赫斯 (HES) 2003 Q1 法說會逐字稿

Good day, everyone and welcome to this Amerada Hess quarterly earnings release conference call. This call is being recorded. Today's presentation will be available for rebroadcast at 1 p.m. Eastern time today, running through May 6th at Midnight. You may access the replay by dialing 1-719-457-0820. Again, 1-719-457-0820. Or 1-888-203-1112. And enter confirmation code 335264. That is 335264 on your telephone. All media will be in a listen-only mode for the duration of this call.

Media questions should be directed to Carl Tursi (ph) at 212-536-8593.

At this time, for opening remarks and introductions, I would like to turn the call over to the Vice President and Corporate Secretary, Mr. Carl Tursi. Please go ahead, sir.

Hello and thank you for participating in our earnings conference call for the first quarter of 2003. This is Carl Tursi. With me is John Hess, Chairman of the Board and Chief Executive Officer, John O'Connor (ph), President, Worldwide Exploration and Production, John Schreyer (ph), Executive Vice President and Chief Financial Officer, and John Reilly (ph), Vice President and Controller.

John Hess will present an update on strategic in addition initiatives, John Schreyer then will review first-quarter results, after which the meeting will be open to questions.

Certain forward-looking information and other previously undisclosed items may be discussed during this call.

I will now turn the call over to John Hess.

Thank you, Carl, and welcome to our first-quarter conference call.

I would like to make a few brief comments on the progress we are making to strengthen our exploration and production business and the improvement in financial results achieved by our refining and marketing business in the first quarter.

Regarding exploration and production, we have made significant progress with our new field developments. We have also moved forward in our program to upgrade our portfolio of producing assets. As to new field developments in he Equatorial Guinea we continue to have ongoing and very productive discussions with government officials concerning Northern Block G.

We currently expect plans of development for the Acume (ph), Oveng (ph) and Elon (ph) fields to be approved before the end of the second quarter.

In terms of the Malaysia, Thailand joint development area where we increased our working interest to 50% due to an asset swap with BP completed in February, we have now been assured by government officials that contracts for the construction of the pipeline and gas plant are currently being committed and will be authorized by the end of the second quarter.

It is important to note that with the production facilities and platform completed, no significant expenditures by Amerada Hess are required for the commercialization of these natural gas fields.

The full investment for the pipeline and gas plant will be made by Malaysian and Thailand authorities. These significant new field developments are projected to commence production in the second half of 2005 and will strengthen the competitive financial metrics of our exploration and production business.

Continuing the process of upgrading our producing portfolio, we are engaged in completing sales of several non-strategic assets. In January, we sold our small interest in the trans Alaska pipeline. On April 23rd, we announced the sale of our 30% interest in the Jabung(ph) PFC in Indonesia for a total cash consideration of $164 million, including working capital. $23 million of the consideration is contingent on certain milestones being achieved in the downstream LPG project.

In May, we expect to complete the sale of the Arbroath (ph), Montrose and Arkwright (ph) fields in the United Kingdom for $62 million. We are currently in final negotiations to sell our Gulf of Mexico Shell properties. We expect to complete this sale in the second quarter.

Proceeds from these assets sales will be used to further reduce debt and fund the development of new oil and gas fields that meet the corporation's strategic objectives of lowering unit costs and increasing reserve to production life.

Lastly, we are extremely pleased with the first-quarter financial performance of our refining and marketing business. Our Hovensa (ph) refinery joint venture with (inaudible) had its full contract crude supply from Venezuela reinstated in March.

The availability of this crude supply, the full operation of our new coker (ph), and the improvement in refining economics due to low product inventories together contributed to our share of Hovensa's net income being $50 million.

The colder than normal winter also significantly improved the financial results from our energy marketing operations.

I will now turn to John Schreyer, who will comment on 2003 first-quarter financial results.

Hello, everyone. Our earnings release was issued this morning, and it appears on our web site. I will spend a few minutes on our usual comparison of first-quarter results to the fourth quarter of last year, and then cover several other items.

Looking first at our consolidated results of operations and cash flows, net income for the first quarter of 2003 was 176 million, and income from continuing operations was 216 million. I will discuss income in more detail in a minute.

Turning to cash flow, net cash provided by operating activities in the first quarter was $488 million. This is a GAAP number which includes changes in working capital and certain other balance sheet items. The cash flow number we traditionally discuss is cash flow from operations, which we define as net income adjusted for non-cash items. That number was $535 million.

The principal uses of this cash were as follows: Our capital expenditures were 341 million. After funding capital expenditures, we had debt reduction of 143 million. Cash dividends were 54 million. And there were miscellaneous items for 3 million.

The quarter-end cash balance was $196 million. Our debt at March 31st, 2003, was 4.8 billion, and our debt to capitalization ratio was 52% compared with 54% at the beginning of the year.

