赫斯 (HES) 2004 Q3 法說會逐字稿

I'll now like to turn the presentation over to today's host, Jay Wilson, VP of Investor Relations. Please proceed.

Good morning, everyone, and welcome to the third quarter Amerada Hess conference call. With us today are John Hess, Chairman and CEO, John O'Connor, President of Worldwide Exploration and Production, and John Rielly, Senior VP and Chief Financial Officer. I would now like to turn the call over to John Hess.

Thank you, Jay. Good morning and welcome to our third quarter conference call. I would like to make a few brief comments on some of our key exploration and production developments and initiatives. In early August we announced that the government of Equatorial Guinea had approved the development for Northern Block G. The development is moving forward and many of the major contracts are currently being awarded. Amerada Hess, with an 85% working interest, will invest approximately $940 million over the life of the development. First production is expected by the first quarter of 2007 with net production expected to plateau at 40,000 barrels of oil per day.

In the Malasia Thailand Joint Development area, the JDA, we anticipate first production from block A- 18 to occur early next year. We expect net production to reach the full-contracted rate of 160 million cubic feet of natural gas per day by the end of 2005, following completion of the Byers gas separation plant which is being constructed onshoreThailand. Negotiations with Byers regarding additional gas sales are at an advanced stage. With regard to Libya, we and our Oasis Group Partners are in the final statement of negotiations with Libya National Oil Company as to the terms of reentry to our operations in the country. We believe that we will be able to reach a mutually acceptable arrangement in the near future. In conclusion, our base business is performing well. We remain committed to executing our development projects and exploration program, and building a platform to deliver meaningful reserve and volume growth over the next several years. I will now turn the call over to John Rielly, who will provide more details on our financial results after which, we will be happy to take your questions.

Thank you, John. Hello, everyone. Our earnings release was issued this morning and it appears on our web site. I will discuss our usual comparison of third quarter results to the second quarter. Net income was $178 million in the third quarter of 2004, compared with $288 million in the second quarter. Turning to exploration and production, income from exploration and production operations was $155 million in the third quarter of 2004. Exploration and production income in the second quarter was $173 million, excluding a gain on the sale of a nonproducing property in Malaysia and a small charge for severance and leased office space in London. The components of the $18 million decrease in E&P earnings are as follows: Average crude oil selling prices were higher, which increased earnings by $10 million. Crude oil and natural gas sales volumes were lower, which reduced earnings by $19 million. The change in foreign currency exchange rates resulted in a decrease in income of $7 million. All other items net to a decrease of $2 million, for an overall decrease in second quarter adjusted income of $18 million.

The effective income tax rate on exploration and production earnings in the first nine months of 2004 was 46%. Third quarter 2004 production was $323,000 barrels of oil equivalent per day, a decrease of 8% from the second quarter, reflecting anticipated declines in the North Sea due to maintenance. Fourth quarter and full year 2004 production is expected to be approximately 340,000 barrels per day. The after-tax impact of crude oil and U.S. natural gas production hedges in the third quarter of 2004, was an opportunity cost of $180 million compared with a cost of $124 million in the second quarter. The status of our open hedge positions at September 30th was as follows: for the fourth quarter of 2004, we have hedged 70% of our crude oil production; for 2005, we have hedged 60% of our crude oil production. We do not have any open U.S. natural gas hedges.

The average price for WTI -related open hedge positions is $37.12 for the remainder of 2004, and $31.24 in 2005. The average price for Brent -related open hedge positions is $32.14 for the remainder of 2004 and $29.49 in 2005. Approximately 20% of the corporation's crude-oil hedges are WTI-related and the remainder are Brent. In addition to the hedges I just mentioned, we currently have 24,000 barrels per day of Brent-related production hedges from 2006 through 2012. The average price of these hedge positions is $26.20 per barrel. The after-tax deferred hedge loss, included in accumulated-other comprehensive income at September 30th, 2004, amounted to $1.047 billion. Of this amount, $205 million was realized. Approximately $80 million of this realized loss will be recognized in the fourth quarter.

