赫斯 (HES) 2002 Q4 法說會逐字稿

Good day, everyone. Welcome to this Amerada Hess quarterly earnings release conference call. The call is being recorded. Today's presentation will be available for rebroadcast at 1 p.m. eastern time running through February 6 at 9, midnight. You may act access the replay by dialing 1-719-457-0820. Once again, that was 1-719-457-0820. Or you may dial 1-888-203-1112 and enter confirmation code 693408. That is 693408 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 at 212-536-8593.

At this time I'd like to turn the call over to the Vice President and Corporate Secretary Mr. Carl Tursi. Please go ahead, sir.

Hello. Thank you for participating in our earnings conference call for the fourth quarter of 2002. This is Carl Tursi. With me is John Hess, Chairman of the Board and Chief Executive Officer; John O'Connor, President Worldwide Exploration and Production; and John Schreyer, Executive Vice President and Chief Financial Officer. John Hess will present an update an strategic initiatives. John O'Connor will discuss exploration exploration and production in greater detail, and John Schreyer then will review fourth 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. Information relating to reserves other than proved reserves also basketball discussed which will not be permitted in SEC filings.

I'd like to turn the call over to John Hess.

Thank you Carl, and welcome to our year-end conference call. I'd like to update you on our most important strategic initiatives to strengthen our exploration and production portfolio, discuss the impact of the Venezuelan strike on our refining and marketing business, and review our financial position. Then John O'Connor will cover some key subjects in exploration and production. After which John Schreyer will comment on our financial results.

First we've been working with the government authorities in Equatorial Guinea to obtain approval for our plans of development for the [ACUMA], [OVANG], and Elon fields. Good progress is being made, and we anticipate receiving approval in the next several months. Second, we are announcing today a swap with British Petroleum of Colombian oil properties, or BP's 25% interest in natural gas reserves in the joint development area, or in the JDA, of Malaysia and Thailand, which will increase our working interests in the JDA project to 50 percent. Essentially, we will be foregoing approximately 18,000 barrels per day of mature oil production in Colombia today for an equivalent of amount natural gas production in 2006 that should maintain this plateau through for the following 20 years. The JDA meets our corporate performance objectives of total unit cost of $12 per barrel equivalent and a reserve to production life greater than ten years. The JDA has the potential for significant further additions to proved reserves and production. once more natural gas is contracted. We expect the contracts for the most of the pipeline and gas plant to be authorized early in the second quarter of this year.

Third, I mentioned on our last quarterly call that we will pro actively sell nonstrategic assets to reshape and refocus our EMP portfolio. To that end asset sales are planned for three producing properties: the Gulf of Mexico Shell properties, and Gebum field in Indonesia, and the [ARBRA], [MONTROSE], and [ARKRIGHT] fields in the U.K.. These properties have current production of approximately 25,000 barrels a day per of oil equivalent, and will only be sold if we receive attractive prices. We already have a contract of sale with the U.K. fields with [HALADEN RESOURCES]. With regard to Venezuela and our refining and marketing operations, on December 6 our Hovenia refinery joint venture received a notice suspending crude oil shipments. In reaction to this notice, the refinery reduced crude charge rates and began buying substitute crude oil. Since December 6, nearly 14 million barrels of substitute crude oil and other feed stocks have been purchased to meet the refinery's crude oil requirements. Hovenia just received its first crude oil shipment from Venezuela this past weekend. Indications are that further Venezuelan crude shipments are being scheduled, although at reduced levels from contractual amounts. Hovenia has continued to meet all financial obligations and third party product sales commitments.

Finally, in terms of our financial position, debt reduction continues to be a primary focus for the company. We reduced debt by $673 million in 2002, exceeding our $600 million debt reduction target. At December 31, 2002, our outstanding debt was $4.9 billion. For 2003, our capital expenditures are estimated to be $1.45 billion, of which $1.4 billion is for exploration and production, of which $700 million is for development projects. Excess cash flow will be used to further pay down our debt in 2003.

I will now turn to John O'Connor, who will discuss our exploration and production operations in greater detail.

Thanks very much, John.

I'd like to focus on three key topics. First our 2002 exploration results and our program plans for 2003. Second, a summary of our reserves position at year end. And third a brief discussion of our recent reservoir experience with Cibra as well as our guidance for 2003.