Turning to our exploration and production business, net income from continuing operations for exploration and production activities was 146 million in the first quarter of 2003 compared with a loss of 362 million in the fourth quarter of 2002. Excluding the impact of the $31 million gain on the asset sale in the first quarter, and excluding the asset impairment in the fourth quarter, E&P earnings were $115 million in the first quarter compared with $154 million in the fourth quarter. The components of this change, which on an after-tax basis is 39 million, are as follows:

Our average crude oil selling price increased by approximately $1 a barrel which includes hedging, and that increased our first-quarter earnings versus our fourth-quarter by $13 million. We had higher natural gas prices. That also increased our earnings in the first quarter by with $11 million. We did have lower production volumes, which reduced our earnings in the first quarter as compared to fourth.

We had an under-lift in the first quarter and we had an over-lift in the fourth quarter. The net effect of this was $28 million, fourth to first quarter. And as I'll explain in a minute, we had higher income taxes in the fourth -- in the first quarter of this year, and that reduced our earnings by 10 million.

All other items are 14 million.

That's a total of 39 million, as I mentioned earlier.

Turning to oil and gas production, which is shown on Page 4 of the press release, in the first quarter of '03, crude oil and natural gas liquids production was 295,000 barrels per day, compared with 315,000 barrels per day in the fourth quarter. The decrease is due to temporary production interruptions and natural decline in the United Kingdom, reserve -- reservoir management in the Ceiba (ph) field, and the exchange in February of the Colombian producing properties for an increased interest in the JDA which is not yet producing.

Production from the Ceiba field in Equatorial Guinea averaged 25,000 net barrels per day in the first quarter. Natural gas production in the first quarter was 754 million cubic feet a day, an increase of 6% from the fourth quarter. This increase was primarily due to seasonal demand in the United Kingdom.

Production of oil and gas on a barrel of oil equivalent basis was 421,000 barrels per day in the first quarter compared with 434,000 barrels per day in the fourth quarter. Full-year 2003 production is presently expected to be approximately 360,000 barrels per day, depending on the timing of asset sales.

Exploration expense in the first quarter of '03 of approximately 108 million approximated the fourth-quarter amount. The first quarter includes 25 million from Devil's Island drilling costs, which were capitalized approximately one year ago, and for which there is as yet no development plan.

Our planned exploration spend for 2003 is approximately $300 million. The effective income tax rate for exploration and production operations in the first quarter of '03 was 53%. The rate is higher than our full-year 2002 rate of 41% due to the absence of the Colombian operations, which are now classified as discontinued operations, and which had a lower effective tax rate than the average for the year.

In addition, the first quarter effective rate includes corporation tax in the United Kingdom at 40%, whereas the average impact in 2002 was less because of the new tax became effective in April of 2002.

There were also several small one-time income tax benefits recorded in 2002, and they contributed to a lower effective rate for that year.

We anticipate that the full-year 2003 effective income tax rate will be comparable to the rate in the first quarter of the year.

The after-tax -- the after-tax impact of crude oil and U.S. natural gas production hedges in the first quarter of '03 was an opportunity cost of $102 million, $4 per barrel on an after-tax barrel of oil equivalent basis, compared with an opportunity cost of $32 million in the fourth quarter of '02. The status of our hedges at March 31st is as follows:

For 2003, the remainder of the year, we have hedged 75% of our crude oil production. For 2004, we have hedged 50% of our crude oil production. The average price for it. I-related open hedge positions is $24.60 in '03, and $24.30 in '04. The average price for Brent (ph) related open hedge positions is 23.80 in '03 and 23.25 in '04. (inaudible) 20% of our hedges are it. I related and the remainder are Brent.

For 2003, the remainder of the year, we have hedged 20% of our natural gas. That is, our U.S. natural gas. The average price of the U.S. natural gas production hedges is $4.40. We have deferred tax hedge losses at March 31st. They total $103 million for the 2003 hedges and $5 million for the 2004 hedges. That's a total of $108 million on an after-tax basis. 39 million of it is realized and 69 million is unrealized at March 31st prices.

Primarily as a result of the decline in crude oil prices since the quarter-end, the deferred hedge loss as of April 25th has decreased from the 108 million at March 31st to 65 million, which -- both of which numbers include the deferred realized losses.

Looking at refining and marketing, refining and marketing earnings amounted to 136 million in the first quarter of 2003 compared with 20 million in the fourth quarter of '02. The corporation's share of Hovensa's income was $50 million in the first quarter compared with $4 million in the fourth quarter. RM earnings include 8 million basis on the (inaudible) note each quarter. The balance of the note at March 31st was 364 million and principal and interest payments are current.

Retail operations were profitable in the first quarter in spite of the sharply higher cost of gasoline. Energy marketing results were significantly higher in the first quarter compared with the fourth quarter and compared with last year's first quarter which reflects the colder winter. After-tax trading income was $18 million in the first quarter of '03, compared with a small loss in the fourth quarter.

