赫斯 (HES) 2003 Q2 法說會逐字稿

Welcome to the Amerada Hess quarterly conference call. Today's call will be reavailable for rebroadcast at 4:00 p.m. Eastern time, running through August 6th at midnight. You may access the replay by dialing 719-457-0820. Or toll free 888-203-1112. And enter the confirmation code 426643 on your telephone. All media will be in a listen-only mode for duration of the call. Media questions should be directed to Carl Tursi at 212-536-8593. The webb cast of the call will be available on hess.com for 30-days, a transcript of the conference call will be available on the company's website for one year.

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

Hello, thank you for participating in our earnings conference call for the second quarter of 2003. 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; John Schreyer, Executive Vice President and Chief Financial Officer; and John Riley, Vice President and Controller. Also sitting in on the call is Jay Wilson.

John Hess will present an update on strategic initiatives. John O'Connor will comment on upstream activity. John Schreyer will then review second quarter results after which, the call will be open to questions. Certain forward-looking information and other previously undisclosed items may be discussed during this call.

I will now turn it over to John Hess.

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

I would like to make a few brief comments regarding the progress we are making in reshaping our portfolio. I'll then ask John O'Connor to discuss some of our exciting development and exploration prospects and finally John Schreyer will review the second quarter financials before we open it up for questions.

We continue to make progress on optimizing our portfolio, with the goals being: to add low cost reserves and production, lower our unit cost, lengthen our reserve to production live ratio, and ultimately, to significantly improve our financial returns. This type of change does not happen overnight. But, we have been disciplined in implementing changes that will allow us to achieve these goals.

First, let me touch on asset sales. During the second quarter, we closed several transactions, including the sale of our gulf of Mexico shelf properties for $260 million. We also divested our 30% interest in the Gabon PSC in Indonesia. The Montrose, Arbroth and Arcright [ph] fields in the U.K. sector of the North Sea. And AVLCC. The upstream assets sold were in mature areas and were either noncore or high cost. Net proceeds totaled approximately $500 million. The proceeds will provide capital for investment in the development of new fields, as well as to reduce debt.

Also, in the second quarter, we announced the transaction with Incana [ph] through which we will reduce our exposure to the North Sea and add exposure to the deep water Gulf of Mexico. We will swap Incana [ph] a 14% stake in the Scott and Telford field, plus an exploration block in exchange for a 22 1/2% stake in the Lano [ph] field bringing our interest to 50%. In addition, we will receive another deep order exploration unit and $17 million in cash. Lano [ph], which is operated by Shell is expected to come on stream in mid 2004 at a net rate of 20,000 barrels of oil equivalent per day. This transaction is important because it will increase our exposure to a lower cost and more profitable asset with greater upside.

In addition, this transaction enabled the restructuring of our U.K. operations which is expected to result in annual after tax savings of an estimated $30 million.

Let me ask John O'Connor to comment on our update stream activities.

Good afternoon. A key proponent in reshaping our portfolio is the substantial state of the developments either underway or nearing sanction which will contribute new production and cash flow, beginning in the 2005-06 and continuing thereafter. I would like to highlight these projects this afternoon and also update you on our exploration activities.

First, Luck- A-18 in the Malaysia Thailand JDA area. As you know the offshore facilities are installed. Various transportation facilities have been contracted. And the pipes have been fabricated. We expect pipe lengths to be substantially completed next year and gas production to commence in the mid2005 time frame at a net rate of 160 million cubic feet a day.

Importantly, we have discovered nearly five TCP resources net to us, but we have only booked about 900 B. We fully expect to contract the remaining gas, which will result in additional reserve bookings and production for years to come. In Equatorial Guinea, the field Saber field is performing as expected with net production expected to average 25,000 barrels a day this year. We are optimizing the water flood, scheduling the installation of sub-C pumps at year end. We've got several more wells to drill.

With regard to northern block G. We continue to refine our development plan. Since our last conference call, we have done a significant amount of subsurface and engineering work which has caused us to believe there may be a better alternative than development of the field and submitted in our POD. The government of Equatorial Guinea fully agrees with our assessment. We plan to drill a number of wells in the second half of the year. The additional data from the drilling program, along with a new high resolution seismic survey, will provide us with an improved understanding of the overall resource potential. And will allow us to install the most appropriate facilities, best locations to optimize the development.

A new project, which will contribute to production in the '05-'06 time frame is the Panca [ph] field in Java, Indonesia. Production startups projected for the second half of 2005 at a rate of 50 million cubic feet a day net to our current 66% interest. A gas contract has been negotiated with the buyer. East Java has a growing gas market and we expect to see increased gas sales from the Panca [ph] fields.

We also have an interesting opportunity on shore Thailand where we operate two whole blocks in the northeastern part of the country with a 40% interest. Recent drilling indicates the existence of gas and commercial quantities. We plan a follow up well at the end of the year. Preliminary plans are for protection to commence in 2005, with the gas being sold to the local par generation market.

Ongoing developments of which you are aware, which will strengthen our portfolio include Bowhow [ph] and Clare [ph] in the North Sea, ACG in Azerbaijan, (inaudible) in Algeria, and Blano [ph] in the deep water gulf of Mexico. In addition, we are working to bring (inaudible) in the U.K. sector of the North Sea to sanctions this year. The first production projected in 2005 reaching 20,000 barrels of oil a day equivalents net to us in 2006.

