赫斯 (HES) 2003 Q3 法說會逐字稿

Good day, everyone. Welcome to the Amerada Hess Quarterly Earnings Release Conference Call. This call is being recorded. Today's presentation will be available for rebroadcast at 3:00 p.m. Eastern Time today running through November 6th at midnight. You may access the replay by dialing 1-719-457-0820. Again, that is 1-719-457-0820, or 1-888-203-1112. Enter confirmation code 709765. Once again that is 709765 on your telephone. All media will be in a listen-only mode for the duration of this call. Media questions should be directed to Jay Wilson at 212-536-8940. The Web cast of this call will be available on www.hess.com for 30 days. A transcript of this conference call will be available on the company's Web site for one year.

And at this time, for opening remarks and introductions, I would like to turn the call over to the Vice President of Investor Relations, Mr. Jay Wilson. Please go ahead, sir.

Good afternoon, everyone. Thank you for participating in our earnings conference call for the third quarter of 2003. With me today is John Hess, Chairman Of The Board and Chief Executive Officer, John O'Connor, President, Worldwide Exploration and Production, and John Riley, Vice President and Controller. Certain forward-looking information and other previously undisclosed items maybe discussed during this call.

I would now to 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 on some key operating highlights and provide some guidance on production and capital expenditures for next year. I'll then ask John Riley to review the third quarter financials, before we open it up for questions. We continue to make progress in reshaping our portfolio.

In terms of asset swaps during the third quarter, we completed the exchange of our 25% stake in premier oil for a 23% stake in the Tunisy block Ain Indonesia. In addition, on October 1st, we closed our previously announced transaction with Incana (ph), in which we swapped a 14% stake in the Scott and Telford fields in the UK sector of the North Sea, in exchange for an additional 225% interest, in the Lono field in the Gulf of Mexico, bringing our working interests to 50%.

The development of the Llano field is progressing as planned, and we expect the field to commence production in the middle of next year with production forecast average 16,000 of barrels of oil equivalent per day net in 2005.

Our appraisal work on Northern Block G in Equatorial Guinea continues. We have drilled two wells of the previously announced six well program so far. We plan to drill the remaining four wells over the next several months. We are going to wait until we have all of the drilling results before formulating our final development plan. We are still targeting submission of a plan of development to the government of Equatorial Guinea early next year.

On the exploration front, we are happy to announce that the tubular bells prospect in the deep water of Gulf of Mexico was a discovery. The prospect is located on Mississippi Canyon Block 725 and we have a 20% working interest. The well was drilled in 4,300 feet of water and encountered 190 feet of net oil pay. Further appraisal drilling is planned to determine the extent of the discovery.

However, the G 13-3 well in Equatorial Guinea was a dry hole. We intend to further evaluate this area, where we have previously announced two discoveries. However, we are expensing both the G-13 two well and the G 13-3 well.

The Shenzy appraisal well on green canyon block 653 was spudded on September 22. We have a 28% working interest in this prospect. The well is drilling ahead, and we expect to be in a position to announce results before the end of the year.

Our refining and marketing operations boast strong financial results in the quarter. The Hovensa refinery benefited from strong margins, particularly in August when the U.S. experienced supply problems. While retail marketing margins strengthened in September. I now want to make a few comments regarding our forecasts for production and capital expenditures.

Our best estimate for 2003 production is 369,000 barrels of oil equivalent per day which breaks down as 259,000 barrels a day of liquids and 660 million cubic feet a day of natural gas. For 2004, we are estimating full-year production of about 325,000 barrel oil equivalent per day w

ith a breakdown being 237,000 barrel a day of liquids and 530 million cubic feet a day of natural gas. About 40% of the expected decline in 2004 is related to asset sales and swaps with a balance related to natural field declines partially offset by the start-up of the Llano field in the middle of next year. While we do not make formal production forecasts beyond one year, the changes we have made to our portfolio combined with our current slate of development projects gives us confidence that our production will enter a meaningful growth phase beginning in mid-2005.

We expect the capital expenditures for 2003 to come in at approximately $1.4 billion and we are currently forecasting 2004 spending to be in the range of $1.5 billion. Over 90% of both years' capital expenditures are devoted to exploration and production activities.

In addition, about 60% of both years exploration production budgets are earmarked for development projects. We are implementing significant change to our upstream business. We are transitioning out of mature areas and are shifting focus to longer-lived and more profitable assets.

While this change takes time, we believe we are positioning Amerada Hess for much improved, long-term operating and financial performance.

Now, let me ask John Riley to review the quarterly financial results.

Thank you, John. Hello, everyone. Our earnings release was issued this morning, and it appears on our web site. I will cover our usual comparison of third quarter results to the second quarter and then cover several other items.