Turning to refining and marketing, refining and marketing earnings were $85 million in the third quarter of 2004, compared with $160 million in the second quarter. The corporation's share of ended income before income taxes was $75 million in the third quarter of 2004, compared with $97 million in the second quarter.

R&M earnings include a non-cash deferred tax provision of $18 million relating to Hovensa third quarter earnings. During the third quarter we received a cash distribution from Hovensa of $88 million. Interest income on the PDVSA note amounted to $6 million in both the third and second quarters. The balance of the PDVSA note at September 30th was $273 million in principle, and interest payments are current.

Port Reading earnings were lower in the third quarter of 2004 compared with the second quarter, reflecting lower -refining margins following a storm -related shut down for 25 days. The results of retail operations decreased in the third quarter of 2004, compared with the second quarter, reflecting lower margins on gasoline. Earnings from energy marketing activities increased slightly in the third quarter. After tax -trading results amounted to income of $11 million in the third quarter of 2004, compared with income of $18 million in the second quarter.

Turning to corporate, net corporate expenses were $23 million in the third quarter of 2004, and $24 million in the second quarter. The third quarter corporate expenses include $7 million after tax from incremental pension and benefit costs.

Turning to cash flow, net cash provided by operating activities in the third quarter including an increase of $372 million from changes in working capital was $817 million. Other net cash receipts amounted to $37 million. The principal uses of cash were as follows: Capital expenditures amounted to $356 million, and we reduced debt by $54 million. We had a net increase in cash and short term investments in the third quarter of $444 million. At September 30th, we had $1.56 billion in cash and short 0term investments. The corporation debt to capitalization ratio at September 30 was 42.2%. This concludes my remarks.

We will be happy to answer any questions. I will now turn the call over to the operator. We are currently looking for the operator at this point to take -- to handle our questions. We are sorry for the delay at this point. We are still looking for the operator to coordinate our questions. We are really ready to answer your questions, we just need to have the operator coordinate the calls. Somehow, we've got a technical difficulty right now. We're still trying to determine what the difficulty is.

Doug Leggate, from Smith Barney, please proceed.

Great, it looks like we're up and running. Gentlemen, I wonder if you could explain about what's happening with the hedging in the quarter? I'm having difficulty understanding how suddenly the hedge realization for the fourth quarter jumped significantly from the guidance you gave us last quarter. And also maybe a little bit of how the dynamic works in Q3; the numbers came in, the realization came in a little bit lower than I was expecting and I suspect that's the reason for it. If also you could give us the break down of the upstream costs, cash depreciation and so on?

I will start with the realizations in the third quarter. I believe the primary issue that at June 30 we had deferred realized hedge losses which relate to contracts that were closed in prior periods. The losses on these closed contracts are deferred for accounting purposes until the underlying barrels that were hedged are produced. In the third quarter we recognized approximately $50 million of after-tax losses associated with these closed contracts and from your question I'm not sure you had that 50 million in your model. As mentioned earlier when I was speaking, earlier in the fourth quarter we will recognize approximately $80 million of after-tax losses for hedge contracts that were closed as of September 30th. So I think that is the primary issue for the third quarter. In addition there is a secondary issue where the sweet /sour differentials widened during the quarter and our WTI crude differential did widen in line with that spread. As for the fourth quarter I think what you were talking about is our WTI-related open hedge positions are up to $37.12 for the fourth quarter and our Brent is $32.14. And what has happened there is, with the rise in crude prices we made some modest adjustments to our hedge volume. You saw our hedge volume at 70% in the third quarter, and in 2005 it's 60%. So, obviously, with the higher prices we pick up a higher hedge-position price. And what we also did is we closed out some lower-priced contracts during the quarter, and added new higher-priced contracts.

Ok, so that's quite a dynamic program, then, not something that sits static despite the fact that oil prices are moving higher.