I'd like to comment on the line item "general and administrative expense" in the income statement. G&A expense in 2003 is expected to be higher than in '02 because of increased professional fees, increased insurance costs, and increased employee benefits, including pension expense. The expense in the first quarter of '03 is $78 million, compared with 61 million in the fourth quarter. The in -- the increase reflects the items I just mentioned, and one-time charges of 4 million related to the consolidation of our Dallas and Houston offices, as well as reduced fourth-quarter corporate expenses which were abnormally low due to the timing of (inaudible) allocations to business units. We continue to work on cost reduction in all areas of our business, and we anticipate additional initiatives will be announced later in the year.

As indicated in the press release, we sold our 1.5% interest in the trance Alaska pipeline, resulting in an after-tax gain of $31 million in the first quarter of '03. That gain occurred largely from the buyer's assumption of debt and his assumption of dismantlement liability.

As John mentioned, consistent with our strategy to lengthen reserve life and lower unit cost, we exchanged our crude oil producing properties in Colombia plus $10 million in cash for an additional 25% interest in block A-18 in the joint development Asia of Malaysia and Thailand. The loss on this exchange includes the adjustment to fair value of the book value of the Colombian assets, and the recognition in earnings of the value of the related hedge contracts at the time of the exchange. The adjustment to fair value is a non-cash charge of $43 million, and the loss on the hedge contracts was $17 million. These items were partially offset by first-quarter earnings from the operations in Colombia of $13 million. The total of these charges is $47 million, and this is shown as a discontinued operation on the income statement.

The corporation's interest in the JDA is now consolidated in its financial statements, whereas previously it was shown as an investment on the balance sheet.

The corporation adopted FAS 143, accounting for asset retirement obligations, effective January 1, 2003. A net gain of 7 million, resulting from the cumulative effect of this accounting change, was recorded in the first quarter. At the date of adoption, a liability of 556 million was charged -- was -- representing the present value of the corporation's required dismantlement obligations was recorded on the balance sheet. In addition, a dismantlement asset of 311 million was recorded, as well as accumulated depreciation of 203 million.

For the full year of '03, we estimate that the depreciation of the dismantlement asset, plus the accretion of the dismantlement liability, will be approximately $50 million. This represents a decrease of approximately 17% from the dismantlement expense under the previous accounting policy.

This concludes my remarks.

John Reilly, John Hess, John O'Connor and I will be happy to answer your questions. Vickie, would you prepare for that.

Thank you. The question-and-answer session will be conducted electronically. If you would like to ask a question, you may do so by pressing the star key followed by the digit 1 on your touch-tone telephone. If you are using a speakerphone, please make sure your mute is function is turned off to allow your signal to reach our equipment. We will proceed in the order that you signal us and will take as many questions as time permits. Once again, please press star 1 to ask a question.

Our first question will come from Steven Pfiefer with Merrill Lynch.

Hi, guys. I had two questions. On the production profile, I know the target is 360 this year, which includes the effect of the divestments. Could you maybe -- I know it's -- the company is always reluctant to talk about quarterly numbers, I know, but give us some sense for when do things really start to fall out and behind all that, when you work out the divestments, what would you sort of calculate or estimate as your underlying decline, ex any kind of divestments.

And then secondly, on the downstream, I guess retail and energy marketing, when I kind of do the math and subtract into what they did, I guess they did about 10 million in 4Q and it looks like 60 million in 1Q. Could you just give us a little color on how much of that is retail, how much is energy marketing, and how much of that may be, you know, obviously just very strong heating -- just let's say sales and how much might be repeatable, thanks.

Hi, Steve. Production profile. I think the key point there is the two developments, and what each one of them will produce, Equatorial Guinea, G Block being -- (inaudible) and also the JDA and what I'd like to do is to give to John O'Connor to give you some guidance on those two major developments and I think those are the two key components of future growth for us. So a little more elaboration on that would probably be helpsome.

Yeah. Okay, John. Thank you. Hi, Steve. We expect that initially those two developments will contribute to (inaudible) oil equivalent in the second half of '05 and hopefully we'll see some growth beyond that. The same, we do some other developments in Mexico which has recently been sanctioned and is moving ahead. And we have a couple of other developments in the north sea. With respect to the outlook for the full year, I think we'll still stay with our guidance given on the last conference call of an average of 360,000 barrels a day, or thereabouts, for this year. Maybe a shade above it, but the guidance still holds.

In terms of when we'll see the impact, I think you'll see the impacts from the asset sales, particularly (inaudible) second half of the year. Obviously Colombia volumes are out of the first quarter now. Jabung will also go out in the second quarter and I think as John said in his commentary, the -- the shelf sales will likely be consummated in the second quarter and so those volumes will come out thereafter. So the second half of the year should be (inaudible) transactions.