A highlight of 2002 was our very successful exploration program. We had five discoveries in west Africa and three in the deep water of the Gulf of Mexico for a success rate of 33%. In total we spent $350 million on grassroots exploration activities and we discovered resource of about $200 million barrels equivalent for a resource finding cost of under $2 a barrel. Our exploration program for 2003 is based on expenditures of $250 million and includes the drilling of 16 wells to test risk reserves of 250 million barrels. The program is focused on our impact areas. Five wells are planned for the deep water Gulf of Mexico, four for west Africa, and two for southeast Asia. Of course, 2002 discoveries won't be added to our proved reserves until development plans are sanctioned. However based on our 2002 success and the promise of another good year in 2003, we see exploration contributing a solid foundation for rebuilding our EMP business, which John Hess alluded to earlier.

And speaking of foundations, we estimate our year-end 2002 proved reserves to be approximately $1.2 billion barrels compared to 1.4 billion barrels a year ago. In addition to 165 million barrels of oil equivalent production of last year, here are the key movements. 56 million barrels of oil equivalent of a reduction occurred from writedowns on LLOG and Colombian properties. 48 million barrels of a reduction attributing to production sharing contracts due to high year-end commodity prices. 22 million barrels of oil equivalent to reduction are associated to asset sales last year, and $50 million of net additions and other revisions. Again, please note in a the reserve additions associated with our developements from our northern block G and the increase from our asset swap with BP is not included in 2002's crude reserves.

Now turning to the Saber field which is a core asset for us, our share of production from the field decreased to 30 thousand barrels a day in the fourth quarter of 2002. We are estimating average production of 25,000 barrels a day in 2003. This lower production is due to our decision to reduce offtake from the field to better manage the slow energy but significant reservoir. Saber's production challenges result from high early oil offtake and delayed water injection which resulted significant reservoir [INAUDIBLE] in associated reservoir pressure decline. This effect was compounded by a reservoir that, with ongoing drilling, was proven to be more complex than the original development plan envisioned. The current plan is designed to maximize the value of Saber. We believe this will require additional wells to optimize recovery. It will also contribute to a longer production profile.

In conjunction with [INAUDIBLE], we lowered the prior petroleum engineers' estimates of total barrels to be produced, including both proved and probable reserves by 10 percent at year end. There was no reduction in proved reserves. This reserve reduction to probables, together with increased development costs triggered the fourth quarter impairment charge, which John Schreyer will discuss in more detail. There is no doubt that the Saber field is a very good oil field that will provide lower near term production that we and our partners believe will ultimately produce some 245 million barrels of oil over a longer time period than originally planned.

Now I'd like to review our outlook for production in 2003. After completing our anticipated 2003 divestments including the Columbia asset swap and taking account of the revised Saber offtake, we expect production averaged over the year to be approximately 360 thousand barrels of oil equivalent per day. The production decrease due to the [INAUDIBLE] transaction, based on expected closing dates is about 30 thousand barrels a day. The forecast for our remaining portfolio decreased by 25,000 barrels a day from our previous guidance due primarily to reduced production from Saber and lower estimates from several fields due to high grading of our capital spending program.

In summary, although we have had a number of disappointments we now have a solid resource base. We see a more robust and cost-effective producing portfolio, an inventory of profitable new developments, and an impact exploration program in place, all of which support our embedded growth trajectory. We look forward to sharing our progress with you on future calls.

John Schreyer will now discuss our fourth quarter financials.

Thank you, John. Hello everyone. My remarks, like the previous two Johns, have been filed on an 8 K and will be on our web site. In order to leave additional time for questions, I'm going to cover only the more important items in those remarks now.

We reduced debt, as John Hess said by $673 million in 2002. And that's after funding capital expenditures of 1 billion, 534 million dollars. Our debt to capitalization ratio at December 31, 2002, was 54 percent. The aftertax impact of crude oil and U.S. natural gas production hedges in the fourth quarter of 2002 was an opportunity cost of $32 million. That's $1 per barrel of oil equivalent. Compared with break even in the third quarter. The aftertax hedging impact for the full year was a benefit of $54 million. Unit costs in the fourth quarter of 2002 were compare to those in the third quarter. As increased production expense was offset by lower Depreciation Depletion and Amortization expense in the United States. Unit costs for the the full year were $15.20 per barrel of oil equivalent, including $7.70 per barrel of Depreciation Depletion and Amortization.

