赫斯 (HES) 2002 Q2 法說會逐字稿

Please stand by, we are about to begin. Good day, everyone, welcome to the Amerada Hess quarterly earnings release conference call. This call is being recorded.

Today's presentation will be available for rebroadcast at 4:00 p.m. Eastern today. Running through July 31st at midnight. You may access the replay by dialing 17194570820. Again, 1-719-457-0820, or 1-888-203-1112. And enter confirmation code 792404. That is 792404 on your telephone.

All media will be in a listen-only mode for the duration of this call. You may also access today's conference via the Internet at www.hess.com. That is www.hess.com. Media questions should be directed to Carl Persy at 212-536-8593.

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

Hello, thank you for participating in our earnings conference call for the second quarter of 2002. This is Carl Persy. With me is John O'Connor, President Worldwide Exploration and Production, John Schreyer, Executive Vice President and Chief Financial Officer, and John Riley, Vice President and Controller. John Schreyer will discuss second quarter results after which the meeting will be open to questions. Certain forward-looking information and other previously undisclosed items may be discussed during this call. I will now turn the call over to John Schreyer.

Hello everyone. Our earnings release was issued this morning and it appears on our website. Our commentary today will concentrate on the results of operations for the second quarter of 2002, compared with the results for the first quarter. Pages 3 and 5 of the press release include an income statement and a summary of operating statistics, together they contain much of the information to which I will be referring.

First, let's look at consolidated results of operations and cash flows. The Corporation's operating earnings for the second quarter of 2002 were $171 million dollars. An increase of 51% from the $113 million reported in the first quarter of 2002. We had cash flow from operations in the second quarter of $561 million. We also had a cash contribution from working capital and certain other items of $71 million. We had total available cash in the first quarter, or the second quarter of $632 million.

The principal uses of cash were capital expenditures, $425 million, debt reduction, $180 million, and dividend payments $27 million.

Our debt-to-capitalization ratio at June 30 was 51.7%, compared with 53.6% at the beginning of the year. We repaid $326 million of debt in the first half of 2002. And we expect to achieve our debt repayment goal of $600 million for the full year. Our estimate of capital expenditures for the year has increased by 7%, to $1 billion 550 million.

Turning now to the exploration and production segment.

Operating earnings from exploration and production activities in the second quarter of 2002 amounted to $198 million compared to $199 million in the first quarter. The components of this very modest change on an after-tax basis are as follows: Our crude oil selling prices increased on average $1.31 per barrel, including the hedging effect. That increased earnings in the second quarter by $25 million. We had higher production volumes, that increased earnings by $7 million. We had increased depreciation and amortization that reduced earnings by $40 million, all these are after-tax numbers. We had an increase in our foreign exchange loss of $13 million, reducing earnings, but we had lower effective income tax rate primarily a one-time $8.5 million foreign tax benefit that increased second quarter earnings by $14 million, and all other items were $6 million increasing second quarter earnings.

Let me now provide some background on these items.

The impact of crude oil and U.S. natural gas production hedges in the second quarter of 2002 was an after-tax benefit of approximately $10 million, which is 31 cents a barrel of oil equivalent. Compared with the benefit of $76 million, which is $2.31 per barrel in the first quarter.

Turning to oil and gas production, which is shown on page 5 of the press release, in the second quarter of 2002 crude oil and natural gas liquids production was 307,000 barrels per day compared with 324,000 barrels per day in the first quarter.

Production in Equatorial Guinea increased to 48,000 barrels per day in the second quarter of 2002 from 30 barrels a day in the first quarter. Natural gas production in the second quarter was 790 million cubic feet a day, a decrease of 3% from the first quarter, primarily due to reduced seasonal demand in the United Kingdom. Natural gas production in the United States increased slightly. Production of oil and gas on a barrel of oil equivalent basis was 690,000 barrels per day -- was 469,000 barrels per day, up approximately 2% from the first quarter, and up 10% from last year's second quarter. We now anticipate production will average 465,000 barrels per day for the full year. The 10,000 barrel per day reduction from our previous estimates results from drilling slippage in non-operated fields in the United Kingdom and Norway.