On so to remind everybody, we are being guide to do reshape our E&P portfolio to have a lower unit cost. Our target is $12 a barrel of oil equivalent. It's not going to happen overnight but the producing portfolio reshaping with new developments coming in and less strategic assets going out is a segue to get there. It's going to happen over several years, and also the reserve to production life target is 10. And we are going to be guided at creating a portfolio that can sustain financial performance for the long term and that's one of the reasons we did the Colombia for JDA swap.

On the downstream, the majority of earnings outside of Hovensa and the trading are energy marketing. Retail was marginally profitable because wholesale prices were still going up very quickly. Our C-store business offset a lot of the increase with improved performance, but the degree days being about 10% colder than normal for the quarter, and I think 35% colder than last year, were big drivers in our two oil sales, our residual sales, as well as our natural gas sales.

Great. Thank you.

Our next question will come from Arjun Murti with Goldman Sachs.

Thank you. Regarding the reshaping of the upstream portfolio, the asset sales certainly seem very logical. After the sale of the shelf properties, will that complete the bulk of the asset sales side TV? I'm sure there's always some small ongoing stuff but will that be the biggest chunk of it. And then on the other side, you know, what is your thinking in terms of acquisitions? There's probably at least I guess a couple-year window before some of the new growth projects in UG and JDA come on. Are there things on the acquisition side to help reshape the portfolio and your targets that you might consider?

You're basically correct, Arjun. The bulk of the reshaping will be accomplished when we consummate the shelf sale but there are still some smaller assets that will need to be moved out of the portfolio as part of the consolidation and as part of the emphasis on having (inaudible) larger assets that are longer lived. And in that context, of course, we continue to actively monitor the market in those areas where we have our core fields, such that if others were to indicate (inaudible) we would be interested in adding to our core fields where that makes business sense.

And to further elaborate, on the second point, no major acquisitions are planned. Our focus is on the developments in the Equitorial Guinea, some interesting opportunities that we have on follow-up in the Gulf of Mexico, and those new developments, along with the asset sales, will go a long way to getting our metrics over the next several years very close to the targets I mentioned, so we really do feel we have the internal opportunities for creation of value. And that's where the majority of our effort's going to be focused.

I guess I certainly don't want to put words in your mouth so please correct me if I'm wrong but it sounds like you are then willing to be patient. I mean, do you have some good stuff in EG and some of these other areas? Usually the transition can be painful for companies, and you've felt some of that but you're willing, I guess, to ride it out, if you will, and then let the new projects come on. Is that a character cravings?

That is a correct statement and we will continue to be financially disciplined to create the portfolio that can sustain financial performance.

Thank you very much.

Our next question will come from Paul Cheng with Lehman Brothers.

Paul Cheng Hi. Good morning, guys.

Good morning, Paul.

Several quick questions. As of March 31st, are we at this point under lift, over lift or balanced for the portfolio?

We actually have an under-lift, a cumulative under-lift of 5 million barrels at March 31.

So that -- potentially that could contribute to the results in the second quarter, right.

Correct.

Where is the under-lift? Is it in U.K. or is it Jabung or --

It's primarily in the U.K., but then -- but then it is spread outside of that. There's some in EG, and there's some in Norway as well. But it is primarily U.K.

Uh-huh. And I think, John, earlier have mentioned that you have way off 25 million related to the devil island. Is that just (inaudible) that project is not going to be go ahead or that may be too much into that?

No, Paul, the situation we find ourselves in is that it is 12 months since we completed the well and capitalized it on the balance sheet, and accounting action is therefore required. In the absence of a commitment to a development, we're obligated to write it off.

Operationally, the situation we find ourselves in is that we have new seismic coming in next month and we have a full-blown seismic survey covering the Garden Banks area which will be processed and interpreted by the gaining of next year. So we think it's more prudent to wait until we have that data in hand and decide how to proceed with Devil's Island.

And also, quite frankly, we find ourselves in the fortune position that we have at this stage more attractive investments to invest in, so it's simply behind in the queue but it does not mean that it won't proceed to development.

Uh-huh. John, how much is the reserve you need for that to be commercial?

I -- I would put a high threshold of around 20 million barrels for development. The key issue there is the transportation system from the discovery back to the processing platform, and somewhere in the vicinity of 15 to 20 barrels, depending where you put your threshold, would be about the crossover point. Of course we feel we're in that vicinity, Paul. As I said to you, we just want to have the opportunity to have greater certainty around that development on the back of the new seismic that's going to be coming to us.

Sure, sure. Last one. I think John earlier have talk about, with the new accounting group, the -- the dismantle charges for the year is going to be lower. Can he just repeat that number?