Turning to the status of our hedges on December 31, and to make this understandable, we have not reduced the production barrels used for anticipated asset sales. So for the year 2003 we are hedged 82 percent of our oil. And 45 percent of our natural gas. The average price at which the TI-related crude is hedged is $24.90 and the average price at which U.S. natural gas is hedged is $4.15. In 2004, our oil is 13 percent hedged. Our gas is unhedged. The oil price for the hedges in 2004 is $23.95. We do have aftertax deferred hedge losses. They equal $91 million at December 31, $71 million is unrealized. $20 million is realized. R and M earnings include $8 million of interest on the [Pedvesa] note in each of the third and fourth quarters. The balance of the note at December 31 was $395 million. We have been assured that the interest and principal due in the first quarter, which totals $47 million, will be paid.

As John O'Connor mentioned earlier, the corporation recorded an aftertax, noncash impairment of $530 million relating to the Saber field. As he said, the charge resulted from a reduction in probable reserves comprising approximately 10 percent of total field reserves, as well as from the need for additional capital expenditures to produce the remaining 90% of the reserves over a longer field life. These two factors caused projected cash flow from the project to be less than the book value of the field. And that's a book value which reflects allocated purchase price from the acquisition. FAS 144 requires us to take an impairment charge, and future net cash flows must be discounted in arriving at the amount by which the carrying value of the field is reduced. As a result of the longer production profile that John has explained to you, this discounting had a significant can't impact on the amount of the impairment charge.

Moving on to another item, the asset sale recorded in the fourth quarter of 2002 is the sale of the corporation's interest in the on-shore K&K fields in Azerbaijan. That production from the fields was approximately 2,000 barrels per day. John Hess discussed the Colombia JDA property swap being done with British Petroleum. We are, as he explained, swapping our Colombia asset plus $10 million for an additional 25 percent interest in the JDA gas project. Swap accounting dictates that when the swap is finalized we adjust the book value of the Colombia asset we are transferring to BP to fair value. Therefore, when the transaction closes we will incur a charge to earnings of $48 million. This reflects a 30 million barrel of oil reduction in the Colombia proved reserves carried on our books prior to December 31, 2002. We must also mark to market the hedges we have in place in Colombia. This will increase the charge to approximately $60 million.

A word on pension accounting. When the market value of pension plan assets is less than accumulated benefit obligation, the difference must be recorded in other comprehensive income which is a component of stockholders equity. As a result of negative returns on the pension plan assets and the lower interest rate used to discounting the actual determined pension liability, an aftertax charge of $71 million was recorded in shareholders' equity at December 31, 2002.

So now I ask the operator to prepare for questions and turn the meeting back over to John Hess.

Thank you. Ladies and gentlemen, today's question and answer session will be conducted electronically. If you would like to ask a question at this time, you may do so by pressing the star key followed by the digit 1 on your touch tone phone. Once again, that was star 1. If you are using a speaker phone, be sure your mute function is turned off to allow your signal to reach our equipment. We'll pause for a moment to assemble the roster. We will take our first question from Arjun Murti with Goldman Sachs.

Thank you. Just a question -- a couple of questions. First, if you changed your 2005 guidance? Obviously there is going to be assets sales. I assume it will come down by that amount. Beyond that is there any change to that? And can you talk about the experience at Ciba? How it's impacting what you think maybe the production potential of the fields that start up in 2005, [INAUDIBLE], and what the production potential and reserves may be from those fields?

On the first point, guidance for 2005, Argen, as you can imagine, we have several moving pieces here. We have asset sales that are underway. And we will only move forward with them if we receive attractive prices. We also have several developments that are moving forward both in northern block G, which I mentioned, we are pretty confident of getting approval for moving forward in the next couple of months. And then the JDA, which we think again will start moving forward in the second quarter of this year. Obviously, that affects 2005 and 2006. And rather than give you a specific number, I would rather say, you know, these are material projects. We also have some deep water Gulf developments that either are underway or almost underway. And with all those moving pieces, I would rather not give you a specific point out there just to say that we definitely are on a growth trajectory obviously from this lower base. But the key point is it's much more profitable growth. And on the second point, on Saber, John O'Connor, I think it would be helpful if you answered.