As I mentioned, second quarter DD&A, depreciation, depletion and amortization, increased $40 million on an after-tax basis from the first quarter. This is a $66 million pre-tax increase. A portion of the increase results from increased production. Several additional items have contributed to the increase. Firstly, the impact of some new production in the offshore U.S. with DD&A costs higher than the material production it is replacing. Also, increasing Equatorial Guinea production, which, as we have said before, has acquisition costs embedded in its DD&A. The DD&A costs and EG are not increasing, it is just that this production is becoming a larger percentage of our total production. Finally, we are experiencing a more severe decline curve than originally anticipated on several of our Gulf Coast natural gas fields.

We believe this will reduce our proved reserves by approximately 15 million barrels of oil equivalent, or 1% of our proved reserves. The effect of accelerating the depreciation of the book value of these fields over the reduced reserves is $28 million pre-tax, $17 million after-tax, in the second quarter. This causes 48 cents of the 96 cents increase in unit costs in the second quarter as compared to the first quarter. We estimate that our unit costs for the full year will be approximately $14.70.

We had foreign exchange losses in the second quarter of $13 million after-tax. This reflects the impact of an 8% decline in the value of the dollar versus the pound. The effect was mitigated by hedges. The effective income tax rate for exploration and production operations in the first half of 2002 was 39%, compared with 40% for the year 2001.

The proposed change in the United Kingdom income tax rate we discussed with you in the first quarter conference call has not yet been enacted. However, we anticipate its enactment in the third quarter, at which time, we will book a one-time, non-cash charge of approximately $45 million, relating to the U.K. deferred tax liability on our balance sheet. At the same time, we will record a $12 million charge for tax expense from the effective date, which will be April 17th until the end of the second quarter.

Over the third quarter, we will also record the impact of the higher rate on third quarter earnings, approximately $15 million. We expect our full-year effective income tax rate for exploration and production to be 42%, excluding the one-time charge.

As we said in our last call, it is likely that our cash taxes in the U.K. will be reduced slightly in 2002, from what they would have been otherwise. The status of our hedges at June 30th is as follows: And we talk about two periods, the remaining six months of 2002, and the year 2003.

For the remaining six months of 2002, 40% of our crude oil is hedged, and 30% of our U.S. natural gas. For 2003, 20% of our crude oil is hedged, and 25% of our U.S. natural gas. The average price at which TI-related crude oil is hedged in the remaining six months of 2002 is $24.90. And the average price at which U.S. natural gas is hedged is $4.30. The average price of TI-related crude oil hedges in 2003 is $24.30 and the average price of the U.S. natural gas hedges in 2003 is $4.

Our after-tax deferred hedge losses at June 30th are $1 million. They are composed of two components a realized component of $4 million, this is closed positions waiting to be recorded in the income statement, at the date they would have matured and then unrealized losses of $5 million which are priced to market at June 30th price, those are on all open positions.

Exploration expense of $50 million in the second quarter was slightly lower than the first quarter. The $6 million cost of the F-3 well in Equatorial Guinea which was unsuccessful will be expensed in the third quarter. Using the conservative assumption that all second half wells are unsuccessful, full-year exploration expense is estimated to be approximately $315 million versus $368 million last year.

Turning now to refining market and shipping.

Refining the marketing operating earnings amounted to $39 million in the second quarter of 2002, compared to a loss of $22 million in the first quarter. The corporation's share of Hovensa's results was a loss of $18 million in the second quarter compared with a loss of $26 million in the first quarter. Refining margins continue to be depressed throughout nuch of the second quarter.