Yes. I said that the charge for the current year, 2003, would be about $50 million, and that's about 17% below what it otherwise would have been if we'd continued with the old policy.

And what's that number last year, John?

It was 61 million last year.

Okay. Very good. Thank you.

Uh-huh.

We will now hear from Deutsche Bank's Jay Saunders.

Hi. Thanks. Two questions. First is, where -- where in the process are (inaudible), (inaudible) and in he can by Equatorial Guinea and what is the timing for first production there, and the second is on the asset sales. Is the target still around 300 million for the year?

On the asset sales, the total proceeds, we didn't, I don't think, set a target out there. The numbers that we're looking at will be in excess of that. That much I can say. Assuming different things get finalized, but we can't elaborate more until the shelf sale is finalized, so it would be premature to talk on it. In terms of could you may, Oveng and Elon, we mentioned that we hope to have approval by the end of the second quarter, no later than that, to move forward. Our plans are certainly on that basis. John O'Connor, you might want to elaborate on that.

Yeah. We have a full accord between ourselves and the authorities in EG on the development path. Right now, we're finalizing subsurface optimization and final facility selection, and as John said, we expect that we will have that work completed and reviewed and receive our approvals in the second quarter of this year. As to first production, we are still targeting mid-2005 for first production from those northern Block G fields.

How about for the other three, (inaudible), (inaudible), and (inaudible).

Currently, the way we look at that, Jay, is that we will bring up the first three fields and then we will supplement with the other fields subsequently. So we'll probably go ahead with applications for development approvals for those while the facilities are being constructed, and have the flexibility to add the developments from those fields into the (inaudible) production from the initial three.

Okay. Thanks.

You're welcome.

Our next question will come from David Willer (ph) with J. P. Morgan.

Hi, gentlemen. Two questions. Can you -- the first one is just can you clarify what's the impact of asset sales assumed in your '03 target of 360,000 a year? What's the number that you've assumed as an impact there?

I can give you an annualized number, so on a full-year basis the production that we see from the asset sales would be about 45,000 a day. And then it's going to depend on the timing. It will depend on how much of that production we see this year.

Does that include Colombia?

That includes Colombia.

I think it's important to know that. Okay. And secondly, on -- John, you mentioned the cost target. Back in May of '02, you were talking about a target for '02 costs of $14 a barrel and a longer-term target of $12 a barrel. Well, your '02 costs ended up coming in closer to 15-and-a-half dollars a barrel, so a little bit lower higher than you were looking for, so that longer term target is now a little bit harder to get to. Can you elaborate a little bit? I mean, do you expect to get -- to cut your costs from 15-and-a-half to 12 just through these asset sales or --

No. It's going to be a combination of asset sales, new developments, and further cost reduction initiatives, and we are going to be very disciplined to go after that. It will take some time, but we have modeled this in our plans, tan as the new developments come in, the higher cost production goes out, as well as the asset sales and cost reduction initiatives that $12 target, while it is an aggressive stretch, we do think it is realistically achievable over the next several years.

Okay. And can you comment as to why you didn't hit the $14 target and you ended up more in the 15-and-a-half range?

Lower production at the time versus the estimate. You know, LLOG went against us, as well as EG and Ceiba, ended up being lower production for a longer time period.

Okay. Thank you.

Our next question will come from Mark Flannery with Credit Suisse First Boston. And Mr. Flannery, your line is open.

Hi. Can you hear me?

Yes, we can.

Oh, good. Thank you. Yeah, the G&A expense which is going to be higher in the quarter, can I clarify a couple of things? Should we take that let's call it $75 million as a run rate for the rest of the year? And if so, can you give us a little bit of a split between the three items that you mentioned as contributing to that? And then I have a follow-up question.

The run rate for G&A for the year is approximately 75 million. You can take it as you said. And of the three items affecting G&A?

Uh-huh. The fact that they're higher, one was professional expense, one was, I think --

I can tell you how much they're affecting our costs in general. It's harder to tell you how much of it impacts G&A.

Okay.

The insurance costs are up by $18 million. Our pension expense is up by $20 million. And our professional fees are up in the 5 -- up $5 million, more or less.

Okay.

And these are annual numbers I just gave you.

Sure. Okay. And the follow-up question is: We're expecting to see some closure of the remaining asset sales in this current quarter. This might be a hard question to answer, but what -- in general terms -- are you expecting in terms of book gains or losses to be included in the second quarter number? I.e., will it be a gain or a loss? And will we hear that number before we hear the second quarter results?

I think the fair thing to say it would be premature and inappropriate to put a number out there right now until these sales are closed. At the same time, we are, in aggregate, looking at gains.

Right. Okay. Thank you.

Our next question will come from Matthew Warburton (ph) with UBS Warburg.