Now, moving onto the exploration program. As you know, we are focusing on high impact prospects which will make a material difference to a company of our size. We are encouraged that the first three wells in this program have found oil. Chemzi [ph] and Chinook in the Gulf of Mexico in the U.S. and G13 in Equatorial Guinea. Let me mention a few of the prospects that we will drilling in the second half of the year and give you a taste of what we are doing. We have a 20% interest in the Jupiter Bells prospect of Mississippi Canyon, Block 725, which is currently drilling. The well is in 4,360 feet of water, expected to reach TD shortly. We expect to spot an appraisal well in the Chemzi [ph] discovery in Green Canyon block 654 during the second half of August. The well should take about a hundred days to drill. PHB Operations and we have a 28% working interest. Chemzi [ph] One well was drilled at the end of last year in 4400 feet of water. Anything countered 140 feet of net pay.

We expect to spot the Jeep 13-3 appraisal in block G in Equatorial Guinea in the fourth quarter. Drilling results on the prospect thus far have been encouraging. We believe that we have got a very good portfolio of development projects and exploration prospects. This allows us to successfully diversify away from the mature provinces which have traditionally been our main stay. We now have a stronger opportunity set in which to vest which, over time, will allow to improve our financial return.

And now John Schreyer will review the second quarter financials.

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

Turning first to consolidated results of operations and consolidated cash flow. Net income for the second quarter of '03 was $252 million. Including gains on asset sales which gains are included in discontinued operations. Income from continuing operations was $63 million this quarter. This income includes charges totaling $43 million for severance and related costs and a loss of the sale of our interest in a shipping joint venture. Income from continuing operations excludes $14 million of operating income from assets prior to their sale in the second quarter. This $14 million is included if discontinued operations. I will discuss income in more detail in a minute.

Turning to cash flow, net cash provided by operating activities in the second quarter including $205 million of cash from working capital changes was $571 million. Cash provided from assets sales was an additional $500 million. The principle uses of cash were as follows. Capital expenditures $367 million. Debt reduction after funding the capital expenditures $207 million. Cash dividends $27 million, and other items of $11 million. The net increase in cash in second quarter was $481 million.

We have repaid $350 million of debt in the first half of '03 and our June 30 cash balance was $677 million. As John Hess previously said, this cash will be used for future capital expenditures including field developments and further debt reduction. Our debt at June 30 was $4.64b and 50.4% compared with 54% at the beginning of the year.

Exploration and production. Net income from continuing operations or EMP activities was $88 million in the second quarter of '03, compared with income of $120 million in the first quarter. This income from continuing operations includes a $23 million charge in the second quarter of '03 for severance, primarily in the United States and the United Kingdom and a reduction of leased office space in London. The first quarter of '03 includes $31 million gain on the sale of our interest in the Alaska pipeline. Excluding these items, EMP earnings from continuing operations were $111 million in the second quarter of '03, compared with $89 million in the first quarter. The components of this change, on an after tax basis follow.

Our average crude oil selling price decreased by approximately $1.10 per barrel, including the effect of hedging. That reduced earnings in the second quarter by $21 million.

Average natural gas prices were also lower, reducing earnings from the first quarter to the second quarter by $10 million. Production volumes were lower, reducing earnings by $9 million. In the first quarter, we had -- we underlisted our production. Inventory was at a more normal level in the sec quarter and when you compare quarter to quarter, that increase second quarter's earnings by $22 million. Exploration expense was lower in the second quarter, increasing earnings by $13 million. Our effective income tax rate was also lower, also increasing earnings by $13 million and all other items increased second quarter earnings by [indiscernible] compared to the first quarter. All in all, the increase in second quarter, adjusted income from EMP operations was $22 million over the first quarter.

Turning to oil and gas production, which is shown on page five of our press release, in the second quarter of '03, crude oil and natural gas liquid production was 260,000 barrels per day, compared with 295,000 barrels a day in the first quarter. Natural gas production in the second quarter was 695 million cubic feet a day, a decrease of eight percent from the first quarter. Approximately one half of the production declines are due to asset sales and the asset exchange.

Production of oil and gas on a barrel of oil equivalent basis was 376,000 barrels per day in the second quarter of '03, compared with 421,000 barrels on the first quarter. Full year, 2003 production is presently expected to be approximately 360,000 barrels per day.

Exploration expense was $88 million in the second quarter and $194 million in the first half of 2003. These costs are higher than in the comparable periods of '02, when more of our drilling program took place in the second half of the year.

Our planned exploration spent in '03 is approximately $315 million and our forecasted exploration expenses including leased amortization is approximately $350 million. The effective income tax rate for exploration and production operations in the first half of '03 was approximately 49%. This rate is higher than the United States statutory rate reflecting an increased proportion of E&P earnings from foreign jurisdictions with higher income tax rates such as the United Kingdom and Norway and a lesser percentage from United States sources. All of the corporation's hedgings results are included in the United States tax return which reduces United States taxable in come this year. We anticipate that the full year '03 effective EMP rate will be comparable to the first half rate.