Dynamic, I don't know if I would use the word dynamic. What it is is, you can leave the hedge programs and be static as you said and watch the rising price all throughout the quarter. What we've done is to make some modest adjustments to close out some of the lower-price contracts and then obviously replace them with higher prices later on in the quarter as the prices move up. So it is just some optimization, if you want to say, of our hedge positions.

Okay. Great.

I think you also asked for our unit costs?

Yeah, the breakdown, please, the depreciation and production costs and so on.

Sure. Our overall unit cost in the quarter was $17.27. For exploration that came to $2.14 per barrel. Lifting was $6.78 per barrel. G&A was $1.04 per barrel. And DD&A was $7.30 per barrel.

That's great. John, thank you very much, indeed.

You're welcome.

Our next question comes from Steve Enger from Petrie Parkman. Please proceed, Mr. Enger.

Yes, a couple things. John, on the after-tax deferred hedge loss, I was trying to write quickly, the numbers, did you say 1.047 billion as of September 30th? And could you just walk through and maybe flesh out a little bit, you said I think a little over 200 million of that is realized to show up in the fourth quarter. Is that right, can you flesh that out a little?

Yes, at September 30th our deferred hedge loss, which is deferred from profit and loss, is recorded in stockholders equity immediately in other comprehensive income, but that number is 1.047 billion. Hopefully you heard that because I heard some static on the line.

Yeah, I heard that, too but I got it.

You got 1.047 billion. Of that amount, just when I was speaking before, there is a portion that relates to closed contracts where effectively we've locked in the loss as of September 30th, on certain contracts that we've closed. That amount is 205 million, and that's included in the 1.047 billion. Of that amount that is closed or locked in, of that 205 million, $80 million of that on an after- tax basis, will be recognized in the fourth quarter.

Okay. So there's another 125 million out there that you know is going to be recognized in subsequent quarters?

In 2005, yes, correct.

And there's another 800 million plus that is still in other comprehensive income, those contracts have not been closed?

Exactly, and that will fluctuate based on where actual prices come in.

I won't ask any more questions, because my understanding can only go down from here on that topic. However on -- I do have another one -- On U.S. gas production trends, John O'Connor, I guess I was looking -- expecting a little bit more uplift from Llano, sir, have you seen the full impact of Llano, sir, or are other things going on in U.S. gas production?

Yes and no. Yes, we have seen the full uplift in Llano. In fact it's been quite stellar in the third quarter. We continue to experience gas production declines from the Llog properties, however. I think the one tends to offset the other.

The only thing I'd add on that, Steve, is Llano is not just a gas field.

Okay.

Right.

But going forward, then, as we look into 2005 we pretty well have seen the positive impact of some of those short-term projects on U.S. gas and what will dominate '05 is natural production declines from those properties. Is that fair?

I wouldn't put it quite like that. I don't see any dominance occurring in terms of domestic production declines. But, remember also, in the third quarter we did have some impact from Hurricane Ivan. In fact , through the third quarter, we lost a shade under 2.5 thousand barrels a day of oil equivalent, A lot of that was gas because the major impact was in the Main Pass/Preston [ph] Sound area which is mainly gas production. And John, final question, on the Shinzee [ph], you guys have been very busy, the same thing you have several penetrations now about how consistent the results have been, how much more you see doing, and then kind of a side issue when you may do an ENC [ph] test and how does the timeline look at this point to you on that project? Okay. Sure. Yeah, we've been very pleased with the appraisal results from Shinzee [ph] as I think we've been commenting on on each of the conference calls. The Shinzee[ph] number three Well, currently has finished probing the straight-hole on the downdip section has been plugged back and sidetracked up dip currently we are setting casing just above the objective sections. I would expect another four, six weeks of work to finish out the number three well following which we will move immediately to drill the Number Four Shinzee [ph] well before the end of the year and that will carry over into the first quarter of next year. We will probably take the Number Four Well down to probe the ENC so that's when we will test that.