Good morning, gentlemen. A couple of questions unrelated, if I may. In your 10-K, you talked about before working capital changes and asset disposal proceeds, an operating cash flow reduction of 30% for 2003. I just wondered if circumstances have changed in terms of the way prices have moved so that you can update us on that guidance is the first question.

My second question is on Hovensa. Clearly you've obviously pleasingly been able to restore crude supply to the units there. I've just wondered if you've estimated an opportunity cost from the third-party purchasers you had to make in the early part of the quarter. And then I've got one final small follow-on from that.

Okay. Matthew, as -- on your first question, regarding the cash flow, we did have in our 10-K a disclosure that said "assuming constant oil and gas prices," that our cash flow from operations would be down 30%. And as you mentioned, with the increase in oil and gas prices, we do now anticipate that number to be down 20%. So obviously an improvement from -- from that disclosure at that time, due to the prices.

As far as an effect on first-quarter earnings, there obviously was some effect. It's difficult to determine whether -- I mean, when you have the (inaudible) volumes in the market, whether it's affecting overall refining margins and that the effect related to the margin itself versus us not getting the supply. So it's -- it's difficult to determine. We had a good quarter, $50 million of income from Hovensa, so I think we have to leave it there.

Sure. Okay. One final one, if I may. One of the group constituents, one of the other companies that reported recently, was able to over-lift in terms of its U.K. gas position on one of its systems. I know you mentioned that the U.K. contributed to the under-lift overall, but I wondered, given the very strong prices in Europe and the U.K., whether or not on the gas side you were able to actually over-lift in the first quarter.

No. there wasn't over-lift and again we ended up with a cumulative under-lift and that was more -- that was from the I'll side.

It was oil driven, not gas.

Right. Okay. Fantastic. Thanks much.

We'll now hear from First Albany's Mark Gilman.

Good morning, guys. I had a couple of things, the first of which is just clarifications. Did John Reilly say that the position at the end of the first quarter was a 5 million barrel under-lift is? Is That seams awfully large.

It is a 5 million barrel under-lift. It wasn't all 5 million barrels in that quarter but it's a cumulative barrel under-lift at the end of the first quarter.

Okay. I believe John O'Connor said incremental production of 60,000 equivalent a day from JDA and northern Block G. Is that correct?

Yeah, that's correct, Mark.

That applies only 30 from northern Block G. Is that what your thinking is?

That -- at this stage, what we're looking at, given how we have recognized the key to effective management in these reservoirs through the Ceiba performance, which I'm happy to say has been running very well in the first quarter, very stable, responding nicely to water injection, we now understand that the effective way to manage these reservoirs is a more modest offtake rate for a longer period of period of time. So feeding that experience into the development, we're adopting an approach that says the initial development is probably of the order of 50 to 60,000 barrels a day gross from the first three fields and that's the approach we're taking until we know some more from our experience in Ceiba, Mark.

I'm sorry, John. 50 to 60 gross?

Correct.

How does that get to 30 net?

Multiply by 68 to 70%, depending on the operation of the PSA.

Oh, so you're putting in -- that's an entitlement number?

Right.

Okay. John Schreyer, I can't understand for the life of me how your effective tax rate can be 56%, or whatever the number north of 50 was that you talked about. I mean, you just don't seem to me to have enough in the way of statutory rates to justify getting to that level. Could you possibly shed a little additional light on that?

Yeah. I said it would be 53% on average for the year. There are several moving parts. We do have a high effective rate in Norway, where production is constant to increasing a little bit. We do have a high effective rate in Jabung, very high effective rate in Gabon. Our U.S. production is declining, to a certain extent. That is a lower effective rate of 35%. We also have -- we are doing drilling and incurring other costs in areas where we don't presently receive a tax deduction. Either because we don't have any other operations in that country or it's outside of PSC. We may get a tax deduction as a worthless stock, but we don't take that into account in advance. So that reduces -- that reduces the benefit that we get. So it's all those items added up together, Mark, that give us a -- a 553% effective tax rate.

So in other words, you think going forward, all things being equal, it's sustainable into '04?

I don't know about '04, but '03 -- '03, it's -- it looks like 53%. ^.

Okay. What was interest expense so high in the quarter?

There was less capitalized interest, Mark, in the quarter. Predominantly related to JDA, and with the sanction of -- of the project, meaning that the actual construction of the facilities were completed in the fourth quarter. We stopped capitalizing interest.

What was that number, John, please?

It's -- it's about -- I think the total amount on the interest itself, the capitalized interest, was about 12 to $13 million. Less in the fourth quarter.

Okay. Just one more. (inaudible) in Algeria, obviously the gross field number must be moving up very smartly, or there's some kind of adjustment occurring there. Could you comment, given that the PSC effect should have taken that number down, not up, in a high-price environment? What's going on?