The after tax impact of crude oil and U.S. natural gas production hedges in the second quarter of '03 was an opportunity cost of $45 million. That's $1.80 per barrel of oil equivalent Compared with a cost of $102 million in the first quarter.

The status of our hedges at June 30th is as follows. For the remainder of 2003, 65% of our crude oil is hedged, none of our natural gas is hedged. For the year 2004, 55% of our worldwide production of crude oil is hedged, none of our natural gas. The average price for TI related open hedge positions is 24-29 in 2003 and $24.33 in 2004. The average price for brent [ph] related open hedge positions is $23.61 in '03 and $23.30 in '04. Approximately 20% of the corporations hedges are TI related and the remainder are brent. [ph]

At June 30th, we have an after tax deferred hedge loss. It totals $141 million. $24 million of that is realized. The remainder, based on June 30 prices of $117 million, is unrealized.

Turning now, to refining and marketing. Earnings were seasonally lower in the second quarter of '03 as anticipated and amounted to $46 million compared with $136 million in the first quarter. As explained in our earnings release, the second quarter includes the loss of $20 million on the sale of the corporation's interest in a shipping joint venture. Over 50% of this loss was related to a special tax provision. The corporation share of [indiscernible] income was $15 million in the second quarter, compared with $50 million in the first quarter. R&M earnings include $8 million of interest on the [indiscernible] note in each quarter. The balance of the note at June 30th was $364 million and principle and interest payments are current.

Retail operations were more profitable in the second quarter of '03 than in the first quarter. Energy marketing activities were profitable in the second quarter of '03, but earnings were lower than the first quarter, which benefited from the cold winter. After tax trading results amounted to a loss of $6 million in the second quarter of '03 compared with income of $18 million in the first quarter. Corporate expenses were higher in the second quarter of '03, compared with the first quarter. As indicated in the press release, $8 million of after tax expense from the early repayment of debt was recorded in the second quarter. The comparable amount in the first quarter was $3 million.

And finally, general and administrative expense was $106 million in the second quarter of '03 and $77 million in the first quarter. This increase reflects the inclusion in the second quarter of substantially all of the pretax charge for severance and the reduction in leased office space. This charge was $38 million on a pretax basis. The reduction in force that it reflects includes the elimination of approximately 30% of employees and contractors in our exploration and production operations. Additional severance and lease costs of approximately $20 million on an after tax basis are anticipated over the next several quarters. The estimated annual after tax savings from this cost reduction initiative is approximately $30 million.

This concludes my remarks. I will now ask the operator to prepare for questions and turn the meeting over to John Hess.

Today's Q&A answer will be done electronically. Press the star key followed by the digit one on your touch tone telephone.

If you are utilizing a speaker phone, be sure your mute button is turned off. Let's go to Arjun Murti with Goldman Sachs.

Thank you, John, you noted that you were (indiscernible) seismic and some additional drilling activities caused you to refine some of your blocked G plans. Do you have a new estimated startup date for that. I think you are aware there has been some trade press speculation it's going to be delayed to '06. And then, has there been any change to where you think those volumes will come on when they do come on.

John O'Connor, I would be happy to try to answer that, Arjun.

Thank you.

Just to make it clear, I wasn't sure in your question if you had said we had [indiscernible], what we are talking about doing is an incremental work program, which would involve additional drilling at a new high rez [ph] spot program still to be undertaken. As far as the onset of production is concerned, I would say there is a range of first production dates, probably in the vicinity of the latter half of '05 to the second quarter of '06. When we have the development plans tied down and finalized, we will be better able to pinpoint a startup date. It is dependent, obviously, of coming up and satisfying our part with the government that we have a developed plan. As to startup rate, it is likely that additional drilling program would facilitate higher rates than we previously estimated. That's one possible outcome of the additional work program we are undertaking.

One more question if you don't mind. I believer Mr. Schreyer had suggested a 365,000 barrel a day full-year production guidance for '03. That implies 330 second half. Do you have any updated '04 or '05 similar type billing numbers?

No, we don't, at this stage. We probably would be looking at the back end of this year before we are ready to come out with the forecast for the following year.

That's great, thank you very much.

We'll go to Steven Pfeifer with Merrill Lynch.

Hi, guys, two questions. I wanted to follow up on Arjun's's question, you guys when you made your adjustments went to 360 thousand barrels a day and if the first half, you have been running close to 400, which implies 320 in the second half. know the divestments are part of the story, here, next to divestment, I guess, in the second quarter are probably running close to 360. Even after the divestments that would suggested a fairly sizable dropoff in the second half. I guess what I'm getting to, are you still being conservative on the 360 or do we need to see a fairly steep drop in the second half to get to the 360 for the second half of the year?

I think the answer is probably between the two. There may be a little bit of upside in the overall 360,000 forecast, but we went into the beginning of the year before the front end of the year projecting 360. We stayed with that at the first quarter conference call. Staying with it, now. There is no down side to that for the full year, but there will probably some upside, Difficult qualifying at this stage and I wouldn't like to put a number on it. But that's one explanation. As far as the the exit volumes at the end of the year, we are looking to them being somewhat higher than you calculated.

Okay, perfect, my last question, could you give any sense for what transactions have you done to unit costs and unit CD&A [ph] when you look at stabilized run rate where you were and where you think you are, now.

