity?

Sure. In the press release it lays out the year-by-year contracts that we still have outstanding. So what happens is each quarter as it's been going in 2005 we are rolling off a significant amount of the hedges, the existing hedges that we had on. So the number of contracts have been going down each quarter and will continue to go down each quarter based on that information you see in the press release.

So what happens with other comprehensive income, all else being the same meaning prices, the accumulated loss that's sitting in comprehensive income will reduce each quarter as the contracts come off. Now prices move around. If prices move up it may mitigate some of that decrease on a quarter, but if prices go down it will cause the accumulated loss to go down quicker. So that's the basic dynamics.

Given the bulk of your hedge you'll roll off at the end of this year, will we see a disproportionate reduction at the end of this year on the other comprehensive income?

You will see -- similar as the after-tax impact that I spoke about earlier in this quarter you're going to see that same type of impact with these kinds of prices coming off in the fourth quarter. Then it all depends on the curve going out to 2012 versus the contracts that we have outstanding which are listed out in that press release. But yes, I mean again, you're going to see a good chunk of it come off in the fourth quarter.

Great. I guess my final question is to John O’Connor. John, there's obviously a lot of interest on the Pony prospect. Would you care to comment on any perhaps ongoing discussions to potentially unitize Pony with -- or your block with the adjacent Knotty Head block?

We always talk to partners and people with shared interests. I'm not personally aware of any substantive discussions going on, but there are always interactions between people operating in the same neighborhood, so to speak. So discussions will occur from time to time. I would think that there will be further discussions obviously depending on the outcome of the well once our Pony well reaches TD. I think that's more the time to look for discussions.

Gentleman, thanks very much indeed.

Bruce Lanni, AG Edwards.

Just a couple quick questions, both on the upstream. I may have missed some comments I think early on when you talked about the Malaysian Thailand production being down 12,000 barrels a day. Could you go over a little bit more detail about that and if it will go into 2006? And then my second question will be on the swap, the Permian basin for Egypt. Can you kind of outline what the capital outlays will be? In either words, Egypt versus the Permian Basin, are you going to be spending more per year both on capital and exploratory expenses? And what will be the impact on per unit operating costs as a result of this?

Okay, Bruce. A fairly comprehensive set of questions there. Let me first of all address the JDA. The actual 20-year contract term for the gas at 390 million cubic feet a day takes effect the 1st of January 2006. In advance of that, in negotiations with the buyers and just to remind everybody on the call, Amerada Hess has 50% equity in the production and Petronas Carigali, the EP arm of Petronas Malaysia, has the other 50%, and the producers are responsible to deliver gas at the rail, at the platform to the buyers. The buyers are responsible and have constructed a pipeline to shore and have constructed a gas plant onshore to treat the gas to make it sales ready.

The buyers have asked for an additional roughly 200 million cubic feet a day for nine months of this year or all told some 73 BCF of gas to be delivered. This is to be delivered under take-or-pay agreements, meaning if they don't take 73 BCF, they pay us and Petronas Carigali for the gas not taken. That is the situation. They started taking gas in February this year. The rates were within the range of the 200 million cubic feet a day. They constructed the gas plant and they started commissioning it in August. This is a three-month commissioning period. So August, September and October are the periods that they may have planned, they the buyers, TTM, have planned to commission their plant.

At the same time and overlying that take-or-pay for this early gas increased to 390 million cubic feet a day with effect from the 1st of September. So our expectation was that that 390, given it was contractual, would continue from the 1st of September through the end of the year. And it was with respect to that that we have reduced our forecast. So what we are saying is perhaps they won't take 390 million cubic feet a day. Right now, they are taking day to day between 100 million cubic feet a day and 250 million cubic feet a day, depending on their commissioning activities.

If the commissioning activities can begin satisfactory at the end of October, then our projection will be too conservative. But at this stage, because we are not party to the plant construction, we do not have insights into the commissioning schedule. We simply respond as producers to the takes the plants ask for. We thought it was prudent to assume that through the fourth quarter. The takes will continue to be the same as those we have experienced in August and September. So that is the story on the JDA.