Thanks, John. Obviously, Argen, we are learning significant important information from our management of Saber, both in terms of design, in terms of optimization of recoveries. This variance will be incorporated in [INAUDIBLE]. This learning is going to be incorporated in all of block G development.

Okay. And then just one follow-up. What are the key hurdles for the JDA to come on stream at this point? And as I stated moved around over the years a little bit.

The key hurdle is awarding a pipeline contract and a gas plant contract. A lot of work has been done on this. And both [PETRONAUS] and PTT, who are the owners of the pipeline project, are very close to authorizing a decision on this. I would say it's closer than later. That's why I'm pretty confident that by the end of the first quarter everything should have a green light for in project to move forward.

Great. Thank you very much.

We'll go next to Bruce Lanni, AG Edwards.

Good afternoon, gentlemen. I guess, again, circling back to Ciba, just talking about that for a few minutes. What will the additional costs be incurred for Ciba on an annualized basis, and how will this impact our operating costs on a per unit basis?

Bruce, I would rather give you sort of a scaling of what is involved rather than try to estimate year by year. We are talking of perhaps four to six more wells over and above the original plan. To an extent, this is driven by our experience month-by-month as we get to fully manage complexities that we are managing in the field. So I don't want to imply it's going to be a stunningly large number. But it is simply additional wells over and above the previous reservoir management plan, which assumed by the end of this year full development had been completed.

Okay. And then just a couple of things so I understand correctly. What is your estimate for production in 2003 again on a total BOE basis, including the divestitures you are speaking of?

The net average over the full year of 360,000 barrels a day. That compares with the 415 we gave with previous guidance on the last conference call. Just as a throw away, I might mention the January average has been 420,000 barrels a day.

One other thing. When you went three your reserve replacement numbers, if I understood it correctly, are you implying the organic replacement rate is around 30 percent; is that correct?

Depends on how you want to calculate. But the net additions an a conventional basis will be an order of 60 million barrels. But there were a lot of moving parts in that.

And that's on your production basis of 165, right?

That's right.

What was F and D associated with that last year?

Meaningless, given the numbers.

Yeah, okay.

But that's not going to be the case going forward. We will have meaningful F and D costs.

Thanks a lot.

We'll go next to Frederick Leuffer with Bear Stearns.

Good morning, gentlemen. Can you hear me?

Yeah, we sure can. Hi, Fred.

Hi, John. Thank you. John Schreyer said in his remarks there were two parts to the writedown regarding Ciba. The first is the adjustment in the probable reserves and the second is the additional capital expenditures. What is that second part, John, the additional capital expenditures?

This is John Schreyer. That's the extra wells John O'Connor was talking about, and it was $150 million added capital expenditures. Beyond that, which is already in the field.

And what is your proved reserve in that field right now?

81 million barrels to our account.

Okay. What do you estimate to be the earnings impact on 2003 earnings from the BP swap?

In 2003?

Yes.

It will actually improve our earnings. As you heard me say, there is a writedown of the barrels in Colombia. As a result of that, the Colombian asset isn't showing good returns for us. So while the JDA won't have started, the Colombian asset would be showing a loss. So it will be a gain of a little more than $10 million. And that exists for about the next three -- for the next three years.

And what part of the $10 million is below DD and A?

It's all below DD and A.

Okay.

And, Fred, just so you know, I mean the other part on the JDA, besides the pipeline, I think everybody should be aware in a a gas contract already is in place. It would have a gas price of about $3 per MCF and a well head; it's got an oil component to it. And just take our pay that's accumulated already. And the gas is needed in Malaysia, and we are optimizing about the future prospects for future gas growth in that area.

Fred, this is John Schreyer again. The absence of Colombia will reduce our total unit costs -- DD and A unit costs by 20 cents a barrel.

John, if I might, just two other quick ones. The corporate and other expense was pretty low here in the fourth quarter. You know, can you tell us why that was, and maybe give us some guidance for 03? That's the first question. And then the second question, John Schreyer, can you make any comments on what may happen to pension expenses for the company in 2003?