As discussed in our last conference call, the FCC unit at Hovensa was shut down from mid-March until May 19th. This unit is now fully operational. We estimate that our share of lost margin in the second quarter was approximately $20 million. In addition, approximately $6 million was expensed for our share of repair costs in the second quarter. The Hovensa Coker project has achieved mechanical completion. Process testing is underway and it is anticipated that the Coker will be operational by the end of July.

R & M earnings include $9 million of interest on the [Ped Facia] note in each quarter. We anticipate interest of $35 million for the full year. The balance of the [Ped Facia] note at June 30 was $419 million and principal and interest payments are current.

Excluding Hovensa, and the interest on the [Ped Facia] note, income from operations of the remaining components of refining and marketing was $48 million in the second quarter. Gasoline station marginals improved and as a result, retail operations were profitable in the second quarter as compared to a loss in the first.

After-tax trading income in the second quarter of 2002 was $17 million, compared with break-even in the first quarter. Noted on the press release that we had two special items. As mentioned in the first quarter conference call, cost reduction initiatives had been undertaken within refining and marketing including its energy marketing unit. The carrying value of energy marketing intangible assets related to past acquisitions and these are things such as customer lists, has been expensed. The after-tax amount was $14 million.

In addition, $8 million after-tax was accrued primarily for refining and marketing severance payments. Approximately 165 positions have been eliminated, and one office will be closed. The estimated annual savings from the staff reductions is $10 million after-tax.

The pre-tax expense for these items is $35 million, and it is that amount that is reflected in the marketing expense line of our income statement, and is the reason for the increase in this line over the first quarter of 2002 and last year's second quarter.

I would like to comment on the variance in the line item "other nonoperating income." Which is lower in the second quarter of 2002. In both the first quarter of this year and the second quarter of 2001, we had asset sales which were included in nonoperating income. First quarter included a $40 million pre-tax gain from the sale of several small oil and gas fields, and the United Kingdom energy marketing business. In the second quarter of last year, there was a pre-tax gain of $26 million from the sale of our tug and barge business. We had no asset sales in the second quarter of 2002. This concludes my remarks.

I will turn the meeting over to John Riley for your questions. I will ask the operator if she would please give instructions.

Thank you, sir.

Today's question-and-answer session will be conducted electronically. If you would like to signal for a question, you may do so by pressing the star key, followed by the digit 1 on your touchtone phone. Once again, that is star 1 on your touchtone telephone. We will pause a moment to make sure everyone has a chance to signal.

Our first question comes from Paul Cheng with Lehman Brothers.

Thank you. Hi, guys.

Hi, Paul.

Several quick questions, John, I am wondering, it doesn't sound like a big deal but on the Wall Street Journal this morning there is an article talking about some of the trade that you guys did and maybe about ten years ago, can you comment on that and to see if the -- what is the nature of those trade and if you are still doing those trades right now?

And secondly, as on the tension, I think with the increasing concern about the accounting side, I noticed that your current rate of assumption for the future return is about 9%, is there any plan, perhaps to change that, into a more conservative rate, if so, when that will happen, and what kind of impact may be on the income statement?

Thanks, Paul. John Schreyer will handle these questions.

First, as to the transactions that were discussed in the newspapers this morning. We, in fact, did do five transactions with two different financial institutions beginning in 1993, and ending in 1998. We believe the transactions were not unusual for commodity businesses and they were certainly straightforward elements of tax planning relating to the use of foreign tax credits for us. Each transaction was a sale of oil to a bank at a fixed price with deliveries of the oil scheduled over a number of future months. The bank paid us for the oil on the date of the sale. The amount we received was recorded as a separate current liability on our balance sheet. In every case the oil was delivered as specified in the contract. Income from the sales was recognized when the oil was delivered. The transactions were clearly described in both MD & A, management discussion and analysis and in the debt footnote included in our financial statements. After 1998, our tax circumstances changed, and we have not entered into any such transactions since then.

So, in summary, Paul, these transactions were done for a sound business purpose, they were accounted for properly, and they were fully and clearly disclosed.

Thank you.