John Riley will address that.

Hi, Steve. As far as the unit cost this quarter, we ran about $16.90 and for the first half of the year, we are about at 17. For the short term, because of the reduction in the production of these asset sales, in the short term we will have a trend of unit costs that will increase. And then as a result of the asset sales and also the reorganization that we talked about in the severance accruals, when those begin to take full effect, that's when we begin to see the reduction in the unit costs going forward.

Okay, thank you.

Paul Cheng with Lehman Brothers.

Hi, guys. John, I'm wondering if you can break down the 14,000 barrel per day of the discontinued production in the second quarter by regions?

Okay, Paul, we'll try to get that broken out for you.

Also, I was looking at -- while you are trying to do that -- I was looking at the U.K. -- does natural gas output in the U.K. that was really impressive typically from the first to the second quarter seasonally which is a big drop. Is there any particular reason why you can see that?

On the natural gas in the U.K., John O'Connor will answer that while we are getting the answer to your other question.

Hi Paul. A couple of things actually and we're pleased to see the number. One was as to the report as to the end of the first quarter, we are seeing sales volumes of gas from the barrel complex rather than being reinjected, this gas is going to [indiscernible] continue to the second quarter, which is what untraditional. The other source, of course, is that we commissioned the Juneau fields earlier in the year. They have been ramping up. We have better deliverability and strong denominations for a number of those fields in the Juneau complex.

[Indiscernible] Is that sustainable or is that going to be back to normal?

I'm sorry Paul. You were garbled for the first part of that.

Yes.

Say that again.

No I think that -- you say that's two reasons why the U.K. gas production is so good in the second quarter.

Yes.

The part -- the first one is that one of the fields that the gas is not going back into the reservoir, you saying that is somewhat of an abnormal phenomenon. Is that going forward that you would continue to do that or that you will have, at some point have to reinsert the gas back into the reservoir.

To some extent, that will be dependent on the operator, Exxon Mobile, obviously and what their call is. But I think so long as we see a strong gas market in the U.K. that makes it appealing to move the volumes into the market rather than reinject them, I expect that to continue.

Okay. Thank you.

And on the other question, John Riley.

For the 14,000 barrels day that you were seeing in discontinued operations, 11 of that is in U.S., two of that is in the U.K. And one with Gabon.

And John, do you have a breakdown in the U.S. between gas and oil portion?

In the U.S. between oil and gas?

Yeah.

It would be seven BOE for gas and four is oil. You have to remember, Paul, that's our prorated basis. It depends on the timing.

Sure, I fully understand. Maybe for John O'Connor, can you tell about what Algeria -- the role that in your new portfolio is going to look like if Algeria is one of the core areas that you are going to do more -- try and expand your footage over there. Or are you satisfied with what you have or over time, even exit from there.

Paul, you I think, first of all, we have been, long-term partners. Secondly, the project is turning out to be very attractive in terms of what it's delivering to us. And thirdly to get to the heart of the matter, we would be delighted to find more similar opportunities and we would look to see more growth in Algeria.

Very good, thank you.

And we'll next go to Don Textra [ph] with Dorset Asset Management. afternoon, everybody.

Let me back track, I have two questions, back track to Equatorial, was it tying in all the well control subservice geology and EGs that caused you to slow up the development of the project? I mean it sounded like the 3-D's still to come, so I was curious. The first part of the question is what precipitated that is this.

There are a couple of things. We have done increasingly subsurface work and geo-modeling over the past six months. That has identified a couple of things. One is a series of opportunities where we see prospects in the vicinity of the known fields which have come up more clearly than we previously saw.

These are additional prospects in the first fixed field?

Exactly. More drilling opportunities that had not been contemplated at the time. We think it's prudent to test those in case they have an impact on the geometry of the concept. Second thing is as we look at the seismic that we had, we can see room for improvement, and rather than wait for a new survey, we have decided to drill in locations which will help to give us confidence as we extrapolate from the data we have.

Does this imply extension of the existing field, maybe that they -- the general shape and extent could be somewhat different from the original goal?

Yeah, I think we see potential extension. That's some of the testing work that we would like to do, Don.

Okay, and the program itself will start off when?

We expect to start the first of September. We are going to run two rigs on this. We'll take the 700 from the Saber field whether it is finished completing the well it's currently working on. That will move into northern G2 block.

Do you have any idea how many wells you might drill?

I would say six would be a good approximation.

Okay, and after that, you will get to the third well at G 13?

No, actually, what we are looking at doing, quite frankly, taking partner interest into account -- what we would like to do is drill the first of the deep water wells in northern block G with the 700 and move it back down to test G 13. You might say we have an abundance of opportunity and it's a tease as to which we go after first. N

You might switch them back and forth.

yeah, I think for planning purposes. We are looking at spotting the G 13 in the Beginning of November. 60-DAY wells. We would like to have the results of that by year end.

One of the things I wasn't sure of on the JDA, you mentioned 160 million a day. Is that a net number?

That's a net number at plateau. When the field is delivering it's contract quantity, it's 395. So probably for clarity, the field will come onstream in '05. It will ramp up volume -- It will hit plateau in '06 and our share of that will be 160 million cubic feet equivalent.

So about 26,000 barrels a day net.