Great, do you think the Number Four will do it in terms of being at the stage of finalizing your development plans or is additional drilling planned?

That's a very good question. We have formed with BHP, the operator, BP our partner, an integrated task force. They are currently studying that right now. We should have an update for on that for you the first quarter of next year. One or two wells I think, would be adequate which would give us the confidence to proceed with the project.

Are there a couple of main developments you see right there now?

We haven't seen that because that's the project teams work, quite frankly, and I would imagine after they have gotten together and put their heads together, we will hopefully identify an optimum development.

Okay. Thank.

All right, Steve.

Our next question comes from Mark Flannery from Credit Suisse First boston. Please proceed.

Hi. I'm interested in the downstream. I would like to try to get a little bit more detail on the impacts of weaker retail margins that you cited. Moving from the second to the third quarter of this year, going from 160 to $85 million, I wonder if you could give us some more color on the components there exactly of how we got between those two numbers.

John Rielly will answer that question.

Mark, you saw the, what the -- Hovensa numbers are, effectively are, on the refining margin, our crack was down approximately one dollar between the quarters. And I think you also know that our run rate was down a little bit due to some of the hurricane, the storm season that we had in the third quarter. So it's really just the refining margin on Hovensa and the run rate. And I think if you didn't notice it we also booked an $18 million deferred-tax provision on Hovensa which came in a little bit in the low 20s. Some of our earlier guidance was going to be more around the 15% effective rate, but as Hovensa continues to exceed our forecast as income for the year we've had to increase our tax provision there. On the Port Reading side, the shutdown we had due to a lightning strike that took out a motor at our facility was down for 25 days. The margin there is different from the straight-crackspread margin that had you in Hovensa. We experienced a much bigger decline in our refining margin there which is just a cat cracker type margin there. So Port Reading's earning were off from the second quarter. On the retail side, the margins were down about a penny and a half in the quarter. We also had, some of our business was adversely impacted in Florida due to the storm season that we had there. We also had some storm damage to some of our sites down in Florida which impacted some of our, did impact our retail earnings compared to second to the third quarter. Our energy marketing activities while as we said, up slightly, it is the offseason for energy marketing so there is not significant amount of earnings coming from that.

So if you look now at the retail business, as it's ongoing, would you say that margins are better now than they were in the third quarter or worse? In other words, are we going to see another weak retail contribution?

It really depends, Mark. You appreciate this is just October. There's still November and December to come so I wouldn't want to predict. But obviously, margins have been, I would say about at the same levels as they were in the third quarter so far in October, being squeezed periodically. So, I wouldn't call them on the strong side right now.

Okay. Great. Thanks very much.

Our next question comes from Fred Leuffer from Bear Stearns. Please proceed.

Good morning. It looks like the unit cost was up about one dollar, a little more than a dollar per barrel quarter over quarter. I know you expected some increase but it looks like the big jumps were in lifting costs and DD A. Could you talk us through those, John, and what you expect going forward?

Sure. It was -- just to let you know, the overall unit costs we had in the third quarter is about what we had expected with the decline in our production volumes. Just to talk a little bit, if you want to say on lifting costs, in general, I think, as you know, there's a good part of the lifting costs that are fixed in nature, platforms, helicopter costs, chemicals, thing like that that don't move with production. On an overall basis, let me just talk about product costs, we've been fighting foreign exchange rates in comparison to last year. So our costs are up a good bit over $30 million in a year due to foreign exchange rates. In the quarter itself, what we did have is we are getting more involved in the recommissioning of J. D.A. platform as we are getting closer to production so we picked up some additional recommissioning costs there in J. D.A. There was some additional -- Seminonle maintenance, there was some additional maintenance in the Seminole facility in the third quarter. As far as DD&A, DD&A is up, as you take down in the fields in the North Sea there is a mix issue that comes in just in the third quarter. So from the mix in the fields, our DD&A rate per barrel is up. We also, we also have in the DD&A there were some wells that will be dismantled in the short term that we got new estimates in as operator are putting their budgets together. We picked up some additional costs there, again to be flat with the last quarter, the DD&A will only be a $6 million cost. So, the big thing was, product was down in the quarter, our costs were down but just on a flat unit -cost basis they are up a bit, which was to be expected.