Starting with consolidated results of operations and cash flows, net income for the third quarter of 2003 was $146 million compared with $252 million in the second quarter. I will discuss income in more detail in a minute. Turning to cash flow, net cash provided by operating activities in the third quarter after a reduction of 366 million for changes in working capital was $99 million.

The installment payment on the pedasa (ph) note increased cash flow by $30 million. Cash provided from asset sales was $20 million. The principal uses of cash were as follows. Capital expenditures amounted to $307 million.

We reduced debt by $152 million in the quarter and cash dividends paid were $27 million. We now have repaid $500 million of debt in the first nine months of 2003 and our September 30th cash balance was $340 million. The cash will be used for future capital expenditures including field developments and further debt reduction.

Our debt at September 30th was $4,490 billion and our debt to capitalization ratio compared to 54% at the beginning of the year. Moving to exploration and production. Net income from exploration and production activities was $124 million in the third quarter of 2003, compared with income from continuing operations of $88 million in the second quarter.

As discussed in the press release, the third quarter results include income tax benefits of $30 million reflecting the recognition for United States income tax purposes of certain prior year foreign exploration expenses.

The second quarter includes a $23 million charge for severance costs, primarily in the United States and United Kingdom, and costs to reduce our leased office space in London.

Excluding these items, E&P earnings were $94 million in the third quarter of 2003, compared with $111 million in the second quarter. The components of this change on an after-tax basis are as follows.

Our average crude off selling price increased by approximately 55 cents per barrel, including hedging which increased earnings by $9 million.

Average natural gas prices were lower, which reduced earnings by $4 million. Production volumes were lower, which reduced earnings by $20 million. Our exploration expense was lower, which increased earnings by $16 million.

Our effective income tax rate was higher, which reduced earnings by $16 million, and all other items reduced earnings by $2 million for a total decrease in third quarter adjusted income of $17 million as compared to the second quarter.

Now, turning to oil and gas production, which is shown on page 6 of the press release.

In the third quarter of 2003, crude oil and natural gas liquids production was 241,000 barrels per day, a decrease of 7% from the second quarter. Natural gas production in the third quarter was 591 million cubic feet a day, a decrease of 15% from the second quarter. Production of oil and gas on a barrel of oil equivalent basis was 339,000 barrels per day in the third quarter of 2003 compared with 376,000 barrels per day in the second quarter.

Of this decline, approximately 14,000 barrels per day is due to asset sales. The remainder is substantially due to field maintenance. Fourth quarter production is presently estimated to be 340,000 barrels of oil equivalent per day.

The line item production expense was higher in the third quarter of 2003 as compared with the second quarter, reflecting increased maintenance, including work overs. These higher costs, along with lower production volumes, resulted in a increase lifting cost per barrel in the third quarter.

Exploration expense was $59 million in the third quarter and $253 million in the first nine months of 2003. For the full year, our planned exploration spend, as well as expected exploration expense is approximately $350 million.

The effective income tax rate for exploration and production operations in the first nine months of 2003 was approximately 52%. This is a composite rate which includes income taxes in excess of the United States statutory rate in several producing areas, such as the United Kingdom and Norway. It also reflects the income tax benefits of the corporation's hedging results at only the U.S. statutory rate.

In addition, certain expenses in foreign jurisdictions are not deductible for income tax purposes or benefited at rates equal to or below the US statutory rate. Each of these factors increases the corporation's overall exploration production effective income tax rate.

The after-tax impact of crude oil and US natural gas production hedges in the third quarter of 2003 was an opportunity cost of $54 million, or $2.13 per barrel of oil equivalent, compared with a cost of $45 million in the second quarter. The status of our hedges for September 30th was as follows.

For the remainder of 2003 and for the year 2004, we have hedged 60% of our crude oil production. For 2005, we have hedged 15% of our crude oil production. We do not have any U.S. natural gas hedges outstanding.

After-tax deferred hedge losses at September 30th amounted to $109 million. Of this amount, $37 million is realized at September 30th and $72 million is unrealized. The average price for WTI-related open hedge positions is $26.38 in 2003. $24.62 in 2004, and $25.03 in 2005. The average price for Brent related open hedge positions is $24.34 in 2003, $23.74 in 2004 and $23.79 in 2005. Approximately 15% of the corporation's hedges are WTI related and the remainder are Brent.

Now, moving to refining and marketing. Refining and marketing earnings increased to $89 million in the third quarter of 2003, compared with $46 million in the second quarter. The corporation's share of avenges income was $43 million in the third quarter compared with $15 million in the second quarter. R&M earnings include $7 million of interest on the PDVSA (ph) note in the third quarter and $8 million in the second. The balance of the PDVSA note on September 30th was $334 million and principal and interests are current. Retail operations and energy marketing activities were profitable in the third quarter of 2003 but less so in the second quarter.