Yes.

In phase one?

Correct.

Do you have any idea or any indication in terms of when the Malaysians might want to go ahead with phase 2? There has been some talk that if phase 2 following fairly rapidly off of phase one.

I think that both countries have growing [indiscernible] for natural gas. They're going to have on their doorstep a very sizable resource, pipeline connected to the pipeline that has initial capacity double initial sales volumes. So although we don't have any firm information on this, I think it's reasonable to expect the second phase of gas from the field will follow on fairly closely.

Great, thanks, John.

Thank you.

We'll next go to Fred Leuffer with Bear Sterns.

Good afternoon, John, I guess with the new plan for block G development, when might you expect to submit an approval plan for the government?

You know, we have been working very closely with the ministry and the national oil company on this. They have been working hand and glove with us on this. We spent a lot of time in their country. I don't think that putting a date on the submission and them trying to work out a lag time is going to be as difficult as you might have thought. I think this will be a parallel process. I expect it to be the turn of the year when we submit it. But, I would think think at that time they would be fully informed.

All right, you indicated additional reserve bookings likely here on A 18, but that's probably not going to make it this year, right?

That's right. We would want to contract those volumes before we book anything.

Looks like block G has knocked out maybe for bookings to next year -- what do you have that you think might help reserve placement in '03.

I think we'll talk about it later in the year.

If I could ask John Riley, how much would you expect unit production costs to run from the 16.90 level?

We don't have that forecast, because we are working out with the severance cost, the people and the way the portfolio is shaking out. So, short term trend, as we say, will be going up and start to come down as reorganization takes place.

I think the key points is with the reshaping of the portfolio, asset sales of high cost properties, new developments coming on, starting in '04, then '05 and '06 and it's toward the trajectory towards the target that we have of $12 about. It's not going to happen overnight. There are a lot of moving pieces, about you this will have a significant effect over the next several years.

Okay, thanks.

We'll next go, then, to Jay Saunders with Georgia Bank.

Thanks, most of my questions have been answered. One small one here, on potential reserve additions this year. I think there is an additional portion to be added at Lano [ph] this year. Is there a number for that outside of the swap? More reserve there?

In other words what's the net change in reserve between Lano [ph] and the sale of Scott?

That's right, but I thought there was a 20% that wasn't booked, yet, that you guys were going to book this year.

I don't think there is a difference in reserves. The upside of the reserves we referred to will require more drilling.

So it's a wash?

yes.

Okay, thanks.

Thank you.

We'll next go to Mark Flannery with CS First Boston.

Yes, I have two questions. First is on natural gas hedging. I notice the portion of your gas hedge does not fallen to zero percent and earlier in the year, I believe we were just shy of 50%. Can you explain what's going on with the hedging philosophy? How you are making those decisions and how we might expect you to make them in the future. I have another follow-up question.

I believe in the second quarter, there was an opportunity cost of about a dollar in MCF, whereas in the year earlier, it was a comparable amount the other way. The point on natural gas is when it was a bigger part of the portfolio, just like oil, with the developments that we have on our balance sheet, we want to protect the revenue until we get the developments to generate the cash flow and we would be probably more comfortable with a lower hedging level. Once the properties in the shelf were sold, we had less gas exposure. Since it's at a comfortable amount, we are comfortable leaving that unhedged. When prices started to come down, we took the remaining hedges off once the properties were sold in the gulf. On the oil side, it was a bigger risk and we can't predict the oil prices and since so much of our cash flow is determined by oil production prices, we will continue to hedge during this time where we need the money for developments as well as paying down debt. Once that's behind us and our debt cap gets to lower levels, we'll look to taking the hedge percentage down.

My follow-up question is what's going on in. U.K. with the reduction in the present state. Is there some general change in strategy to get out and kind of wanting more operatorship type projects over there? It's clearly something else going on.

the U.K. Has been and will continue to be a very important part of AmeradaHess going forward. We are talking about reshaping our portfolio to get longer life. When we find properties to develop, be it in the U.K., the U.S. or outside of those areas, we will, as long as the unit cost and reserve life meet our criteria. The assets we are keeping in the U.K. are the ones that meet our criteria of lower unit costs and longer life. Some we will operate some we won't operate. We were built for a much bigger operation in the U.K. and as we weren't finding, if you will, a Scott field every year. We had to right-size the organization for the portfolio that we saw going forward also meeting the criteria we had on unit costs and reserve life. So, point take away, UK is important, will continue to be, in fact, we're actually applying for an exploration block in the current licensing round. We are awaiting word on that so our commitment to the UK will be there as it has been in the past. But right-sizing the portfolio and right-sizing the organization are key for us to have the unit cost performance that we have to have for financial performance in the future.

Right, thank you.

Once again, star 1 for a question. If your question has already been answered, you may remove yourself from the question roster by pressing the pound can. We'll next go to Albert Anton with Carl H. Forsheimer.

I wonder if there is something nonrecurring in your production expenses. In the second quarter, production expenses were up 15% and production was down nearly 20%. It just doesn't look right.