As I said in my remarks, we are not economically impacted in any event by the production number. So I would just like to point that out. If they don't take at the contract rate, there will be cash payments, etc. As to West Med, certainly -- first of all, in our press release on West Med we pointed out that contractually first gas production from the block will occur in 2009. So there's a period of time to go between now and then. Secondly, until we made the press release, we really did not have access nor the ability to put together a constructive integrated project team. We are in the process of doing that now. So estimations of capital requirements at this stage would certainly not be sanction quality.

I would just say, however, that this is a growth project. We will have 55% equity in it. It is a substantial development, and we will have a significant call on capital probably not noticeabe in 2006, but more likely in 2007, 2008. By comparison, the assets in the Permian have minimal call on capital.

In terms of unit cost for the portfolio, this will be -- certainly it will have the effect of reducing unit cost because of the type of development we will have. I don't think the absence of the small volumes in the Permian will cause a significant reduction, but the addition of 55% of the contract quantities for that gas in West Med after development costs that are likely to be incurred on the operating cost there will certainly be beneficial to unit cost going forward.

Okay, great. So, in other words, what you just said, so the loss of the Permian, net-net your per unit costs are going to be the same up until the time production would start over in Egypt, correct?

With respect to that swap. Of course, there will probably be other portfolio issues that will be affecting the cost too, starting up other production at the end of '06 prior to West Med. But the direct effect of the West Med addition to the portfolio, once it comes onstream, will certainly cause unit cost to come down.

Understand, thank you very much.

Nicole Decker, Bear Stearns.

Good morning, everybody. My question is on unit costs. If I adjust the lifting cost for hurricane related expense I still note on a unit basis a higher cost year-over-year and sequentially. Can you just talk about how much of that is related to inflation pressure and how much perhaps is changes in your production profile?

Sure, Nicole. You did adjust for the production so you take out the $21 million from those production expenses and then you see the absolute costs are down from the second quarter. However, then when you're looking at the unit cost per barrel as compared to the second quarter, we have the volumetric issue in the third quarter being that we had the downtime from the North Sea maintenance and the extended shutdowns in the North Sea as well as the hurricane. So what ends up happening is you just have our fixed costs now being divided over a lower number of barrels, and that is going to drive up the cost of our unit cost per barrel. So it is a bit of an anomaly here in the third quarter.

Now having said that, there is no question we are not immune to the cost pressures in the industry and the cost increases that are coming from the service companies in the industry. So we are having to deal with that just like every other company, but if you're specifically looking at the third quarter, it is a volume issue.

No, that is great. Can you quantify maybe on a percentage basis the inflation rate year-over-year?

It is difficult to do because you could look at individual contracts and you can see day rates on rigs and you can see numbers going up by a substantial amount, but then you have to factor in it is going to be a company by company type analysis of we had locked in some of our rigs for a good portion of time before really we saw the substantial cost inflation. So you try to average it all in, it is difficult, and it would just be a pure guess on what the inflation rate is for Amerada Hess, because you have to compare it from a capital standpoint and from our expense standpoint.

Okay. Do you still have a target range for unit cost going forward?

What we try to do is look at it from a competitive standpoint. So we are going to look at the rest of our competitors, and we want to be in the first quartile as we compare to our competitors. So again, it's this kind of price environment, and with the cost inflation you're seeing, it is very difficult to just set an absolute target. So again, we want to be competitive with our peers.

Okay, great. Thank you.

You're welcome.

Mark Flannery, Credit Suisse First Boston.

I guess this is a question for John O’Connor. It is a follow-up really to Nicki's question there about cost. Could you talk specifically about the Okume Complex, which is entering a fairly high spend phase right now; how much of those costs let's say are already dialed in or controllable, and how much of those costs, that capital cost there, will you feel inflation acting on over the next, say, 12 to 14 months?