And just some guidance for the fourth quarter next year?

Fred, we are not giving guidance on the fourth quarter. John gave you guidance on the production number. When we get the first quarter, fourth quarter conference call in January, that's when we will be laying out our targets for capital expenditures, production and other items such as that, for 2005.

I think John in the last conference call you said that for '04 you are hoping to get those unit costs down to kind of the 2003 level. Is that still a good direction to be thinking about?

For 2004, we talked about for the whole year of 2004 we were going to be comparable to have 2003 level.

Exactly, John. Are you still thinking like that?

Yes, we are.

Just two other quick questions. What percentage of your production is sour?

I don't have an exact percentage on that. What I would say is in the U.S. we have a generally more sour crude than the benchmark. So we are typically under the benchmark. Historically it used to be in the two-dollar or less range. However, now with some of the lining of the spread of additional crude on the market it has moved up a little bit more than that. But I can't give you an exact percentage of what's sour.

And Fred, it's not just the sour/sweet spread, it's also the heavier crudes get the discount. So some of the west African crudes while very good were impacted with widenning differentials in the third quarter as you're aware.

Lastly, should there be any more Gulf of Mexico storm -related impact on fourth -quarter production?

Right now, Fred, we are down about 500 barrels per day versus our production potential, net to us. We pretty much have restored the levels that I had talked about earlier that affected us in the third quarter and over the next couple of weeks we think we are going to restore the missing 500 barrels a day.

Thank you.

Our next question comes from Jennifer Rowland from JP Morgan. Please proceed.

Thank you. A question for you on exploration expense and CapEx as well. Exploration came in a little bit lighter than we expected. Just wondering if the guidance of 300 to 320 for the year is still what you're targeting. Then also a similar question on CapEx. it looks like you are running a little bit lighter than the target of 1.5 billion, just curious to see if that number is indeed what we should be thinking about for full year.

Yeah, the answer to both questions is yes. The guidance on exploration is still around 320 because the fourth quarter is backend loaded and we are quite actively exploring right now so we do expect to hit that guidance, Jennifer. As to Capex, we are pretty much on track with the number that we've given you earlier.

Okay, great. Thank you.

You're welcome.

Our next question comes from Paul Ting from the UBS Capital Markets. Please proceed.

Good morning. A couple questions. John, about four years ago under the Clinton administration, there was an SPR bid round and I believe you were pretty actively involved. I don't know your level of activity this time around. Can you give us some color as far as to, it doesn't look like to me that you were bidding for two many from SPR release. Is it because the terms were not attractive, or is there adequate crude around that you didn't feel the need to bid? Could you give us the difference between this time and last time?

Yes, the bottom line is we have not been involved in the SPR activities related to the hurricane. When we were involved the last time it was actually more done by Hedco, our joint -venture trading company, and had nothing to do with our joint-venture refinery. And this time around neither one of those entities had any interest in participating.

Okay, but the fact of the matter is it doesn't look like to me the crude appears to be adequate from your perspective otherwise you may have bid it?

No, it has nothing to do with that. As you are aware, our joint-venture refinery, about 70% of the supply comes from Venezuela. And the rest of the supply generally comes from West Africa. And those crude are more competitive than the SPR crude.

Thank you, and the second and last question -- Libya. Can you give us some order of magnitude of what kind of CapEx you would expect over the course of next however time horizon you would choose to talk about?

Yes, I would really like to be helpful. We would like to be helpful in answering that question but it's a work-in-progress and unfortunately it would be premature for me to comment on that. First we have to get our deal commercially agreed to between the second parties and the Libya National Oil Company. And then once that happens, then formalizing budgets and production plans would be appropriate at that time. It's premature to comment right now.