Al, this is John Riley, production expenses for this year, there's a couple of items to address if you are comparing them to '02. We do have a portion of our severance accrual in there, is approximately $6 million of costs in production expenses in the second quarter, relating to that reorganization accrual. Also, when you a comparing to the prior year, it has to do with transportation costs in the U.K. -- There is two parts to the transportation costs. One is it's payable in sterling. So, based on the exchange rate between a dollar and the sterling, we have had an increase in costs in our transportation. Also, our transportation costs in the U.K. are linked to oil prices. There has been a rise in oil prices from the prior year and that's driving an increase in costs. And just like most other companies, the insurance costs due to hard market has increased our production costs this year.

We'll next go to Mark Gilman with First Albany.

If the change in plans was recently in northern block G, it's primarily associated with the evaluation of additional opportunity on the assumption that you are reached a development threshold with respect to activities to date, why didn't you consider proceeding with a phased development, there?

I don't want to leave anybody with the wrong impression. There is information requirement together with recognition of peripheral and other opportunities in the vicinity. So, it's not just the one. It's both and it just seems to us that increase the degree of confidence we all would have in this, it is worth getting that information now, rather than further down the road with the architecture of a production system.

You got to help me with something else. If we are divesting high cost properties, maybe John Riley could be a little more specific as to why unit costs will be going up.

Sure, again it's very difficult as we are divesting the high cost properties. Production is obviously dropping. It's difficult for us to keep up at the same pace reducing costs at the same pace that our production is going down. This year, we have announced some of these changes, obviously, completed the asset sales, but as our fixed cost base, that will not be -- you won't see reductions in that until 2004. Even at that point, we are assuming 2004, maybe we'll get 60% of the savings and we wouldn't get 100% of it until 2005. So as John Hess mentioned with the portfolio and changes going on that will result in unit costs starting to move towards our long-term target.

Maybe we could visit on the tax issue for just a minute. The 49% is lower, John, than what I believe we talked about at the first quarter, but is still above statutory rates and in all areas that the company has upstream operations. Do you want to take another shot at giving us an idea of why it's even that high?

Okay, from our basic tax rate from a basic premise -- Let's look if you are comparing this to a typical independent group, more of our operations are global and therefore, our income is in more of the foreign jurisdictions that have statutory rates and let's say than 49% such as Norway and Thailand. Those are higher than 50% and even in the U.K. when you factor in some of the special taxes, our effective rate in the U.K. is in the upper 40's. What then -- after you take that basic premise and compared to some of the integrated, we are in a comparable basis, but in as John Schreyer mentioned, we have the hedge losses. What that is effectively doing is reducing the amount of our U.S. income in proportion to our foreign operations and, therefore, we are taking out the 35% tax rate and leaving only the higher tax jurisdictions. That is the primary driver of why our rate is up.

one more, if I could. I guess I don't quite understand why interest expense, as reflected on the income statement in the second quarter, given the funds surplus of significance in the quarter is actually up from first quarter levels.

It's lower capitalized interest.

And that is, John? $5 million.

$5 million lower or absolute? Absolute of less capitalized interest. There was 8 in this quarter versus 13 in the prior quarter.

Thanks very much guys.

We'll next go to Steve Enger with Petri Parkman.

Hi guys. A couple of things. On JDA, are there any key hurdles yet to be cleared or is your confidence now high that you are on a clear path for a mid '05 startup?

I would say we are on a clear path to a mid '05 startup. I did mention that the site for the gas separation plant is also being worked on. That's probably the most critical item of the critical path. Everything at this stage looks like the parties are committed, work is underway.

And Steve, our group, the operating group CTOC [ph] has periodic meetings with the operating group for the buyer on construction progress. So, I would say that information is pretty live and pretty current.

Great. You mentioned Panca [ph] and also potential for onshore Thai gap production. Can you talk more broadly, are are there other opportunities you see based on discoveries you have made in the past based on more gas sales in Asia.

I think the first place to look for more gas sales is in Asia, is JDA, which is a huge gas standard. With respect to both Panca [ph] and Gabon, I think we will be upside in both of those areas because of the matching to the market. I think the market will accept pretty much upside gas volumes yet to be established, but we believe will be established. I'm not sure over and above that -- yeah--

The biggest opportunity is we obviously have huge amounts of far gas available out of the JDA and as John mentioned, both Malaysia and Thailand, we think, will be pretty ripe as we go out past '07.

Okay can you put any -- can you give us any sense for what you see onshore Thailand?

I don't think we can go any further than what we are saying, Malaysia and Thailand have indicated to us that their demands going forward are getting stronger.

Okay, can you update me on Clare and Voltal [ph] in terms of production impact and in the case of Clare what you see a startup?

I would be happy to do that. The Clare project, we are happy to say, is on schedule and on budget. Sail away is scheduled for May next year. Upsides are on track. So, we look to see first production there, on time, on schedule fourth quarter next year. As far as Bowhow [ph] is concerned, problems with the piling, we believe, have been resolved. We believe we have a good schedule there and we are also seeing initial production from some of the wells are coming in. We feel good about Bowhow.

And what kind of rate increment might you see over there over time from Bowhow?

I think that the first thing is that we are going to see rising volumes, so, the first big impact is that we are not looking at any signs there. Gradually rising rates in time. A lot of it will be with respect to the performance of the individual as they come in, but it might be in terms of our share, something like a 10% upside versus today's volumes.

Great, thank.