After-tax trading results amounted to income of $3 million in the third quarter of 2003 compared with the loss of $6 million in the second quarter.

Now, to corporate costs, corporate expenses were slightly lower in the third quarter of 2003 than in the second quarter, but higher in the first nine months of 2003 than the comparable period of 2002. As indicated in the press release, $15 million of after-tax expense from the early repayment of debt was recorded in 2003.

The comparable amount in the first nine months of 2002 was $4 million. I have one last item to mention. I would like to provide an update on the status of the costs associated with the E& P reorganization described in the second quarter conference call.

We currently anticipate that the total costs for severance and the reduction of leased office space in London will amount to approximately $60 million before income taxes. This is a reduction of approximately 20% from earlier estimates.

In the second quarter, we recorded a crude severance and lease cost of $38 million before income taxes. There were no additional expenses reflected in third quarter earnings. We anticipate that the remaining expenses of $22 million before income taxes will be recorded partially in the fourth quarter and the remaining amount will be recorded in the first half of 2004.

The anticipated annual savings from the cost reduction initiatives is $50 million before income taxes. Approximately 60% of this benefit will be reflected in 2004 and the full annual benefit will be realized in 2005 and beyond. This concludes my remarks. John Hess, John O'Connor, Jay Wilson and I will be happy to answer questions.

Thank you. The question and answer session will be conducted electronically. If you would like to ask a question today, please do so by pressing the star, key followed by the digit "1" on your touch-tone telephone. If you are using a speaker phone, please make sure your function is turned off to allow your signal to reach our equipment. Once again please press star, "1" on your phone to ask a question.

We'll go first to Steven Pfeifer with Merrill Lynch.

Hello, guys. Just a few questions. If you would be willing to talk a little bit about at least the prospect size on tubular bells and the price for that?

And then on the upstream unit cost, John if you could may be put a little more cover on the higher lifting cost and what they were previously during the third quarter and lastly, reserve a placement, any initial thoughts on how '03, '04 look and the timing when you might be able to book some things?

And lastly, CAPEX is going up next year. If you could just talk a little bit about the driver of that higher spending. Thanks.

OK Steve, you're going to keep us busy there, but we're happy to answer those questions. I think the first one, we'll have John O'Connor do, to talk about tubular. Then John Riley will talk about unit costs, and I'll be happy to try to give some guidance on reserves and then the last point on CAPEX John?

Hi, Steve. With respect to tubular barrels, I would say the rig is still adjusting the information. As you know, we have two partners there BP operates at 50%. I think the next step in all of this will be putting together a proposition to follow up with raising the well, and that timing will be dependent on the security equipment for that, and pending the results of that appraisal well, I think it will be prudent just to say, you know, we're encouraged. We're pleased, and we await the outcome of the next well.

Steve, I'll discuss the upstream unit costs. In the third quarter, unit costs amounted to approximately $17 per barrel, and they were $16.90 in the second quarter, and the increase is typical in the third quarter for us, and it's due to in the UK the seasonal nature of the gas market over there and since we don't have the nominations for gas, it is a planned shutdown period in the third quarter.

So what you saw happening is even though exploration expense was lower in the quarter and if you just looked at that, you would have expected unit costs to go down, it's the additional work orders and maintenance that really happened in the UK that brought that unit cost really back around to the second quarter.

John, just as a quick follow-up, you can give us detail on the lifting and the DD&A unit costs 2q to 3q?

Sure. In the second quarter, the DD&A per barrel was 778 and it's 766 in the third quarter, and the lifting cost was 560 approximately in the second quarter and 660 in the third.

Great. Thanks.

Sure. On the reserves, obviously, Steve, it's too early to give a firm number. We do that in the January conference call after the Guy McNorton, who audits and certifies our approved reserves works with our engineers to come up with the official number and obviously, they're moving pieces until then, including some of our production sharing agreements some where final prices are at the end of the year.

Having said that, I think the best guidance we could give at this time taking into account the significant asset sells we completed this year, natural field decline, and also that any reserve bookings from areas such as Northern Block G or even potentially some of the Gulf of Mexico exploration prospects that are having exploitation and appraisal drilling done, like tubular bells or Shenzy are included in the numbers.

I think the best guidance is we could give that are the worldwide approved reserves at the end of 2003 will probably be down 5 to 10%, let's say for this year, but I think it's important to know the assumptions that go into the number. It's a discreet point in time.

We're on a trajectory here to really strengthen our reserve base, and we will are going to be disciplined about it, but it will take time to change the reserves so they're less in the mature areas and more in the sustainable areas and we're confident we're on the right track there In terms of CAPEX, John Riley.