Yes, great question. All of the total project capital exposure, somewhere between $300 and $350 million of that has already been committed to the fabrication and other material procurement issues. That is going to continue to step up through next year as the facilities -- construction is finished and they're moved out to West Africa starting in December and through the first quarter with installation to occur in April. The drilling rigs required, we have two rigs contracted to drill the production wells, starting in the fourth quarter of 2006. I would say that they have been contracted, one certainly before the most recent one up in rig rate, so it is very competitive; the other just at the cusp as rates were beginning to move. So I think we are pretty well covered with respect to the inflation pressure we are seeing on costs in the industry. I think as John Hess remarked in his opening, our major projects are still on schedule with respect to time and on budget. So while it is -- overall license fee is a $1 billion development, everything was contracted for and controlled before the run-up in prices.

Maybe I could just have a quick follow-up then. As you look forward into 2006 and you see costs rising, you mentioned rig availability impacting when you're going to drill one or two wells, is there anything at the edge of your portfolio that you are considering not doing because of cost pressures, or at least further deferral of the very marginal discretionary piece of spending?

Great question. First of all, to give you some sense with respect to what John Rielly talked about, the primary driver I think that is going to significantly move the needle upwards in terms of cost exposure is in gen 5 deeper water drilling equipment. That is where we're seeing significant increases. We think we're covered through 2006, and that for the rigs we're starting to continue to use, the contract extensions will probably be negotiated late '06 into '07. And that is when I think we will see a significant increase occurring, depending on what the market is at the time, because they will be renegotiated at market prices.

The equipment we are using now and next year, whether for our own purposes or whether in partnership with public operators, all of this equipment is being secured before the run-up to the $400,000 a day type day rates. So through 2006, I think we're not going to see the significant increases that are going to feed their way through in the industry over the next 18 to 24 months or so. I don't know if that helps.

Yes. No, that answers the question. Thanks a lot.

Paul Sankey, Deutsche Bank.

Given all the moving parts that we've talked about this morning, I wondered if you could give some guidance on fuel volumes for '06?

We'd like to, but we're in the process of finalizing our program capital and our objectives for the year for '06, and we will give guidance in that regard as we normally do in our January fourth-quarter conference call.

But I guess it has changed somewhat, but we're not going to get anything more at this stage?

No, that's standard practice.

Sure. I'm going to ask the traditional demand question. How is, so far in October and post-hurricane, how have you seen through your service stations oil demand holding up?

Oil demand is holding up.

Okay, good. I'll leave it there. Thanks.

Thank you.

Jennifer Rowland, JPMorgan.

I wonder if you could comment a bit on the Port Reading earnings? It looks like those numbers would have been close to 50 million versus last quarter of around 7 million. Just wondered if you could talk about what drove that, if it was anything outside of margins, and then also what the outlook is for that sector going forward?

Sure. I mean, Port Reading did have a strong quarter. It really was marginal related, a clear expansion from the second quarter. You have to remember that the cracks are a little different if you're looking at Port Reading to Hovensa, it really is just a cat cracker unit there at Port Reading. So when you're comparing it to the second-quarter margins, they didn't move as much for Port Reading as they did for Hovensa in the second quarter. And in the third quarter, though, the margins really did expand, and that is what drove the significant increase in earnings.

Okay. Then I think you may have mentioned this earlier; I just missed the comments. On the foreign tax rate, it looks like it went up quarter on quarter to 50% versus last quarter at 43%. I think you had quickly mentioned two items, though, that impacted that. I just wondered if you could just repeat that.

Sure. Again, for overall E&P, we said at the beginning of the year that the rate we expected to be 43 to 45%. And what happens quarter to quarter, it is difficult to absolutely forecast the E&P rate because it is going to move around based on mix. So now in the third quarter, you had the hurricane -- you were just talking on the foreign side, so you had the North Sea maintenance. So you're taking down our UK fields which from an international basis have a lower tax rate than the rest of our production. And basically what happened is, especially with Norway, Norway became a much more significant component of our earnings overseas. And so from a mix standpoint, it just drove the rate up higher. But again, from an overall standpoint, we still are saying it will be 43 to 45%.

Then one last question, can you just remind us what your insurance covers you for, given the damage from the hurricanes?

Sure. Per event, so each hurricane is a per event, we have $400 million of property damage coverage. Each event has a $10 million deductible associated with that. So we were covered from a property damage standpoint. We do not insure for business interruptions in the Gulf of Mexico.