Maybe I can just ask an add -on question on Libya, then. Any interest in SBR , the license, the new license round?

Paul, we are keen on the global stage to find competitive exploration opportunities. But at this stage we have the data in-house. We are evaluating it. We have obviously indicated interest to the Libya authorities. So the answer is, yes, we are interested. Whether we will whether we will actually submit a bid is going to be dependent on the evaluation that the team has underway right now.

OK, thanks a lot.

Our next question comes from Paul Cheng from Lehman Brothers. Please proceed.

Good morning, gentlemen. Several quick questions. I think, John Rielly said earlier that talking about the fourth quarter production 340,000 barrels of oil per day for the fourth quarter. Can you break it down oil and gas between U.S. and international?

Paul, I tell you what. Do you have another question and I will see if I can get that break out?

Also, as of September 30th can you tell me whether you were underlift , overlift, or about balanced?

We did not have any underlift or overlift in the third quarter so we are balanced --

You're balanced.

-- right now at September 30th. And, I'm sorry, go ahead.

And also, interested in Core, I think Core processes about 25% of heavy sour. Do you have a rough breakdown for the remaining 75%? How much is the medium sour and how much is straight oil?

I can give you directional guidance. The medium sour is about 155,000 barrels per day. The heavy for the coker is about 120,000 barrels per day. And then the balance is which crudes are most competitive in the market; it tends to be lower-sulphur crude but sometimes it's medium sour crude as well. Okay.

Paul, for liquids gas for the fourth quarter we are looking similar percentages, 72% on the liquid side, 28% on the gas.

Okay. Very good. John, on the copy, you indicated $7 million of the, I think, on higher pension contribution or benefit expense, going forward what will be a reasonable run rate given all the restructuring that you have done over the past two years?

This is really an incremental non-recurring type cost. I can see a little bit coming in the fourth quarter on the corporate side. Outside of that it really shouldn't affect our run rate. It was a bit unusual, what it was was just settlement accounting required type-of -settlement accounting on our supplemental pension plan with some of the restructuring that we had going on. I wouldn't say you need to bake that into your numbers.

I think in the past we were talking about somewhere in the 15 to 18 million a quarter going forward. Is that still a reasonable proxy?

We've been giving guidance at about $18 million a quarter.

Okay. And I think this is for Mr. O'Connor, John, can you give us, I mean you are talking about Shenzi Well for the appraisal. Other than that what will be some key wells on the exploration front we should watch out for over the next six months?

Right now, Paul, we are in the process of high-grading the prospect inventory and looking at the make up of the program. The key to next year's program will really be the Gulf of Mexico. That's where the impact well are, although the other wells are also value-creating, but the impact will be in the Gulf of Mexico. We have a good slate of wells from which to choose. Which wells actually get drilled, I would also say by the way, that you are going to see some more wildcat drills next year than this year because we have been involved in the Shenzi appraisal this year which means that next year wildcat activity is going to be significantly greater. Why look for four to six wills in the Gulf of Mexico. Specific wells remain to be decided because they are dependent on partner agreements and also on securing drilling rates for them.

Is there any particular region of the Gulf of Mexico that you are going to focus on?

I would say the central Gulf of Mexico and I would say it was the lower Mayocene flat.

And if I could, two final questions, one is a single one for John Rielly, on the marketing expense, sequentially is up about $12 million. What's the reason for the higher marketing expense?

Quarter to quarter it is because of our trader compensation obviously increased and that's about half of the increases due to some of the trader compensation, nine months into the year. Our trading income is $44 million versus $15 million last year. So we had to pick up some additional traders compensation. We, the remainder of the difference was due to retail and the credit card fees are, have been increasing for the second quarter due to the higher pump prices, as well as as I mentioned before we did have some storm damage in Florida with our retail sites.

So that's being treated as marketing expense?

Correct.