And I have to admit, could you just repeat that question, Steve? Was it what our CAPEX levels were?

Yes. If I remember your comments, I think you said 1.4 billion for CAPEX growth re-growing to $1.5 billion in '04.

Correct.

And I just was trying to get a little flavor on what were the incremental projects or the increased activity, how you might be readjusting here.

I think Steve the right answer is it's not a material difference. The exact numbers we'll be able to give more granularity too in January. I would rather hold on that. It isn't a specific project. Obviously, northern block G is in there for x, and I would rather hold out on what x means until we get it more defined. It's a sort of placeholder right now. But there is nothing material in the changes.

You know, the marketing expenditures are still estimated in the $50 million range the rest is for e & p, and there's nothing material in going from the 1.4 billion to the $1.5 billion, and I think the key take-away Steve is, you know, in the year 2000 like approximately 15% to 20% of our capital expenditures were in the developments and now it's in the 60% range, so we really do have the developments captured, and that's going to be the major driver in the CAPEX for the next couple of years.

I think the number in 2000 was 20% of our expenditures, about 137 million for developments, and you know, we're in the 850 million to 900 million range It should be a comparable number next year. So there isn't anything material there in terms of what's driving the number. It's how the numbers add up, and again, it's a preliminary estimate. The definitive one, we'll be more comfortable giving new January.

Great thanks a lot.

Our next question comes from Steve Enger with Petrie Parkman.

Hello guys quite variable results now on the G-13 structure. What do you think you know at this point with three wells? What do you need to know? You can characterize the number three for us relative to the first two successes? Was it different somehow? What's likely to be next there?

Hello, Steve. You caught us at a time when the rig is finishing up the work on the G-13 well, and we understand it's part of business of exploration. We believe that our models have worked. We have a lot of postmortem to do on the well results and the implications for the surrounding area, but we're being sanguine about it, and we're being conservative, appropriately, so, and it's too early to really comment on what the consequences it may have are for the surrounding area, we just got more homework to do, with more data to evaluate and once we got that done we will be in better position to judge whether any potential remains are in the G-13 area.

By seeing the models have worked, John, does that imply you saw the number three well as riskier somehow?

No, I don't think so. I think that we have viewed all along and I think if you take a look at what we have said in the past about the well results, we've been cautious about this for a variety of reasons to do with reservoir, quite frankly. Obviously, we were encouraged to see that we had exhaust and migrated oil into the wells, wells number one and two.

The issue here always was about the quality of the reservoir rock and the producibility of it, which is why we were cautious about expectations for the third well. And, indeed, the third well, I think, has borne out justification for the caution.

And then back up in northern block G, you've got two wells down. You can just characterize the program for us there, the six wells in terms of mix of exploratory versus appraisal, deep targets, shall lower water targets. What does that six-well program look like?

You pretty much described it in your question, quite frankly. It ranges from very shallow to deeper water. There are different objective sections targeted, and so it's a variety. I think that's the best way to characterize it, quite frankly.

Most prospectivety will be like to be encountered in the existing channel sequences that we have already established both good oil and good producibility. That would be the predominant nature of the program, but there will be wildcat drilling also.

OK, can you give us any feel for results from the first two wells, John?

I'd say that we're tracking right along before we'd hope to be from the first two wells, and I think John may have said earlier, John Hess, but at the end of the drilling program, we'll come out and discuss the compos program because really it's an aggregate here.

We put the program together on a risk basis, taking into account the six wells, and again, common sense would dictate that we discuss it when we have all of the results in.

Thanks.

We'll move next to Paul Cheng with Lehman Brothers.

Hello, guys. Quick question. I think the first one would be for John Riley. On the unit operating costs and the detail A, I understand it's going to take some time before we see the improvement, but if we are looking at 2004 as a whole comparing to 2003, what's your best estimate? Do you believe that the unit cost is going to be trend higher, or is it actually going to be lower? The second question will be for John O'Connor.

In Equatorial Guinea, I think the last time that the guidance is that, you believe the CBC will be able to patrol net to you and maybe 25,000 barrels per day. In the recent quarter, you average about 21,000 barrels per day. Is it a new number that we should be assuming going forward, or do you think you have already stabilized and be able to get back up into the previous nightfall.

Finally, for John Riley again, I think I missed when you go through the number, you can just repeat it, what is the hedging realized price for, or average price for '03, '04, and '05 for crude oil, and then your exploration expense assumption for the full year. I think it's $350 million, but we are in pipe fourth quarter at $95 million, and I want to make sure that's the number.