Okay, great. Thank you.

You're welcome.

Paul Cheng, Lehman Brothers.

John, over the past couple of months that we've seen a lot of the large E&P companies start making acquisitions on some smaller E&P names. When we're looking at Hess, you guys have a pretty nice profile there over the next several years. But on the other hand, that your stock has gone up a lot over the past two years. And so one may argue that your currency, while it may not be perfect yet, but it's far more attractive than several years ago.

When you're looking from that aspect, if acquisitions will play a role or a more meaningful role for you over the next two or three years, is there any particular area that you may think that that will be useful for you to quickly free up your present or that you're pretty satisfied with where you are, and you think the better course for you, at least for the next two or three years, would be organic?

Paul, I wouldn't want to speculate in any way. I think the important thing about our company is we've worked very hard the last five years to position the Company to organically create value with our exploration and development program on a global basis, and it's creating a lot of value. So that's the best use of our money and the best use of our focus and we're not going to be distracted from that.

We're just in the execution mode now and in the investment mode to grow our reserves the way we've outlined and grow our production in a very cost-efficient way, and we think that's the best use of our money. You always pay attention to opportunities on the markets, whether it's assets or companies. If things come along over the next several years that are accretive to our strategy, obviously we'll consider it at the time. But right now, we see better opportunities internal in the Company to grow our Company for the future.

I think that this one is for John O’Connor. John, for Egypt I know that you can't really comment too much before you close the deal, but can you comment a bit in terms of what kind of physical regimes that we may be talking about? Do you think that's under a PSC or gas realization? Is it linked to a certain basket or portable, how does that work?

You're right, Paul, it is premature, and our intention is once we have actually closed the deal because we should remind ourselves that this is subject both to EGPC and to ministry approvals, which we will go to seek next month, I would certainly be more comfortable at a fuller disclosure on the moving parts of this once we are party to the agreement, because we are not yet party to it.

Okay. John, you gave a 320,000 to 330,000 barrel yield per day of production guidance for fourth quarter. Can you break it down by the three different regions -- U.S., Europe, and others?

That's pretty much made up, Paul, from the comments I had in my opening remarks. What we have said is 12,000 barrels a day less than we had assumed for the JDA. And again, I would point out this is conservative. It assumes that the experience we have seen thus far in the commissioning of the gas plant will continue. And again, I will make the point if that turns out to be the case, we are not economically disadvantaged because this is gas that is contracted for on a take-or-pay basis.

John, how does the accounting work? You're not going to book the income, right? It's just become a deferred revenue, I presume?

That's correct, Paul.

The cash that you will bring in, but income-wise that you won't book yet.

That's right, until the production is delivered. We don't record the revenue until that time. So economically, we will have the cash, but from a book standpoint, we will not book the income.

What I also talked about, Paul, was the impact of the hurricanes, that in the fourth quarter that might be as much as 17,000 barrels a day average for the quarter. So between Southeast Asia and the Gulf of Mexico, if you add those two together, together with our projection, then the Schiehallion turnaround which is going to be a full-scale turnaround in the North Sea is going to have an impact together with perhaps some minor other operational issues, the total amounting to about 9,000 barrels a day in the North Sea. So that's roughly the breakdown.

Will all of it happen? Who knows. That's why we've given the range for the outcome for the fourth quarter, because there are a lot of moving parts there. Will production come up sooner in the Gulf of Mexico? It's dependent on repair of major gas and oil transportation lines in the offshore. In the JDA, will the commissioning suddenly result in takes of 390 or even greater, because we have the well capacity to deliver above the DCQ. So it's really quite a range, quite frankly, of outcomes likely. At this stage, I would say that we have projections such that we will not be below that.

What's the DD&A -- unit DD&A and unit operating cost for the JDA?

Just repeat the last part.

The unit cash operating cost and DD&A charge for the JDA operation?

When you're looking at it right now, Paul, we've got a start-up operation. And as John was saying, the nominations are moving around.

I'm talking about the ones that went into next year, that when the contract is firm and you start delivering in the full production.

So it's from a DD&A?

Both DD&A and cash operating cost on a per unit basis for the JDA next year.