We're unhappy, Mark, with the developments that are ongoing there, but I think the net number to us, if you gross it up, would mislead you in terms of where the total hundred percent field development is. It is moving up, but not in a way that's substantial. It's running at around 40,000 barrels a day gross right now.

This is a -- a very interesting PSC, quite frankly, that (inaudible) operates in Algeria, and it moves around quite a lot in terms of entitlement, more so than the normal PSC where you're just looking at profitable on (inaudible) so it's partly on the basis of hundred percent basis, field volumes are going up quite nicely buff it's also attributable to the operation of the PSC that governs of the (inaudible) operations in Algeria.

Thanks, John.

You're welcome, Mark.

Moving o we will hear from Frederick Leuffer with Bear Stearns.

Good morning. Can you hear me?

Yeah. Good morning. How are you, Fred?

Good, John. Thank you very much. I was surprised at the jump in the dry hole and lease impairment expense, and I heard what you said about Devil's Island, but I'm -- I'm still -- it looks a little high to me. I'm just wondering if there was a jolt in impairments or if there was some notable dry holes that you can talk about.

I'll try to help you, Fred. So you had the Devil's Island number in it. Our seismic is a little up in the first quarter. We're kind of front-loaded on our seismic program this year. And a good piece of that has to do with the fusion transaction, so we have some earlier commitments on the -- on the seismic in West Africa related to the fusion deal. And then for our dry holes in the quarter, what we had was -- was really, outside of devil's island, which we expensed, would be El Dorado, which was approximately 10 million, a little bit less than 10 million. We had a dry hole, West (inaudible) in Block G in EG. And then -- I mean, there was a couple other dry holes of a smaller nature, making up the rest of it.

Okay. And for the year, you said you would expect expense to come in at what? 300, you said?

This was exploration spend was right around 300.

Do you have an estimate for exploration expense?

Expense will be a little bit higher with that. If you -- if you're including the devil's island piece into it, it could be 325 to 330.

Okay. I tuned in a little late, so if you did this, we can take it off-line, but if you haven't, can you give us drilling update for the rest of the year, the Gulf of Mexico and EG.

John O'Connor?

John O'Connor Yeah. Happy to do that. Gulf of Mexico, currently we are participating in two deep targeted medium to deepwater wells. The deepest well currently is Chinook on Walker Ridge 496 No. 1. BHP is the operator. We have a 15% working interest, earned interest, net. Currently, the well is at 25,000 feet and targeted to go to 29.

The second well in the Gulf of Mexico is tubular bells, Mississippi Canyon, 725 No. 1, BP operator, (inaudible) 25% working interest in that well. Currently the well is at 18,000 feet, setting casing and is projected to go to around 30,000 feet. Later on, mid-year, another key well will be an appraisal well to last year's Shenzee discovery and we're looking forward to that obviously. Also around the same time frame, we will be drilling in Equatorial Guinea, the G 13 No. 3 well which is which was an appraisal to last year's discovery (inaudible) appraisal well in the quarter just gone by. Those are really the key wells to watch out for. We will have a second well in Algeria. It's an obligation, wildcat, and we have a couple or possibly three wells in Denmark which I would categorize as of being of a similar nature. These were contractual wells to which we're obligated. But the key wells are the Gulf of Mexico to watch out for, and the appraisal well to the G 13.

Okay.

It's possible also that we may be involved in some wildcat drilling in Brunei Block J.

All right, John. Thank you.

You're welcome.

Our next question will come from Tim Gary with Arc Asset Management.

Yes. Can you help me understand why production expense was up year over year, both absolute and more significantly on a per BOE basis?

I think, Tim, it's predominantly due to even as the -- as the production levels come down, we've got a fixed cost of some of our operations, so the fixed base isn't going down as much as -- as our production levels are. And that's basically the driver for it.

So that would be on the BOE basis?

Yeah. And then --

And what about on the absolute basis, year over year, 205 versus 173?

My understanding, there's some -- obviously there's a mix of field issue with it, and also some higher transportation expenses that are -- that are in the production line. In the first quarter.

And is that -- there ha -- is that tanker rates or what?

I'm getting the answer. It's -- it's more of a pipeline type rates coming in.

Tim, let me just say that with respect to production costs in the E&P business, we are very conscious of the fact that these costs are well in advance of the targets that we have laid out as a corporate goal of $12 a barrel. We did take some initiatives last year with respect to reorganization, consolidating offices, as we've reported on both in northwest Europe and in the move of the Dallas office to consolidate into Houston. We are obviously deep into evaluating opportunities to progress those cost reduction initiatives, and we believe that in the not-too-distant future -- that is to say, in the next two to three months -- we will be coming forward with specific plans to take these costs down to much more competitive levels.

Okay. Thanks.

Our last question today will come from Paul Cheng with a follow-up.

Just a -- two real quick question. John, when we talking about exploration (inaudible) program, going forward how many wells that you plan to do in (inaudible) major region on average in the deepwater Gulf of Mexico, EG, and maybe if we throw in Algeria and also Norway together?