Sure. The corporate G&A should generally average about $15 million a quarter. It and will in 2003. That's on an after tax basis. The fourth quarter, which characterized by a billout of expenses from the corporate center to the business units. That was additional pension expense that had been recorded in the corporate center in the third quarter. So it was all an inner-company transaction. But what it did was make the third quarter expense look high and the fourth quarter expense look low. So it was just bookkeeping at the end of the day.

Okay. And how about pension expense?

Pension expense in 2001 was $10 million. In 2002, it was $20 million. In 2003, it will be $36 million.

After tax?

No. That's pretax.

Terrific. Thank you very much, guys.

We'll go next to Paul Cheng with Lehman brothers.

Good morning, gentlemen. Several quick questions. One on the Cibra charge. What is the pretax number and what is the discount rate that we use?

The pretax number is $706 million. And the discount rate was 10 percent. But let me give you a few more facts. What we had here was an allocation of purchase price to Ciba. It was built on cash flows at the time we did the acquisition. We assumed the production profile was going to be much higher than it is. In fact, we saw the production profile peaking in 2003 and then coming down. So we calculated a value going forward based on that production profile, discounted it, and based on that, we put $1.2 billion of asset value on Saber. On the other hand, we didn't assign much value to exploration. We only assigned $167 million. But it had to go somewhere, Saber looked good and so that value. Subsequently, we have a book value now of saber of $1.4 billion. As you know, the way the test works, you run out cash flows and you compare them to that book value. And for that runout, we used $21 Brent flat and then took the saber discount except in the first year, 2003, where we used the strip, which was $25. We discounted the probables by 25 percent after we did that test trying to see whether we were below $1.4 billion. We missed 1.4 billion by $100 million. Not much, but by $100 million, it is a miss and we're conservative about these things. So we took the writedown. When you do the writedown, you start over with the cash flows which were pretax. You go to aftertax. And then you have to discount the present value of those cash flows. And now we are present valuing cash flows that stretch out over a far longer time than we thought. The value is there, it's just coming in over a number of years as opposed to the first four or five years. And so the discounting really hurts. The end result is a $706 million impair meant, $530 aftertax, a remaining book value of $711 million. If you divide that by the remaining reserves in the field, 142 million barrels. Already said the 81 proves and 61 problems. And it was the 20 that came down in the probs along with the capital that we are going to have to put in the field that caused to us flunk this test. When you take that into account and have 142 million barrels, the life of the field DD and A is now going to be about $8 a barrel.

John, in your final test for the impairment charge, are you still using $20 Brent or are you using a different price assumption?

No. We used $21 Brent. And flat. We didn't escalate it.

You used 21 Brent?

Yeah.

Okay. On the Colombia and the JDA swap, when do you guys expect that to be complete?

That deal was announced -- it's been signed. And it was announced by BP and ourselves.

Do you need the Colombian government approval? I mean, are we going to see the 18,000 barrel going to be gone starting in the first quarter or it's going to be second quarter? I mean, is there any time max?

We don't believe that we will actually close the transaction in the first quarter. So we expect the barrels of associated production there to continue through the first quarter. We would expect, however, that all the approvals will have been obtained by the end of the first quarter. But the deal has been signed, Paul. That's the important thing.

I understand. I understand. Thank you. On the exploration expense in the fourth quarter, given several success wells that you had that seems high at 110. Did you decide using the more conservative accounting to write down a way of orders of discovery also?

Yes, there was some conservatism. For example, the G-13 well in Equatorial Guinea, which is a very promising thing. But at $16 million of cost was expensed, as were G-11, 12, 14, and EG.

How about in the Gulf of Mexico?

There weren't any wells there that were significant. Nope, there weren't any there that were significant. Jedi was written down.

Okay. Very good. Thank you.

We'll go next to Doug Terreson, Morgan Stanley.

Good morning, guys. Circling back to the asset swap between your assets in Colombia and BP's in Malaysia. I was wondering if you could provide guidance as to valuation you expect to receive on your properties and when you expect the transaction to close. And when you talk about reserves and profits, could you also provide some guidance as to how much capital the Colombian properties occupied on your balance sheet?

This is John Schreyer. The value of the properties for the deal is $500 million, more or less. The deal is $500 million, more or less. The value on the balance sheet was $37 million more than that -- I guess 43 more than that, and that's what we had to write down.