Now, to the pension plan, you are right our assumption for investment return in the pension plan is 9%. That has been our assumptions for several years, was arrived at by benchmarking other company's assumptions which at the moment average 9.3%. In -- up until 1999, our pension plan, or as recently as 1999, our pension plan was fully funded. Over the last couple of years, we haven't achieved that 9% rate and so our plan is now somewhat under funded. We have been discussing this, our policy is to fund each year the pension expense that appears on our income statement. That is meant that we have been putting about $15 million a year into our pension plan.

Obviously, at times like this, when the market is going down, that is not enough. So this year, we are putting in for approximately $45 million in the pension plan through the 12 months ended at the end of the first quarter of 2003 and maybe sooner. We are looking at our assumptions and we will be going to our pension committee to discuss whether that shouldn't be reduced. In addition, when we agreed with our pension committee that we wanted to, and they agreed, put in this extra money this year, we also said that our intention was to continue to put in extra money, looking to get the plan fully funded, that is to make up for the market losses within the next three years. The rest of our assumptions in the pension plan having to do with the discount rate and the salary are pretty much down the middle of the plate.

Not -- John, if I could have just a separate question, a last one. On the office sales program, are we pretty much done?

No, we actually are -- have several assets that we are looking at right now and have discussions with various parties on further asset sales, so -- and that is actually both on the upstream and the downstream side. So we are committed to our debt reduction goal of $600 million, and asset sales will play a part in that reduction.

Thank you.

Our next question comes from Steve Phiefer with Merrill Lynch.

Hi, guys. I wanted to go back to John's comments on the DD&A's. I think you said there were more severe declines in the Gulf Coast. One question. Are those associated with L-log [ phonetic ]? And secondly I think you referenced it because of the write-down of 15 million barrels I guess there was a $28 million negative impact, pre-tax, $17 after tax, is that something that is a one-quarter event or is that something we should continue to see that element as we go forward?

Steve, the reserve write-down did involve primarily five fields that we acquired from L-log and actually 45% of the anticipated reduction is in one of those fields. The additional DD&A you see this quarter, we will have additional DD&A, and that is one of the reasons why our unit costs are forecast to that $14.70 for the year. We will have additional DD&A for the rest of the year that we approximate on a pre-tax basis to be around $90 million. And what I would like to do, maybe, is just hand your question over to John O'Connor so he could further elaborate on that.

Hi, Steve. I think that John has pretty much captured the essence of this. The one thing that I want to do is be sure is we don't get it out of context obviously. Aside from the correction to the crude reserves that we acquired with L-log and I would point out while we had crude reserves in the field we had no production history. We have had a very successful drilling campaign, 26 out of 28 wells have been successful. We have added thus far, we think about 60 VCF of new reserves to the L-log properties. Our MCF costs are running about $1.25 in the sound area. We have an inventory of prospects remaining, 50 prospects waiting to be drilled. So I want to give you some context around that, Steve.

Sure. So is the new field -- as the new fields start up with $1.25 per MCF, F&D, will that start to reverse some of this higher unit DD&A as we go forward as those start to be booked and start production?

Yes, that will. But we will have to -- if you want to stay eat away at the higher DD&A rate on the established producing fields. You are right as the new fields come on at the lower F&D costs that will lower our unit costs, related specifically to these natural gas fields in the Gulf Coast.

Got it. In the $90 million sort of annual higher DD&A rate for those fields that were written down, is that something as we get into '03, those fields will be largely depleted and that goes away or maybe some visibility on how long that high DD&A rate for that particular field or fields continues, how long we have to think about that in our models as an ongoing drag, if you will?

The fields that we are talking about will extend beyond 2003. Obviously the production from those fields will decline in 2003 versus this year. And then obviously into 2004, they will decline further. But there will still be a lingering effect on the DD&A rate from those fields, even into 2004.

Great, thank you.

You are welcome.

Our next question comes from Ray Deacon with RBC Capital Markets.