I would say overall, Paul -- it's a general estimate -- it would be approximately a $7'ish DD&A rate. Again, that's from the acquisition costs associated with that rolling through on the DD&A. From an operations standpoint, it's a fairly low-cost type operation in the $3'ish to $4 range. So you're looking at a $10 to $11 overall unit cost.

And the gas part you realize there is about $4, right, right now per MCF?

What we have with the JDA, again there is a basket calculation to it, and it's clearly north of $3, and that's really what we've been giving out. It does move with the basket, but it's a nice price right now north of $3.

Is there a net effect on that basket? Is it a 12-month lag?

Yes, Paul, that's exactly the point. There is a 12-month lag effect with respect to recalibrating the index. So as we move into 2006, price will be recalibrated, taking kind of the higher commodity prices that we have experienced in 2005. So the price right now is not an indication of current commodity prices. The price next year will be.

Okay, thank you.

Mark Gilman, Benchmark Company.

Good morning, guys. I had a couple specific things if I could. First, John O’Connor, where do we stand on the Shenzi sanction, and can you give me an idea on timing on that? Secondly, you may not want or choose to answer, but let me give it a try anyway. On the West Med gas contract, is that a warranty contract or a reserve dedication contract, and are there take-or-pay features? Thirdly, John Hess, maybe you could comment on Port Reading or Hovensa turnaround activities planned for the fourth quarter and first quarter?

I will answer your second question first and tell you that in January, hopefully, fingers crossed once we've closed the transaction, we will give you full disclosure and all the details, and hopefully by then we will master all of the details. So I'm sorry, you are going to have to be patient until hopefully January. We will talk about that at that time.

With respect to Shenzi, the operator and the nonoperating partners are well along with the development plan. I still look to see Shenzi sanctioned around the turn of the year. Will it be in the fourth quarter this year or first quarter next year? That is really a function of the diligence we are now doing as a partnership with respect to the case for the platform in the wake of the experiences with respect to offshore facilities and their reactions to Rita and Katrina. So we are taking time to go back and recalibrate the engineering calculations in the wake of experience from those two hurricanes, Mark, but I don't think that is going to be an extensive relook.

In terms of turnaround work, nothing major planned for the fourth quarter, Mark, either at the Hovensa joint venture refinery or Port Reading. As you will recall, we had major turnarounds in the cat crackers at both facilities in February and March of this year, so they are in pretty good shape on a run rate going forward.

First quarter, John?

No, in the first quarter of this year.

Next year, what are you looking for?

Next year not so much the first quarter, but next year there will be some work in the Virgin Islands on two of the different crude units.

Thanks.

John Herrlin, Merrill Lynch.

Pretty much everything has been asked, but I will throw some more West Med questions out for Mr. O'Connor. Apache was looking for kind of a $1 billion type development cost. Ballpark, are you still kind of thinking that range, or you'll answer it in January? Then my other question regarding that, is laminated pay an issue at all at West Med or not?

With respect to the capital, while I didn't have our own people as I said earlier give me their views on what the capital will be, we do have an integrated project team at work now. They have visited in country. We do have to be somewhat circumspect, as I said earlier, because of the dependency on securing government approvals. I will say, however, that in relationships and partnerships with Apache in the past, they have got a pretty good pencil. And I think there is no reason not to assume that our work will come close to their cost estimates, whatever they may be. What was the other question, John?

My recollection of West Med was that you were dealing with turbidites that were laminated pay?

I think that the analog I would draw for you and one of the things that fit our pistol in terms of this acquisition is that the subsurface bears somewhat of a resemblance to the subsurface in Equatorial Guinea. As you know, we had a very, very able team of subsurface people, geologists, geophysicists and reservoir engineers, working that area now for a couple of years. We think we have very good insights into how to develop and manage fields of that nature. That gives us confidence that we will be able to bring a lot of expertise to the West Med development.

Great, thank you.

Ted Ivatt (ph), Bear Stearns.

Good morning, everybody. I have a couple questions here. First of all, how will the production declines affect your free cash flow for the fourth quarter?