We'll next go to [indiscernible] Morgan Stanley.

it's Akeba Cowen. You referenced a $205 million decrease in working capital in the quarter. Could you provide some details as to what the components were.

Sure, if you remember from our downstream operations in the first quarter we had, due to the cold winter, we had a very strong operational quarter and at March 30th, we had receivables, basically, on the book reflecting our increased sales and the $205 million is the collection of those receivables in the second quarter.

okay, great. In terms of debt repurchases, if you could give us an amount of principle that you repurchased in the second quarter and what plans are for the remainder of the year.

Sure, as John Schreyer mentioned earlier, we have $350 million of debt that we reduced for the full six months. In the quarter it was $207 million. Just to add on, we repurchased about $670 million worth of our debt last year, so, over the last 18 months, we have had more than a billion dollar reduction in debt.

On block G, this is reading the trade press, the article referred to block G as complicated reservoir issues, and said that they feel it's analagous to the Seba [ph] field and I guess I'm trying to understand -- the way that that article read was a clear negative tone versus, I guess, the way that it's being presented to the analysts this afternoon basically highlighting the upside and just wondering if you could kind of close that information gap, there.

Again, I reiterate I don't want to highlight any upside. I want to portray a balanced view of the opportunities and some of the challenges in northern block G. Yes, the geological setting is analogous to Seba, but we don't view that as a disadvantage. We have demonstrated how to order flood savers, how to produce it and optimize recovery from that field. We are obviously going to recover from those learnings. We are confident we can develop it at a profit.

I guess, in terms of production levels, cost structure, and so forth, right now, there is no change and the only change that we should be thinking about at this point is timing?

The pieces are in place that the cost reduction starts in '04 and builds even more in '05. Also production increases over time, as well, plus, the new developments coming on '05, '06, start to contribute to a material change in the unit cost. And if I may, we have other people waiting on the phone, I this I what would be appropriate. We'll try to make your question tight so we can move onto the next question.

Thank you.

We'll next go to David Wheeler with JP Morgan.

I have a couple of questions. John O'Connor, you referenced the possibility of higher volumes with additional fields. My question is, you guys, back in April had alluded to a 30,000 barrel a day number for the 00 and E fields, are you telling us that the rate for those three fields are likely to go up or down?

Let me clarify what I was saying. I was saying as a result of drilling programs. Not from any potential field. From the drilling program, all of those wells will be infield to help us optimize the existing fields. They have the outcome we presume they will have. That means more producers than we earlier talked about. Therefore, we would expect higher rates. Obviously, if there are other discoveries wrapped into the development at the same time, that would be added to it.

But obviously, those additional oils come at a cost. In terms of the cost for EG, we should be expecting higher development costs, I imagine.

Possibly overall, but not in unit terms. We are trying to find nonincremental costs.

Okay, very good. Are we still anticipating to save a field will be sustainable at 25,000 barrel as day for several years, or do we think this is going to start to decline a little sooner?

Certainly not going to decline over an extended period. We think we can look to this rate for a number of years if not somewhat higher.

Last question for you, on the cost structure, again, back in May of '02, I think costs were running between 14 1/2 to $15 a barrel and you set that target of 12 and now costs are 2 or $2.50 higher. Is that $12 target still realistic to have?

It's a target. It's a multiyear initiative and that's a target we are going to keep shooting for. All I can tell you is the different pieces we have in place over the next 3 to 4 years. They are going to close a lot of the gap.

We'll next go to Mark Tibbel with Park Place Capital.

Good afternoon. Could you help me understand where the additional 40,000 barrels a day of decline is up coming from for the second half of this year and what would be your exit rate in terms of production for 2003?

For the most part, the reduction in the second half of the year is due to the asset sales that we had mentioned. If you combine the ones that we have announced so far, at the time of the sale, there is about 45,000 a day production from the ones we have announced so far that have been completed, I should say. We also have the Scott Lano [ph] swap later on in the year and at that time, we are estimating somewhere around 9,000 to 10,000 a day of production of Scott would go away. That's really the primary result of it.

But from the current run rate -- what would be the exit rate?

I think we are looking at somewhere between 330, 340, in that vicinity.

Down from 370?

Yes.

And that's primarily due to the asset sales? The bulk of it is, yes. What will 2004 look like once the swap kicks in?

Too early to say, Mark.

We'll next go to [Indiscernible] Goldman Sachs.

My question has been answered.

We'll next go to Don Textra [ph] with Dorset Asset Management.

John or--

You are safe asking the name "John."

Or anybody. You had mentioned that you booked about 900 B in the JDA. You had discovered P 1, P 2, P 3, I guess, about five TCF. You know, you picked up an extra quarter interest there with the swap with BP and I was wondering have those reserve been booked on the swap or were they booked this year in the swap? Were they booked last year? And secondarily, if you went ahead with phase two in a year's time, what would the effect on bookings be?

You are right. The 25% interest we acquired in the swap is in this year's bookings, although on our books, it's not part of the public record, yet, so, it was booked last year, I'm sorry, did you say? No, it's booked this year.

it will be booked this year.

It's booked now, but will you see it at the end of the year in the public release.

Yeah, okay, and how much would that be, roughly, John?

Roughly half of the 900 base.