Yeah, hi. I had a question for John O'Connor. Just, John. Is most of the CAP-X increase directed towards upstream projects and if so where are you adding focus?

Yes, it is. A little bit more expenditure in exploration in Equatorial Guinea, a little bit more in an exploration opportunity in the Gulf of Mexico, and I believe there is some capital payments associated with our entry into the AOIC consortium. Yes, it is all [INAUDIBLE] and it's all for quality projects, we are happy to have the opportunity to invest in them.

Just to elaborate real quickly on what John said, the AOIC payment relates to our previous acquisition of an increased interest in AOIC. We had a payment that was due for that in 2003, because of our stronger cash flow, we elected to pay that now in 2002. So that is what that additional CAP-X is.

And just, John, one more, as far as further exploration this year, is the plan still to drill what is it, one well on block F and two more exploration wells on block G, is that --

Yeah, we are drilling F-4 right now. We will probably have another one on block F after that, and my guess at this stage, or our plans are for three in block G.

Three in G, great. And just -- yeah, that was it. Thanks.

Good.

We will go to Arjun Murti with Goldman Sachs.

Thank you, just a follow-up on the CAP-X there, should we assume further ramp-up next year as you continue to ramp up development in EG, and then any thoughts on a volume number for '03 at this point?

At this point, we are still looking at what our budget will be for next year, and our production forecast, and we do not have a set target for next year on our production.

As far as the CAP-X for next year, you know, just from an earlier guidance, we obviously have some developments that will be coming on stream more in the 2004 period, but that we will have to start spending money on next year. And that is the northern block G developments around the O & O area. As well as some projects in the U.S., [be it lawn owe], Devils Island and some in the U.K.. We do expect to have additional CAP-X for those development projects, and would see our CAP-X budget going up in the hundred to 200 million range next year.

That's great, thank you.

We will go to Doug Terreson with Morgan Stanley.

Good afternoon.

Good afternoon.

I had a question about the cost reduction program that you guys [INAUDIBLE] at the analyst meeting. I think you mentioned $95 million is the number you expected to attain this year. Can you, kind of, update us on progress on that number thus far?

We do clearly have cost reduction efforts underway, at this point right now, it is something that is kind of a long-term program that John O'Connor has been focusing on and we are doing it on the downstream side as well. So I don't think we have got numbers in place that we can tell you exactly where we stand, but it is something we are clearly focused on.

Okay. Also, a clarification on the Coker. The Coker is fully streamed at this time; is that correct?

No, no, just process testing is underway. We are looking to be in operation toward the end of July. We are not fully streamed at this point.

You expect to be fully streamed by?

We would say the first week in August we will be fully streamed.

Caller: And also maybe we could get John O'Connor --

Just to clarify that, at about a 45,000 barrel level. I would say that would be the first two months for the Coker.

Okay, good. And also could we get John O'Connor to maybe comment on the motivation for the acquisition of the interest in Cameroon? It may or may not be that significant but that is a country that doesn't come up that frequently. And so, if we could get him to talk a little bit about that, I would appreciate it.

Sure. It is part of the new venture initiative where we took a significant interest in properties held by Fusion, an Australian exploration company. We looked at their portfolio and we picked three of the areas that we found a particular interest. [INAUDIBLE] obviously, with our experience in Equatorial Guinea, that we like, we see structures, a lot of interest. So it is really [INAUDIBLE] with Equatorial new Guinea.

Thank you.

We will take a question from Michael Young with Jerrod Klauer.

Yes. Good afternoon. I wanted to focus again on the DD&A issues and make sure I understand clearly.

The first question would be with respect to the $90 million figure that was referenced I believe in additional DD&A, I assume that's for full-year 2002, or is that to be expected in the second half of this year, in addition to what was already sort of the stepped-up depreciation expense in the just-reported second quarter?

That $90 million you can look at as approximately $30 million each in the second, third and fourth quarter.