OK, Paul, what I try to answer the first one on unit costs. It's premature to forecast 2004. On the unit cost side, we're still finalizing our budgets. We want to give guidance on the things we felt comfortable giving guidance on for next year, and obviously, by January, we'll be able to put more definition there. I think the real point on unit costs is we are committed to bringing them down.

It will take time. We have done a lot of work the last two years to reshape our portfolio between asset sales, of higher costs projects, developments, lower costs, more profitable projects that will come on, really '05, '06 and also the assets swaps, so there's a lot of noise in the numbers. It's starting to stabilize.

You also saw us giving guidance next year at a lower production number, so I think the real take-away, Paul, is we are on a trajectory year. It is going to take time. I think the most significant change in unit costs will start to occur after mid-'05, assuming the JDA comes on as we have talked about, and then our production really enters in new growth phase.

OK. That's great.

Paul, as far as SEDO is concerned, I think the question is very well put, and I'm happy to say that the reservoir performance is stable. It's not necessarily reflected in the net production numbers because we do have one well, 7,000 barrel a day well, so significant well, which has got mechanical problems, which is off-line, and which we plan to resuscitate and bring back on toward the end of the year. That we also said that we have a lot of work going on in the field.

We have the high rest seismic survey going on, and we are also in the process of installing three new sub-c pumps which will obviously provide a boost to production going forward, and then we have a drilling program for the first half of next year.

So all in all, the question and the answer you gave about can we go back to the levels we predicted, the answer is yes, and I would on present trends feel comfortable about that and see upside once we get more experience about the reservoir. So far, we're very pleased with how stable it is performing.

Paul, I think you asked about the hedge prices. The average price for WTI-related open hedge positions is $26.38 in 2003, $24.62 in 2004 and $25.03 in 2005. The Brent prices for open hedge positions is $24.34 in 2003, $23.74 in 2004 and $23.79 in 2005. And then you did ask what we're estimating exploration expense to be and it is $350 million, and you're right. That is about $95 million in the fourth quarter.

What we do have in the fourth quarter is we've kind of back ended -- actually, I think we front ended and back ended our seismic program so the total seismic is in the 45 to $50 million range, we have $20 million of seismic costs coming in the fourth quarter, so let's say $10 million higher than you would normally be on a straight-line basis.

As John Hess mentioned earlier, we are expensing the g-13 two well and the three well. It turns out the two well was basically expensed in the third quarter.

However, the g-13 three well, the majority of the costs are in the fourth quarter, and along with a Danish commitment, well that we had, so we have two wells that are essentially dry and are going to be expensed that are in the range of $17 to 20 million in the fourth quarter, and that will be hitting our exploration expense, so what it basically means is the normal exploration expense of $7 million in the quarter is what we will be incurring.

Very good. Thank you.

You're welcome.

Next, we'll move to Arjun Murti with Goldman Sachs.

Thank you, just a couple of questions, one on e.g., you mentioned submitting the development plan in early '04. From the time in which the government approves it, should we think about, may be a two-year period before start-up or some different timeframe? Any update on gd-8 start-up? Just an update on how you're thinking about acquisitions. I know you want to be patient. You want to add development projects to your portfolio that improves the reserve life and such things. Any other update to acquisitions? Thank you.

I think John O'Connor may be the first. Repeat, Arjun, the first part you wanted, how long between the time of approval and first oil would be.

You got it.

Thanks, Arjun. I think two years is a reasonable estimate at this stage. For planning purposes, we would contemplate mid-'06 in start of first production, so somewhere in the 24 months, and we'll set ourselves a target to fast track it to the extent it's prudent.

As far as the JDA is concerned, the news there is that we have had significant shipments of line pipe to the both sides of the peninsula Malaysia, both on the east coast and the west coast, so that we're now seeing physical progress on the ground. I think as far as projecting ( inaudible) is concerned, its probably going to be a fairly widish window for some potential for accelerating, depending on whether the gas and the gas plant necessarily coincide, so there is some opportunity to accelerate the schedule, and on the other hand, it may slip back on the pace of which gas plant is constructed.

The timeframe on that schedule?

Probably second through third quarter of '05 at this stage.

OK.

And on the acquisition question, on origin, I'm glad you remembered the comment from last time, and it does accurately depict what we discussed on a prior conference call. You know, our focus is spending the money on these developments. We're in, you know, an important building mode, rebuilding mode of the e & p business, we're delighted we do have the opportunities captured, and we're going to focus on delivering them in a cost effective and timely manner.

So in terms of use of cash, that's a major priority and focusing on that, and that's where the majority of our cash flow is going to go, in addition to which, we made a lot of progress on debt pay down, financial flexibility, along with the development as a major priority.