So you would book roughly 450 B in the swap?

Slightly more because of the effective carrier.

500 B?

Yes. Yes, 90 million barrels.

80 million barrels.

I think actually, the number is 86. I hate to work with that degree of precision.

If nothing else happens this year, whatever you produce, 130 million barrels, you will be able to book 86 million barrels in the JDA?

Right.

Would that number sort of double up -- I guess not double up, but does that mean you would book 170 million barrels equivalent when phase two happens?

It depends on the gas contract and the terms of the gas contract. We wouldn't want to speculate. The purpose of John O'Connor spelling out potential resources is there is a lot of upside in the JDA. It's a function of getting the I gas contract or contracts in place. We are optimistic about that. Initial talks have started, but it takes some time.

Great, thanks very much, John.

We'll next go to Audrey Fine with JP Morgan.

My question has been answered. Thank you very much.

Then we'll go to Ed [Indiscernible] with Lehman Brothers.

A couple of questions. Could you please go through what your capital spending program is for the rest of the year, and how you intend to fund it and what is going to happen with these cash balances and are there any other debt reductions anticipated either from that money or from asset sales?

Yes, right now, we anticipate that our capital expenditures would be -- this is both downstream and upstream $1.460 billion for the year. With the cash balance that we spoke about earlier, we intend to fund that cap X and then we'll look to reduce that with any excess cash that we have.

So are you projecting in any excess cash at this point? Can you give an amount or range?

There are a lot of moving pieces and staying general and broad is probably appropriate as we said before, the cash flow we have will be predominantly directed to our developments of new fields and whatever excess will be used to pay down debt.

Thank you. The second question I had is what level of confidence and sort of probability terms can you give that you are going to be able to meet targets with these developments out over the next couple of years? I mean there have been delays and things. Are you highly confident -- what assurance can you give the market on this issue?

We want to say we are conservative, so cautiously optimistic is probably the best way to say it, but, we have all of these different changes modeled in terms of the new developments and the cost reductions as well as selling the higher cost properties and when you add it all up, it's pretty encouraging trajectory to get towards our target. And I think, over the next several years, we will close the majority of that gap.

My last question is would you consider any other actions in the meantime, to try to significantly increase your production. In other words go out and do some sort of acquisition or something else?

We look at opportunities all the time that help us to reshape our portfolio to lower unit cost, to extend the reserve life. Sometimes, it's sales, sometimes, it's investments. We are constantly looking at how to upgrade the portfolio. Sometimes, it swaps, which is what we did on Scott and Lano [ph]. I think the point is that we will be disciplined in our actions, but we will also be opportunistic if the opportunity fits the criteria we set for ourselves.

We have time for a final question with Miguel Keith [ph] with Onstock and Company.

Two quick questions. On the unit costs, is it basically the failure to reduce the absolute cost or disappointing volumes? Or both?

With the driver on our target, I don't per se we had an exact target we were making. We knew we were looking at the portfolio and the targets we were looking to achieve on a long-term basis, so it is not, per se, a failure on a set target. We are looking at this long-term. Trend will be up in near term just due to -- we can't take the fixed cost out as fast as we have sold these. And therefore, it's part of the plan and's the developments come on and our plans for taking out these fixed costs begin to -- are reflected in our income statement, our unit cost will go down.

Another way of translating that. We had too much of our portfolio in mature properties like the Shelf, some of the properties in the U.K. So by selling them, it takes the negative factor out. That's step one. The acquisitions we had, some of them good, some were not so good. Letting that run through the income statement, that's in process and also matching that to future production and in some cases cost outstripped the production in some cases. And also the new developments coming in over the next three years are obviously very positive contributors both in terms of DVNA per barrel as well as unit cost per barrel. All of these things, together, over the next several years will make our portfolio much more competitive than the unit costs. It's not a quarter to quarter thing, but over the next several years we are very confident we will make a lot of head way in this regard.

Briefly, what have you gained over the last couple of years, owning the property? Have you seen any results that you can quantify, like your time, you reduce your cost? What have you gained owning the properties for the last three years?

There are a myriad of answers to that probably. We bought the properties -- really, we bought the corporation with the expiration upside. We saw that the outcome of that last year, first quarter of last year. We are very optimistic about the G 13 discovery and the follow-up potential that that offers us. So, if nothing else, it has met the criteria in west Africa for expiration for upside we saw transactions.

We now have 50% of the JDA, so, in terms of corporate acquisition, we have significant upside there, also, and remember, we have two years left on the expiration in blocks F and G. We continue to see significant opportunity there. This year, we have been focused on the Gulf of Mexico, significant prospects that came our way that we needed to be committed to this year. Next year, without giving the game away, will you see us spending more time, effort and money, in exploring very quick prospects that we see emerging like in Equatorial Guinea.

And finally on the downstream -- on the Venezuela situation, are we back to normal or where are we?

Since March the Venezuelans have been meeting all their commitment on crude oil supply and, you know, we are back to normal. The Virgin Islands is running 470 to 480,000 barrels a day. Cat cracker [ph] full capacity, Coker [ph] full capacity and crude supply totally reinstated. Things are going well.

Thank you.

Thank you all for your attendance and interest in our company. We look forward to the next call and keeping you updated on the progress we are making.

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