Ok. Terrific. And then also still on the same subject, $66 million in additional pretax DD&A expense in the second quarter, we can explain $30 million or $28 at L-log, I estimate probably another $13 or $15 million at Equatorial Guinea, due to the higher volumes there, where does the remaining almost $20 million, how is that occurring?

Okay, I don't know if I have got that exact -- if you want to say the number is $20 million, the other piece that you had left off was John Schreyer referred to in his comments earlier is that we do have some newer production coming onstream in the U.S. and that production comes in at a higher DD&A rate than the mature production that it was replacing. That was the third element of the increase in the DD&A costs.

Boy, that is a big mix shift considering that your U.S. volumes overall were basically flat on a sequential basis.

That's correct. There were some declines from our deepwater U.S. of just natural declines in some of that and then we had some newer production coming on that did -- to tell you the $20 million you referenced, I am not sure if that's the exact number, I would have to look and check that. There clearly was an element of the newer production increasing our DD&A rate.

To be more precise the numbers are $15 million and $15 million. The U.S. effect is $15 million, the EG effect is $15 and $30 million comes from, as we said, the L-log properties.

But still, very, very high cost, new production that is then streaming into the U.S. by implication?

That is true.

It has got to be double digit on a unit basis, I calculate.

A couple of the new projects are expensive projects. They make money but they are expensive projects.

Right, right. Okay. And my last question, somewhat related but it is more on the reserve side, so l-log correct me if I am wrong but at the time of purchase, you booked approximately 450 BCF of reserves?

That -- that is a little high. We didn't book that much at the time of acquisition, but you are in the range.

North of 400, then?

Actually, I think it was more around 3 -- I want to say high 300s, 350,.

And that number you booked, 350, let's say, you are taking that down by 15%?

Correct.

Excuse me, no, by 90 BCF?

Correct, 90 BCF.

That is actually 25% reduction?

Right. And then, as John O'Connor mentioned, we did add 60 BCF through our post-acquisition drilling program.

Right, right. Okay, thank you for that the clarification.

You are welcome.

Our next question is from Steve Enger with Petrie Parkman.

Hi, guys.

Hi.

I wanted to maybe get a little more insight and color from Mr. O'Connor on the F-3 well. Could you talk about what worked and what didn't there?

You wouldn't want me to give away competitive information, would you? Or maybe you would.

I won't answer that.

I think that the main problem we had was lack of reservoir development, in both the primary and secondary objective. We did see sands in the well, but not in those particular objectives, and we also saw indications of hydrocarbons, but if you want a primary reason for failure, both primary and secondary objectives did not have well-developed reservoir sections.

Ok. Which, I think, probably was the greatest risk in your mind going in?

Absolutely. Obviously to say again, the commentary we gave on the first quarter conference call, we are moving to test new plays in blocks F and G, it is appropriate to do that. By definition they're going to be somewhat more risky. But also, when they are successful, hopefully somewhat more rewarding. For the rest of the year we will test new play concepts, it is an interesting and exciting time for us.

Right. In the other two block F wells that you may drill this year, is one or more of those on this same trend, or are you moving to that trend that is farther north?

We are currently drilling one of those two wells, and it is indeed further north.

Okay.

We have no plans for another well at this time on -- adjacent to the F-3 well that has just been completed.

Okay. And then switching around a bit, the Atlantic margin -- margin prospect follow-up is that out for this year at this point?

No, you know, it tends to be a moving target mainly because of the challenge with rig availability.

We have contracted for the West Navia and it has been drilling off of [Saint Alanza], Nova Scotia. But the last I heard it will come available in time for us to move to drill and test, hopefully, the appraisal wells to margin. We expect that about -- to come to us the end of the first week, second week of August. So it is imminent.

Okay. And you would just drill the one appraisal well on March and you had another prospect in this area, would you be able to get to that as well?