We paid off over the two years through this quarter $1.15 billion of debt, and that continues to remain a priority for us, so the real take-away is acquisitions are not a primary focus of our company. You know, we will continue to look at selective sales, selective swaps, smallish types of acquisitions that are good fill-ins that are complimentary, but nothing major is contemplated simply because we have captured the opportunities, and right now, we're really focusing on executing around the developments we have, and there really is no need for major acquisitions in this time period, so if we do any, it would only be on the smaller side that's complimentary to the efforts that we're focusing on.

That's very helpful. Thank you.

We'll take our next question from Fred Leuffer with Bear Stearns.

Good morning, guys. I have a bunch of questions. First, what are the dry hole cost at G13?

Second, just if we could go back to the earlier question on lifting costs just to get some clarity, John. You know, given the lower forecast for production next year, should we still be thinking that '04 would be too early to make progress on reducing lifting costs from the $17 a barrel range?

Third, just on tubular bells, John O'Connor what kind of threshold for commerciality do you need, and are there tieback possibilities there? Fourth, John Hess, in your earlier remark, you said 40% of the impact of production for next year is coming from divestitures. Is that divestitures to date or to date plus planned for next year?

OK, let's go through these one by one. First the dry hole on g-13, and if John Riley has that, that would be terrific, and the lifting costs and the comment I said still holds on that, but directionally, don't look for major changes in the lifting cost even though we're going to continue to directionally drive them down. It's a function of two things.

It's the cost side and the production side, and there isn't a material change in production until the second half of '05, so the material changes in lifting costs really unit lifting costs really happen post mid-05, and that's the most guidance we'd be willing to give at this point. John Riley, why don't you hit the g-13 point?

For g-13, the expense that we'll be having in the fourth quarter as it relates to the g-13 three well is approximately $9 million.

Now, in the third quarter, though, we did expense the g-13 two well, which was approximately $13 million.

If I may, John O'Connor is going to hit the tubular bells point the best he can, Fred, but the 40% from sales in terms of how it impacts production, you know, encompasses all the activities to date. We don't foresee anything major in the fourth quarter as of right now, so as a consequence, you know, it's the full quarter impact of steps taken like Scott, let's say, and other steps we've taken, but nothing in addition to. It's, you know, activities to date, if you will, or actions taken to date on the projections made there.

OK

Well then on tubular bells, like any other drilling in the Gulf of Mexico or anywhere else, for that matter I'm always cautious of the vagaries that much of mother nature will throw at us, and I'm conscious not to give hostages to fortune, but I would say as far as the prospect is concerned, the outcome of this stage is in the pre-drill estimate. We're encouraged and I think at this stage, it holds out the opportunity to be a commercial development, and so far, so good.

Are there tieback possibilities there?

There are tieback possibilities, yes.

OK and let me just have one last one, if I may. Just given the timeframe for submitting a development plan at eg, is it at all possible that you might be able to book some reserves this year?

No definitely not. We have a rigorous policy of not booking reserves until we have a project sanctioned, and I don't see that we will have all the information optimized, synthesized before the first quarter, so I think this is going to be a first quarter sanctions, so you know, the reserves are there. It's just a question of timing and booking them and take them next year when we get them.

Thank you.

Next is Paul Ting with UBS.

Good afternoon, gentlemen. I have two questions One on upstream and the other on downstream. Let me get back to Fred's question about the production guidance of 2004 Relative to 2003 from 369,000 to 325,000 barrels per day. Is there any way you can give us some feel as far as to whether it's going to be a fairly smooth year next year, or will it be pretty lumpy front end or by second half loaded in terms of production declined, if you will?

And 2005 production, as you mentioned, you should expect to see some resumption of growth in '05 and beyond any revision to your target in terms of longer terms production growth rate? That's the upstream.

On the downstream, CAPEX at 1.5 billion total guidance for next year and 90% EMT, and some other companies who have reported have indicated some major capital expenditure in the next couple of years relative to downstream, in part because of the changes in some of the environmental regulations. Are you looking at some possible large downstream increase in '05 and beyond? Can you characterize that, for us please?

OK. I think on the production point, John O'Connor, will be able to talk about, you know, is it getting more stable? Is there anything lumpy in it? I think that was the intent of your question Wasn't it, Paul?

Yes.

Paul basically to reiterate what we said on the last call, the exit rate is 330 and 340 at the end of the year. It's not that far a drift from the average of 325. And basically the only new production that we see of any significance is the start-up of Lionel in the Gulf of Mexico so basically, we will come out of the end of year ahead of the 325, but you know, not significantly so.

We'll see some gentle lines in the first quarter and beginning of may, we will see Lionel kick in and carry us through the rest of the year. So I would characterize that we will be fairly stable next year. We will have the usual seasonality associated with summer downtimes in the North sea, compensated by a pickup in the fourth quarter as the natural gas market in Northwest Europe kicks in, characterize it as being flat through the four quarters.