And John I think you mentioned that you guys had 30 million barrels. Is that correct or not correct?

There was a reduction in our December 31 reserves of 30 million barrels from roughly 80 down to 50.

Okay. And you expect the transaction to close?

End of the first quarter.

Okay. Great. That's all I needed. Thanks a lot.

Thank you.

We'll go next to Mark Gilman, First Albany Corp.

Guys, I was wondering what in-place recovery rates now apply to your revised prove and probable assessments at Saber?

Hi, Mark. We are using the same recovery rate, 35 percent overall which is a composite for different recovery rates depending on the different lines of Saber.

So in light of the experience you haven't brought that down?

Not the recovery rate, no.

Okay. Let me be sure I understand the probable numbers at this point correctly. You are carrying 61 in probables at Saber after the revision or reduction of 20.

That's correct.

What do you have on the books for probables at O & O and the financials, carrying value aside?

The carrying value we have on it is $500 million. I don't know the reserves and we probably shouldn't go there anyway.

Okay. And the same kind of recovery rate assumed on O and O with respect to which indicator, John, on Saber?

It's actually somewhat more conservative, Mark. We are looking at this stage in the order of 25 to 30 percent.

And why the difference, John?

A degree of conservatism because we have less knowledge of those fields.

Aren't they analogueous, geologically?

Yes, they are certainly from the same age. And they are analogueous, geologically, but we are being cautious until we have more drilling and more performance. The way we're going to manage going forward is conservatively until we gain experience which would justify us being more optimistic. And one other thing, the C-17 well that we drilled most recently on the east bank of Saber, we discovered sand there, fully oil-saturated, not depleted whatsoever of initial reservoir pressure. That has not been included in the reserves numbers which we have discussed. Again it speaks to conservatism at Saber. We don't know the downward limits of that well.

What were the results of G-14?

What were the results?

John Schreyer mentioned you had expensed it.

Oh, yeah. Trace oil, not commercial.

And it was located where?

Northern edge of block G, inboard.

Can you come up with a year-end corporate probable reserve figure, please?

It's not appropriate at this time, Mark.

Okay, thanks, guys.

All right, Mark.

We'll go next to Matthew Warburton with UBS Warburg.

Good morning, gentlemen. A couple of questions, if I may. You highlighted, John, the reduction in Cap Ex for the year 2003 down to $1.4 billion for the EMP segment. Can you give a little bit more detail in terms of which fields are being lowered in terms of their Cap Ex allocation?

Well, I mean, this could be a long discussion, Matthew, because we originally started at a level of about 1.9 representing opportunity. And through repetitive high grading based on value creation, we've come down to the 1.4. It is a cross both producing fields and new developments where we have slipped timing on some new developments, and also obviously to some extent Cap Ex reduced to those assets for sale.

In term of the timing of the new developments can be you more expansive on that, John?

Well, the timing on the developments, I think we were pretty definitive on, which is, you know -- first we have to get approval from the Guinean government on northern block G. As I said we are making a lot of progress in our talks. In the next several months we are fairly confident that plans of development will be approved for [ELON], [OKUMA] and [OVAE]. In 2005 if those approvals are given at the time that I mentioned production should start coming on. At the same time, on the JDA, once the pipelines are let, you know, at the end of 2005, certainly the beginning of 2006, we are fairly optimistic about the JDA production coming on.

Okay. On the writedown for John, is there a split between the PTE, [INAUDIBLE] and the good will?

No. This doesn't involve good will. It involves the allocation of $1.2 billion at the time of the acquisition, and $200 million subsequently to the value of that asset.

Right.

So there isn't a PP&E. I mean there was really a PP&E number in there, but it gets assumed by this allocation. If you look, define what that PP&E number is, it's probably $600 million, 400 initially and 200 since. I think it's important to know obviously we are disappointed with the writedown, but it was very close. It was much more a mechanical item of how we allocated the acquisition price. Having said that, we are very happy with the Triton acquisition. We bought it for the upside it offered. We have secured significant upside for the future in northern block G, and there is for more exploration to come in Equatorial Guinea as well.

And one final question if I may. Obviously you have increased your hedge position on the liquid side to quite substantial amounts for this year. How does the writedown affect any debt covenants you may have?