Well, I think it's very much going to depend on both how the first well progresses and also the what the weather conditions are like. But, we're sensitive with a high-cost commitment to the West Navia and the support equipment with it that we don't experience a lot of downtime due to weather. Right now we are flexible and if it looks that conditions are difficult, we will move the second well, which is not in the same structure by the way, it 's on a separate structure, we have moved that into next year.

Thanks. And then finally on the JDA project, can you update us on your view of how that is progressing and best look at timing to start-up at this point?

Yeah, from immediate point of view, we are completing mechanically the production facilities. We expect to have those completed in September.

We are still anxiously awaiting confirmation from the governments of Thailand and Malasia that there is an understanding with respect to letting the contract for the various pipelines and facilities. At this stage I would have to be conservative to realistic and say that we are looking into the second half of '04, for first production.

Okay. Thank you very much.

You are welcome.

We will now go to Paul Teng with Salomon Smith Barney.

Good afternoon, guys. Some quick questions on the downstream side, looking at both product sales and refining through-put, volumewise it is significantly below eihter sequential and year-ago. Is that strictly due to FCC or is there something else involved there?

It really is. It is just lower crude runs that -- and that had a lot to do with the FCC being down for a good part of the second quarter.

Okay. Now, in spite of the FCC downtime, looking at the downstream sequential profitability, it looks like to me that I adjusted for the downtime if you will, we saw something like a $70 million of improvement, versus the first quarter. That seems to be -- that's a very healthy number. Is that totally explained by margin difference or is there something else going on?

Well, excluding Hovensa, from this, which you can see that Hovensa had some improvement in the profitability, and obviously we did have the downtime there, in the second quarter, all other components of our downstream business were profitable. As we said in the first quarter, of '02, the retail business was not profitable, it was profitable in the second quarter. The trading results were break-even actually in the first quarter, and improved to $17 million in the second quarter. And our energy marketing business was also profitable in the second quarter.

Can you isolate the sequential improvement for the marketing side of the business between 1Q and 2Q?

No, at this point, again, like in prior periods, or as we discussed earlier, we don't break out separately the results from the marketing side. But needless to say the margins were much improved from the first quarter to the second quarter.

Okay. Okay. Did you see any visible mix shift, like more into the more profitable gasoline pool as opposed to the less profitable other product?

Yes, yes, that's fair to say.

Okay, okay. Just a number-related question. You brought down your target of production growth rates very slightly this year, I presume that will not impact your 5% long-term targeted of growth rate over -- in the long haul?

No, and as John Schreyer mentioned the comments it was a slippage on some of the drilling, so again not lost reserves, just delays in that production. That is not affecting our long-term 5% target.

Ok. Great. Thanks alot guys.

You are welcome.

The next question comes from Mark Flannery with Credit Suisse First Boston.

Hi. I have a question on U.S. natural gas production. We have heard from some companies [INAUDIBLE] that lower prices are causing them to slow down some activity to certain of their areas. Are you -- now you have less of the production hedged for the second half of the year, is this something you are looking at?

Hi, Mark. I don't know whether you want the hedging issue to be addressed or the issue of why our realizations haven't suffered the same penalty as some other producers.

My understanding is that the net backs are primarily affected in the Rocky Mountains and we don't have production there, we have predominantly Gulf Coast and Gulf of Mexico production which hasn't had the same effect. There is a regionalization effect on realizations. With respect to hedging, I am happy to hand over to John Riley.

What was your question?

If I could go back to John for a second the question is now we have got gas prices, even Henry Hub prices under $3, is -- I mean, is there anything out there,at the margin, even on your normal gas portfolio that you are going to start to look again at with the $2 and something gas?

Are you -- your question, are you -- is your question asking if we are going to cut back production with the lower price?

Are you going to reduce drilling activity and thereby production given the lower price?

No, Mark, definitely not. I think the program is pretty much set. We talked at the end of the first quarter about how we had reacted in the basically Gulf of Mexico shelf, in the main pass area, to cut back on drilling activity associated with the L-log acquisition to one rig. We plan to continue rolling that rig to drill up those prospects I alluded to earlier that remain in inventory. So we're gonna have one big [INAUDIBLE] to continue on into 2003. And I don't really see any other plans to cut back from where we are.