On CapEx, Paul --.

Before we get to the down stream fall, '05 and beyond kind of any growth or relations to that?

No, we're not forecasting that far ahead. We're trying to give guidance that we think is prudent at this time. Obviously, with the JDA coming on, we're trying to give you the feel that we're on the right trajectory.

Downstream CAPEX, please?

The downstream CAPEX basically are in the $15 million range in '04. It's predominantly for retail. No major expenditures outside of that. You know, in terms of the low sulfur gasoline, low sulfur diesel initiatives, the major impact is going to be on holenza (ph), about $450 million starting next year spread out over several years.

The good news is, you know, that is self-funding between their own cash flow, the current cash that they have on hand to date, and you know, plenty of capacity of debt. In fact, their projections are and remember with 50% ours, it's off our balance sheet, it's a separate investment, they don't anticipate any funding needs in terms of meeting those requirements in terms of going to the market per se. It can be self-funding. No major impact on Hovensa, and obviously, that's good news and even though they will have the spending need.

In terms of the our US. operations, in terms of materiality, whether it's Fort ridding, terminals, gas stations, there aren't major expenditures required there, so no major impact on our spending going forward as Amerada Hess for the reasons I mentioned and the number of $50 million a year for the downstream business, basically for retail is a pretty good assumption going forward.

OK, great. Thanks a lot, John. I appreciate it.

Thank you.

Moving on, we'll go next to Jay Saunders with Deutsche Bank.

A couple of questions. On the downstream, are you guys going to be able to supply gasoline in New York and Connecticut with the MTB and still remain in compliance with your emission baseline in St. Croix? The second question is on the timing of the remaining four wells in e.g., how long has it taken to drill each of those wells? What's the pattern? I assume it's one after the other.

OK, on the gasoline, to the best of my knowledge, you know, with MTB going out in New York and Connecticut, really, the month of November, we're changing all of our inventory out, all the plans have been made. We foresee no major problems.

On the Hovensa side, no problems there, and on the U.S. side, no problems there. We're prepared for the change in regulations and don't see any major problems.

As far as Block G is concerned, we're very pleased. We Mobilized to back operate in the country, and we're very pleased with the performance of that rig, the drilling performance, so in point of fact, the wells are actually going faster than program, say average to release 25 days or thereabouts.

OK.

In terms of the end of the program, you know, you're probably looking at the end of January, thereabouts.

Great and then submission of a plan shortly thereafter?

Well, I mean, that's the idea. That's what we're headed toward. There's been a lot of reiteration in trying to parallel processing of the data from the wells, the optimization of the surface facilities and formal documentation of submission of the application, so there's a lot of work going on. A lot of people are working around the clock on this. It has all of our attention.

Right, and the government is apprised of everything.

They're working with us. They're very helpful. The government partners, National Oil Company, they're in our offices. We're in theirs. We're in frequent meetings. That's part of the plan is to make sure they're fully aware of everything that's happening.

Thanks.

Next we'll move to Mark Flannery with CS First Boston.

I wonder if John O'Connor could run us through the rough next series of announcements in drilling. You mentioned one on the call, let's look at the fourth quarter and first quarter, what do we need to be watching out for from that program?

Good question. I don't have a script for that. I think that the next announcement, hopefully, will be the shensy appraisal well. Again, we're very pleased with the drilling performance of the operator there. They have just set casing above the target horizon, which is really a fast drilling to that point, so I would say 30 days or so from now we should have an announcement on the appraisal well depending on operating --operator partner timing.

As far as looking out into '04, we have a really high potential prospect inventory, much of it in the Gulf of Mexico. We're looking to be drilling, you know, I'd say in the order of three to five wells a year for a number of years, so if you take it at four impact prospects next year, the time will be one a quarter frankly, and hopefully, we'll see a heartbeat every 90 days if things work out the way they're planned.

Great. Thank you.

You're welcome.

And we'll go next to Mark Gilman with First Albany Corporation.

Good afternoon. Could I go back to the G-13 for a sec. Refresh my memory as to whether you expensed the discovery well? Perhaps, you could talk a little bit more about what didn't work in the number three. Was it type? Were there shows? Some color would be appreciated.

First of all, the G1 was expensed, so, again, back to my earlier remarks with respect to our overall assessment of the G13 area, I think we have been cautious, but prudent around it so that the actual discovery well was expensed. was not capitalized, and the reason for that was while there was a significant oil column, we were not over enthused by the quality of the rock, and the issue has been to construct a reservoir model which took the sourcing and the migration plan and put it into a viable reservoir rock in that setting, in that water depth. To do that, we looked at a canyon type feature or a relative low by comparison with the number one and the number two well.