Obviously, with the production declines, it will lower our cash flow a little bit as the production is reduced, but no significant impact. We can obviously fund all of our CapEx requirements through either existing cash flow in the fourth quarter or the cash we have on hand.

Obviously, another piece of cash flow is the capital expenditures, and some of the deferrals that John O’Connor talked about should work in a supportive fashion to keep the cash flow strong. But obviously, there are moving pieces there in the CapEx for the fourth quarter.

So would it be fair to say you don't see any borrowing needs at all?

Yes, that would be fair to say.

Second, will there be any impact in terms of your reserve replacement numbers or your reserve numbers at the end of the year based on all of this with these delays?

No, absolutely not. This is all aboveground operational issues. If anything, we project that reserve bookings will be the same, and with production somewhat down from where we forecast, reserve life will likely increase as a consequence. So no, absolutely no negative impact on the reserves; no impact on reserves whatsoever.

Okay, thank you.

Paul Tice, Lehman Brothers.

Good morning. I guess my first one is for either John O’Connor or John Hess. Can you just give us an update on Equatorial Guinea, whether we're still on budget and on time? And then any latest color around the restart of Oasis in Libya?

Paul, let me take the first question, and then John Hess will handle the Libya one. We are very, very pleased with the progress we have been making on the construction for the Okume Complex development. Part of that fabrication is being conducted in the Louisiana Gulf Coast and the Texas Gulf Coast. And fortunately, although the yards did receive some storm water, it was not significant, the impact to the fabrication. In fact, we're ahead of schedule. The fabrication in the Gulf Coast, both in the yards of Texas and in Louisiana.

The TLTs are being fabricated at Samsung's yard in South Korea, and there again they are a couple percent ahead of the S-curve with respect to fabrication. We expect completion of those facilities early in February and flowed out and installation in April next year. Rigs have been contracted and will move to West Africa late in the third quarter to commence drilling in the fourth quarter. And as of this moment, essentially all of construction and materials and drilling and tubulars and linepipe, all of these materials have been contracted for. All are on budget with respect to the original budget developed 12 to 15 months ago.

And how much remains to be -- how much had been spent through the end of September, and what is left to go through the end of '06?

The commitment, the spend earned by all of the fabricators and material suppliers through the end of September was about $300 million. I would expect a similar sum to be expended in 2006, but the shift will be towards installation contracts, transportation contracts, and drilling consumables.

In terms of Oasis, our talks with the government of Libya are ongoing. Just to remind everybody, we and our partners, Conoco Philips and Marathon, as 41% owners of Oasis really worked with a national oil company and got a framework for reentry commercially and otherwise as of last December. And since then, it has been in the government's lap to give us approval, and discussions with the government are ongoing.

Okay. Then just a couple of quick ones for John Rielly. I dropped off, so I apologize if you already answered this. Do we currently have a 2006 CapEx estimate?

No, we don't. We will be updating everyone on our January conference call.

And the fourth quarter of this year, do we have a number?

For the fourth quarter, we had previously said our CapEx program will be 2.4 to 2.6 billion. What I can tell you right now is based -- we were speaking earlier that some of our exploration wells in the Gulf are being deferred a bit as a result of the hurricanes. So I would guide you to the lower end of that range, but we still have that range for our forecast.

For next year, you should be free cash flow positive. Any update in terms of your thoughts around the use of that free cash flow between CapEx and buying back debt or shares?

Again, and it's a very fair question, the exact numbers we won't be able to give you an update on until the January call. Having said that, we have been very consistent in this. The first call on our cash is to grow our reserves and invest wisely to do that. The next call will be further debt reduction, and the third call would be current returns to the shareholders in terms of either dividends or share repurchases. But first it is going to be investing organically to grow our reserves.

One last quick one. Hovensa, can you just provide an update in terms of the cash distributions? I think August of this year, there was going to be a decision about a payout or an actual cash distribution.

Yes. In August 2005, there was a cash distribution; on 100% basis was $325 million. So Amerada Hess' share was $162.5 million in the third quarter.

And those are presuming annual; is that right, John?

They happen in February and in August.

Thanks a lot.

Thank you, everybody, for your interest in the call. We look forward to our call in January. Thank you.

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.