The writedown is -- the debt covenants are unaffected by the writedown.

Thanks very much.

We'll go next to Mark Flannery, Credit Suisse First Boston.

Hi. I'd like to ask about the -- did I hear about the asset sales, you have 25,000 barrels a day of sales right now including the U.K.?

That's correct.

And you have reached some indicative agreement with the U.K. field; is that correct?

It's actually a signed agreement.

My real question then is, are you expecting to have to take a charge for the sale of those fields at, say, the end of the first quarter?

No.

And presumably, you won't be booking a gain either. Is that right?

I don't want to speculate on that. Let's let the sales occur. I said we would only sell the assets if we got attractive prices.

But you are not expecting a charge?

Again, let's let the sales occur. And when we have the results of the sales we'll book them accordingly.

Okay. And do we expect to see that in the first quarter?

All I can tell you is that approximate sales process for both the shelf and the [JEBUNG] asset are underway.

Thanks very much.

We'll take our next question from Craig Albert, from Osprey Fund.

Hi. Good morning.

Good morning.

Just a couple of points clarification, if you would. The hedge prices that you mentioned. Are those your realized prices or are those WTI prices and what have you done about the basis, if anything?

Nothing about the basis. It is a WTI price. There are equivalent numbers on for Brent as well.

And your differential to those generally is what?

Our differential runs from $1.50 to $2.00.

On oil, and what on gas?

On gas it's pretty close. Maybe 20 cents under.

Great. Okay. You mentioned the impact of the Hovenia and substituting the barrels. What is the impact on your profitability of having to make that switch?

It is not so much the impact to the profitability of making the switch. When you have 3 million barrels a day taken out of the crude market, I think you know in January it was not a good refining month for anybody because the crude oil price was squeezed and went up quicker than the product prices. So refining margins then were poor. How much of it was because we were buying alternate crude oil, and how many was it market conditions? I think that's something that is a hypothetical question. Having said that, now that some shipments of Venezuelan crude have been restored they are more profitable to us at the refinery than normal crude oil. Even though we are not getting full shipments yet in terms of contracted amounts the refining margin now is in the profitable category.

And the impact on runs in the first quarter and beyond?

Well, the runs were reduced for the joint venture to about 360, 350,000 barrels a day when we weren't getting the Venezuela and crude. That is not an economic level to run at. Having said that, now that the Venezuelan crude shipments appear to have been restored, even at reduced levels we expect run rates to increase from the level I mentioned.

Okay is my final question -- thank you for answering so many -- is your estimate for debt paydown in 03?

Several hundred million dollars, subject to the outcome of the moving pieces of asset sales, production, oil prices, refining margin, marketing margins, et cetera.

Sure, and the asset sales would contribute to most of that? I'm trying to get a sense what have the free cash flow is.

As I said, we expect several hundred million dollars of debt paid down for 2003. It is a major forth priority for the company. We met the debt paydown we set for 2002. And it is a major priority and as we fund these exciting projects that offer future growth and income in '05 and beyond.

John, I appreciate it. Thank you very much.

We'll go next to Steve Enger with Petrie Partman.

Hi, guys, how are you?

Good.

I wanted to get more definition on the 25,000 BOE per day that you are looking to sell. Do you have a split between oil and guess and also between the geographic areas, Gulf of Mexico, Gabon, and north sea?

Does that answer your question, Mr. Inger?

I think we'll just stay at the oil equivalent number for right now, and you might go through that John O'Connor, or John Schreyer, who has the numbers handy.

U.K. crude production fourth quarter was a little bit below what I was looking for. Was there any downtime that was significant in the quarter?

I would have John O'Connor -- I don't think we know of anything.

And then last question. Kind of looking forward, appraisal to the G-13 well, first of all, what -- have you given that a different number and more importantly, what the timing on completion on that well.

The well designation, Steve, is G-13-2. Currently completing setting casing. And we're about 12 hundred meters to go then to the top of the objective section. So look for something in ten days or thereabouts.

We'll look forward to that.

Me too.

This is John Schreyer, the answer to the question of the division of the 25 a day between gas and production. 19 is gas and 6 is oil.

Thank you.

We'll go next to a follow-up question from Frederick Leuffer with Bear Stearns.