And then also the other question is that for -- what is the interest income or the payment you receive from (inaudible) for the quarter?

Paul, just to talk about the exploration program for the year, roughly running at about 18 wildcats in total for the year. We expect that will probably comprise five wells in the Gulf of Mexico, including the El Dorado that we've already talked about, and Chinook and Tubular Bells which are currently drilling. Whether citizen has one appraisal or more than one appraisal remains to be certainly (inaudible) and we have one other prospect that we are looking at. In EG, in the block L well operated by Shell (inaudible) have text where we have 25% interest has been P and A'd. John Reilly talked about the West (inaudible). We did the first G 13 appraisal in the first quarter and then we have the second G 13 appraisal ready for mid-year drilling. That's coming forward.

The first quarter, we also drilled a dry hole in Gabon. I mentioned to you -- or mentioned on the call that depending on circumstances in the Brunei offshore and the plans of our operator, to Telphena Wells (ph), we may see one more wells in that area. And I also mentioned that we have two to three obligation wells in the Danish offshore, and a couple of wells in Algeria and that comprises the program this year ^

John, I'm more asking not for this year but going forward. I mean, how do you look at your exploration program as a whole on an ongoing basis.

Yeah.

Should we assume that in the future, the number of wildcat and appraisal wells and also the -- the (inaudible) that you're going to spend will be roughly equal to this year?

Yeah, I think that this year is a good template for it, though the mix of wells will be different. I mean, as you understand, Paul, we are transitioning away from a program that existed for us in the past, and towards a program which concentrates on high-impact prospects. I think the areas of focus for us will still be the deepwater Gulf of Mexico, deepwater offshore West Africa, and deepwater Southeast Asia. So the -- the arenas that we are exploring in will be the same, but the well mix will change because once we have the Algerian and Danish obligations behind us, you should expect to see 18 to 20 wildcat wells a year focused on those core areas that we're concentrating on. So the mix will change, the numbers will stay about the same, and we expect to continue to be exposed to high-impact prospects.

Very good, thank you. And how about on the -- on interest income that you guys received in the quarter?

Paul, we -- we recorded interest income in the quarter of approximately $8 million. We did receive our payment from PDVSA (ph). PDVSA is current. You know, the overall payment is 46 million in the quarter, but we recognized interest income of 8 million.

You only recognize 8 million. So that means that your energy marketing must be to the 40 million kind of range for the quarter.

Energy marketing did -- it had a strong quarter, and Hovensa and energy marketing did lead the results for R&M.

Okay. Very good. Thank you.

We do have time for one more question. We will now hear from Fidel Gheit with Fahnestock.

Good morning.

Good morning.

A couple of question. One on the balance sheet. Do you guys have any debt level target at the end of this year, or even in two -- in 2004?

At the end of this year, we are targeting to be under 50% with our -- with our debt-to-cap ratio. On a -- just on a general longer term goal -- and it will depend on how we fund the developments and when they get completed, but we would like to be under 45%, and we've always said 35 to 45 is our long-term goal.

So we're assuming -- then we should not think of the free cash flow as a priority to go pay down debt.

No. Free cash flow is a priority to pay down debt but we also have approximately $900 million of developments this year, and a similar number next year. And as we said in the comments, both our free cash flow, along with the proceeds from the asset sales, will be dedicated to two priorities. One is to reduce debt and the other is to fund these developments that will strengthen our competitive financial metrics in our E&P business for many years to come.

And then do you have a number handy for the average DD and E per BOE (ph) in the first quarter?

It's approximately 770.

Should we assume that this number going to stay or could go higher?

It will -- it will basically stay flat through this year, and then obviously as John O'Connor talked about, the initiatives that we're looking to put in place and then reduce it over the longer term.

And then finally, how much or the percentage of your production right now that does not meet your 15% total end cost (inaudible).

I -- I think, you know, what we're doing right now, Fidel, is dealing with the higher-cost non-strategic properties, which is why the production equivalent, I think, for the first quarter was about 17,000 barrels a day that John Reilly gave you in an annualized number. That's what we're selling. As the future proceeds, and these new developments come on, there may be some other marginal properties that we would also consider disposing, if we got attractive prices, to continually upgrade our producing program and our portfolio there. So that -- this is a continual effort to reshape the producing portfolio, but lower costs, unit costs properties in with the developments, and sell the higher cost non-strategic assets.

What I was hoping for is that you would have a -- a few properties that account for the majority of the higher (inaudible) so when you get rid of the properties, you don't lose the volume (inaudible).

That's why we're selling what we're selling right now, Fidel.

Okay. Thank you.

Thank you, everybody, for your attendance today, and we look forward to keeping you informed on our progress in future quarters. Thank you very much.

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