I see. Okay. Then finally, I think this may be for John Hess, John, I understand that over the past several years that while you were so happy using the hedging program given your large outlay, and at the time you're not that strong, today you have locked in your net debt position, your net debt to capital is in the low 30% and looks like, at least, for a period of time, high prices may stay strong. Is that a time that we should revisit on your hedging program, perhaps, do you really need to be that aggressive in the hedging given you have more than $1 billion in cash already?

Very fair question, Paul. As you know we hedged in 2004 and 2005 to protect our cash flows, to protect our major developments in a period of major expenditures for our developments. That focus, you can say, has got to be on executing developments. We were more concerned about protecting the balance sheet in this investment period and protecting the down side. As they developments come on and generate new cash flow for us in '06 and beyond, we will be able to assume more commodity price risk and we would expect the amount of hedging activity to be much lower.

So, I mean, is it reasonable to assume if everything goes according to plan whatever beyond 2005, right now you have about 24, 26,000 barrels per day hedge from 2006 to 2012. We should not assume that is going to increase over time?

Yeah. I would not make any assumptions that the amount of hedging would be at a high level. It would be much lower in the future.

Okay. Very good. Thank you.

Our next question comes from Jeff Dietrich from Simmons and Company. Please proceed.

I have two remaining questions. You talked about the lasting impact in the E&P segment from Ivan. Is there any meaningful lasting impact on the retail or refining side of the business? No, there isn't.

It's minor.

Okay. Secondly, could you just give us an update on Algeria activities? Drilling progress during the quarter, and outlook there?

Jeff, we've got two drilling rigs and a couple of workhole units working in Algeria. They continue to execute the program. I would say if you want a qualitative assement of it, that we have been pleased to see some upside versus expectations pre-drill, and we continue to execute the program. Production volumes, either at the end of the second quarter, or the third quarter, hit an all -time record out in the field on a daily basis. The facilities installations are progressing very well. We have a new 18-inch slide in from a new separator station. That line has been filled , and we will start to see the benefit of that going forward. So, I think you are going to see continued drilling activity. Although having said that, we will take one of the rigs out of the field to drill an appraisal and wildcat well on Block 401 C. So the news from Algeria, I am happy to report , is good news.

Thank you.

Our next question comes from Chris Moore, Merrill Lynch. Please proceed.

Thank you. If I could just get a clarification on some of your downstream comments there. You mentioned, with regard to Hovensa, the deferred tax provision, is that included in the 75 million that you reported or is that a separate item? And secondly on the downstream, just the absolute level of trading income in the quarter.

Sure. Chris, the tax provision is not in the 75 million so in that line you see the equity pick up from the Hovensa LLC and then the $18 million is in our tax line. As far as the trading income for the quarter, it was $11 million.

And just one final thing, you've touched on the exploration program, kind of focusing on the Gulf of Mexico, can you give a sense for how you see Equatorial Guinea fitting into the exploration program going forward?

We will be drilling a new wildcat in the north of Block G probably sometime in the next four weeks or so. For 2005, the opportunities in EG are going to have to compete with the opportunities we have elsewhere within a disciplined budget spent on exploration. So at this stage it's difficult to say whether, and to what extent, there will be exploration drilling in EG next year.

Okay. Thank you.

You're welcome.

Our next question comes from Gene Gillespie from Howard Weil. Please proceed.

Good morning. Two questions, one, John O'Connor, how long would you expect the, presuming that Llano has peaked, how long will you expect to hold that peak? First question. Second question is, it was mentioned that you were negotiating additional volumes under the JDA, and one of the industry publications had suggested that as far as that negotiation that you would waive the ticker pre-contract? Is that, can you comment on that?