Indeed, we did see permeability and porosity in there but no trapping. For now the issue is, how do you take the combination of what we have seen, the need to be on a high existing from a low, and whether you can maintain reservoir type rock on the high, which was the disappointment of the first two wells.

OK. If I could just a couple others. For John Riley, the impact of Premier and the transaction on balance sheet income statement and what have you in the quarter?

Hello, Mark. Premier, it wasn't really a significant in our P&L. In the balance sheet, if you noticed in my opening comments where we had cash received from asset sales, it turns out we did receive net cash in the transaction from Premier because of the effective date of that transaction was back in 2002.

It got tied in with Petranosen (ph) and get out, and the deal got delayed so effectively all of that production from 2002 to our date was in our account and so we actually picked up some cash from that. But from the P&L standpoint, it's under $10 million, nothing material. And that's a combination of the gain from the equity pickup of the earnings and the actual transaction.

And the reserve impact of it?

The reserve impact, from Latuna (ph), itself, we pick up about 25 million barrels which will come in this year when we announce our reserves. Now, from the premier standpoint, we had -- if you want to say the base Amerada Hess reserves, we would have had equity investee reserves, which was greater than that, 60 million barrels, but encumbered by any debt that Premier had. We pick up 25 million barrels in our base reserves.

OK. If I could, John, the tax rate, the 52% that you quoted, does that include the $30 million benefit?

No. It does not. No. We're trying to make that of a more recurring nature. But the 52% is our effective rate without the unusual tax benefit.

OK. I mean, I don't know what gave rise to that, but did you do some restructuring or reorganization that going forward could lead to a repeat of this type of thing and a lower effective tax rate on overseas exploratory expenditure?

There's no specific, say, restructuring that was done to bring this benefit into play right now in the third quarter. You wouldn't call this recurring. Would there be additional exploration expenses overseas that upon completion, let's say, in an area and ultimately taking those deductions and bringing them into the US tax return that could show up in the future, it's not something I think anybody should count on, and that's why we disclosed it as such as a non recurring nature.

You wouldn't alter the expectations for the future as upstream tax rate as a result of what led to this $30 million gain?

No, I would not.

OK. Thanks.

you're welcome.

Our last question comes from David Miller with J.P. Morgan.

I guess I have a question on John Hess's comment about further debt pay down as we go forward here. When I look at kind of the cash flow the company generated this year, the run rate on an annual basis is about a $1.5 billion eek toll next year's CAPEX, and I would imagine prices will be down from the run rate we had this year of $31 oil, $6 US gas and the dividend payment. The question is, on my numbers, it looks like you're negative free cash as we head through '04, so how are we going to achieve further debt pay down.

Well, David, we made a lot of progress to improve our financial flexibility. That continues to be a priority, but we have to balance that priority with making sure we've secured the funds for the developments we have, and it's really creating a balance there, you know, $1.15 billion of debt has been paid down since the Triton acquisition, and we will continue to look for ways to continue to strengthen our financial position, and yet still make sure we meet the requirements for development expenditures.

We're going to be very disciplined and with regard to our expenditures, but it's a question of keeping the balance right in terms of, you know, funding those developments and looking for ways to strengthen our financial flexibility at the same time.

But right here, if you have to spend a $1.5 billion, it will probably prevent that pay down here, any asset sale?

Well, as you recall, John Riley mentioned that we have cash of $340 million right now, so you know, it's a question of looking at our alternatives, staying disciplined, funding the expenditures. We'll continue to look at, you know, other ways of high grading the portfolio. That's a function of what opportunities may come our way. That has to be, you know, looked at. There's nothing contemplated right now, but at least, you know, that's something to balance. You know, we're going to look at all our options to continue to strengthen our financial position.

If you need to outspend your cash generation, is there a leverage point where you start to think about cutting back on CAPEX?

Well, I think what's fair is we sort of encompassed that into the number. We made a lot of cuts as it is. Obviously, depending upon market conditions, there's always more flexibility, but we think sort of that sweet spot right now is that $1.5 billion number and given the fact that half of it is going to the development.

Thanks very much.

Thank you, and everybody that's been on the call, we very much appreciate your interest and time that you have taken to follow our company, and we look forward to keeping updated on the next quarterly call. Thank you very much for attending.

I would like to remind everyone that you may listen to a rebroadcast of this conference at 3:00 PM Eastern Time today through November 6th at midnight by dialing 719-457-0820, or 1-800-203-1112, and enter confirmation code 709765 on your telephone. Thank you for participation. That concludes today's conference call, you may now disconnect.