Two questions. I think I have down here that John O'Connor said there were about 245 million barrels ultimately produced at Ciba. And just looking at your approved reserve, you said 81 million barrels. And I assume that's net. And with the interest that's 95 million barrels. And then you mentioned the probabilities so we're coming up short by 100 million barrels. I'm trying to understand this better, John O'Connor. Are you saying that you think you are going to be proving up more reserves at Ciba or did I get some part of this wrong.

The 245 is the estimated ultimate recovery, E plus P, that's correct. It's not 95 percent. It's the operating -- the basis are all equivalent.

If I work from your 81 million, I'm going to get to the end the probabilities that you gave us, I'm going to get to 245?

The net to oil reserves over the life of the field operation of the PSE is around 72%. Take that plus 245 and end up with the net E plus P to us. which is close to the 142 we were talking about. 245 was the oil in place. Some of it has been produced. Take that away and take the number and where you were where we are at 142 million barrels.

how much have you produced so far?

I don't have that number.

Calculation would imply 35 million barrels. You haven't produced 35 million barrels yet, have you?

That's about it.

Then it adds up. Second question, last question, John Schreyer, what do you estimate for DD and A company-wide for 03?

$1.1 billion.

And to that, to get 9 cash charges to that $1.1 billion, you need the add about another $300 million for dry holes, deferred taxes and lease amortizations. So a 9 cash charge is about $1.4 billion, about the same. A capital expenditures at 1.45. Yep. Super. Thank you very much.

We'll go next to a follow-up question from Mark Gilman, First Albany Corp.

Just wanted to clarify a couple of things. John Schreyer, you indicated that this impairment leaves good will intact?

Yes.

Correct.

That's correct.

So that the number at year end is about $1 billion?

Correct.

John O'Connor, if -- have you cut the water injection rates back at Ciba?

No. On the contrary, one of the challenges we had in managing this reservoir was the high initial production from the field prior to water injection starting up. Our management philosophy is to replace as much as that water as possible. Hence we are lowering the oil offtake and increasing variety injection. During January we have been running at 120,000 barrels a day of water injection. The facilities are running at 98 percent capacity and we intend to keep going on that. We will be adding more injectors to avoid any -- to fill the voids that the field has. We have a breakthrough we think is a stringer with a high permeability streak. The injectors' completion has the we inherited in the field were open across the whole of the face section. Going forward we're going to look at smart well completions where we can inject the water where we want it to go.

There any completion plan for [SHENZI] in place?

Yes.

And that will be drilled when?

We are not the operator, but I look for that probably around March.

Is there an E and P tax rate applicable in this quarter? I didn't hear you if you answered.

Worldwide EP is about 40 percent. But going forward, we anticipate in large part because of the increase in the U.K. that E and P effective tax rate will be in the 45 percent tax range.

And why wasn't that reflected in the fourth quarter?

And it was. I misspoke, but not for the full year. It was reflected in the fourth quarter.

All right. So the -- the fourth quarter rate was what?

45.

And that's the going forward rate?

That is the going forward rate. What I misspoke about was the rate for the year as a whole.

Thanks very much.

Yep.

And we'll take our final question today from Jeff Bellman with SAC Capital.

I had a question about your U.S. natural gas volumes if you could help me understand the fourth quarter versus fourth quarter drop of 436 to 320. How much of that was natural decline and how much of that was maybe hurricane affected?

We'll get you the specifics. I'm sure part of it is LLOG, that's performance related. But John O'Connor -- I think about 60 of it is LLOG?

We had a natural decline from some of the Gulf of Mexico fields is the rest, and lock was about 60 a day.

Thank you. So hurricane was not much of an impact.

It was about 16 million cubic foot a day.

I'm sorry, 16?

Uh-huh.

Thank you very much.

Okay. Well we appreciate your attending the conference call today and we look forward to updating you on our progress on our developments as we reshape the E and P business for sustained financial performance. Thank you very much and have a good day.

Again, ladies and gentlemen, I'd like to remind everyone that you may listen to a rebroadcast of this conference at 1 p.m. eastern time today through February 6th at midnight by dialing 719-457-0820. Or you may dial 1-800, 203-1112 and enter confirmed code 683401 on your touch tone telephone. That does conclude today's call. You may now disconnect at this time.