Well, what I'd say is with respect to the JDA is that commercial negotiations with respect to additional gas sales are well along. In point of fact, we would hope to see that those negotiations conclude to our satisfaction this quarter. So we will watch the space and hopefully have something positive to say about that when the contract is executed. Obviously it's premature to call in what the contents are. As far as Llano is concerned we have been very, very pleased with Llano. It came on pretty much on time, on budget. The volumes have been coming up over the third quarter. They are now well in excess of what we had expected. There is further drilling potential on Llano so in terms of plateauing I would not say we are flat out on the country. I would say there would likely be some upside in Llano depending on drilling next year and the year after.

Next question comes to Mark Gillman from the Benchmark Company. Please proceed.

Guys, good morning, I had a couple thing. First, two questions with respect to Equatorial Guinea. John, when might we expect you to hit fill cost recovery on Ceiba? And also, will North Block G be developed under a separate tax ring fence from Ceiba is the ring fence inclues as I have of both field?

As far as saves cost recovery it's going to depend on where prices are in the future so I really couldn't give you guidance on when we will hit cost recovery there. As far as the overall tax scheme in EG, there is from a corporate standpoint there is one tax return from the individual cost recovery aspect there are separate fields.

Just a to follow up on that for a second, can you make an assumption, I don't know, choose 30, 40, 50, anything you like, what it might look like under one of those scenarios, John.

No, I don't have that, Mark, in front of me to be able to pick those kind of numbers and lay that out. And again, you know, it all depends, and looking at the budget, maybe there's additional drilling opportunities at Ceiba As they compete for capital. We have kind of a dynamic program going on there so it would be very difficult to do that.

Shifting gears just a little bit, without getting into sensitive commercial negotiations, can you talk a little bit about what the pre-existing fiscal terms were in Libya prior to ceasing operations back 15, 20 years ago?

I guess I'll try this one. Back, I think it was 18 years ago but having said that, you know, there was a tax and royalty scheme. Libya has been very clear going forward. It has to comply with their current hydrocarbon laws and provision, and the negotiations that are underway deal with that, Mark, and again it would be premature for us to disclose until the find out come is achieved.

It was not a productivity-sharing contract then?

No.

I thought it was a fixed-margin situation, you're suggesting.

I can't comment on any more than that, Mark, because negotiations are underway, and it's a very sensitive time in those negotiation.

One more if I can, this may come in as completely off the wall, but I will give it a historical. Back when the St. Croix refinery had another side to it, if I recall correctly of almost equivalent capacity, I know that to a certain extent when you put the FCC unit and subsequently the coker in I think the other side of the plant was cannibalized to some degree. Is there any potential for reactivating that perhaps in light of some of the current thinking with respect to the Gulf of Mexico margin picture?

No, it's a fair question. Mark, your memory is good, but in the times since the joint venture, the neat thing about the deal with the Venezuela is about we have really full-capacity utilization of all our upgrading equipment, be it desulfirization, vacuum units. Is the E. C., the fluid cat cracker, the coker, the crude units so we are really full utilization, even our sulphur plant so there really is no spare capacity there now.

So essentially the other half of the plant doesn't exist any more.

No, the other half of the plant is fully utilized. That's my point.

Thanks very much.

Our next question comes from James Moody from Carlson capital. Please proceed. Mr. Mooney, please proceed with your question. Our next question comes from Ted Isaac from Bear Stearns. Please proceed.

Thanks for everything this morning. The question I have is, do you have any guidance on what the your reserve replacement looks like for year end? And the second question in terms of next year's capital program --

Fair questions. Again, it would be premature to comment and give guidance. That kind of guidance we will be giving for our fourth quarter conference call in January when we can give the annual updates and any annual projection that we will be making for 2005.

Okay. Thanks.

Thanks.

Ladies and gentlemen, that closes the question and answer portion of today's call. I will now turn the presentation back over to Jay Wilson for closing remarks.

I would like to thank everybody for joining us for the conference call. I do apologize for the technical problems we experienced, and if there are any further questions please give me a call at (212) 536-8940. Thank you.

Ladies and gentlemen, thank you for your participation in today's conference call. This concludes your presentation. You may now disconnect. Good day.