Okay, thanks.

You're welcome.

We will now go to Mark Gilman with First Albany.

Hi, guys, a couple questions. John, is it too early to say anything about the performance of the water flood at Sabia [ phonetic ] yet?

Still too early, Mark. I would like to see 12 months of operations. What I would say is that the actual mechanical performance of water injection is going well, we are up to 60,000 pounds of water a day injection now. We have another injector we are completing in the next week or so that will add another 10,000 pounds a day of water injection. So, I guess, the only thing you might want to infer is, that there's nothing negative happening, the water is going away, we are beginning to see - seeing some pressure support from that water injection. And I would like to see more water going in the ground. So far, so good, Mark.

Okay. Update on Lino, John and what the next step might be?

The operator has agreed a plan of development and put it to the partners, and the partners have got to respond to that plan of development.

As you know, Shell took over as operator from Enterprise, they have been very quick to take hold of this, to come forward with an acceptable development program.

Once all the partners have signed up, there is a fairly aggressive development schedule leaving first production by 1/1/04.

The next well on block F, same plateside as F-3 or different?

It is -- I would really -- they are both upper companions, in that regard they are probably the same but not in a different stratographic interval. Somewhat, a different setting I would say but an analog, but I won't infer a dependency between the two.

The DD&A effect that has been talked about or asked about in terms of the U.S. piece of it, can -- excuse me, can I assume that what we are seeing here is an effect almost similar in the U.S. to that which is occurring on E.G., only with the L-log acquisition costs being the culprit as opposed to the Triton acquisition costs, is that a fair statement?

If you mean you've got higher acquisition costs in E.G. that is embedded in the DD&A rate, yes, that is similar. The only other aspect to this, though, on the L-log side is that we did lose some reserves, so the DD&A amount was increasing over what we had originally planned on, on the current producing properties.

Yeah. I mean, you had a $2 [INAUDIBLE] acquisition cost on L-log on the initial reserve assumption.

Correct.

Okay? So if you are finding, let's say you are finding at a buck. When you bring that production on, it is coming on at an absolutely exorbitant rate.

The reserves that we booked at two we are depleting at two. And the neural -- and to that point, Mark, though, as reserves were reduced it now is depleting at a higher -a slightly higher than $2 rate. But the new post-drilling results that came in at $1.25, they are being depleted at the $1.25 rate.

There is no cost acquisition burden on those?

No, essentially most the acquisition costs that were put in were put on the proved -- on the proved reserves that were there.

Caller: Okay. Just one final one, what is your remaining investment in energy marketing?

The overall gross -- you are saying like net book value of energy marketing?

You got it.

That -- that is not a number, we won't give the book values of, you know, separate components of the business, Mark. I don't have that number, but it is not a number that we would be disclosing.

Is it a big number?

No, not --

Not at all. It is just working capital. There are no fixed assets involved in it. It is just working capital. It isn't a big number at all.

Ok. Thanks alot.

We will go to Fred Leuffer with Bear Stearns.

A couple of questions. What is the dry whole cost on F-3?

That is only $6 million.

That will be taken in the third quarter; right?

Yes.

And just back to the United States, what is the level of drilling activity that you have got going on, on the shelf properties now?

It is -- well, I think as John had mentioned earlier, and John you can add if you would like -- but we have one rig working, we are at the end of last year, we hull -- actually had five to six rigs working. With the lower commodity price environment that we went into this year with, we lowered that to one rig, and as John mentioned we were goings to continue with that one rig.

And John, you mentioned in response to an earlier question that there was -- you have discovered about 60 Bs on the L-log properties?

Correct.

Is that proved, or proved and --

It is actually proved developed now, Fred.

Those will all be booked this year?

Yes.

Wait, just to clarify that. No, there was a piece, John, that was booked last yearly. Some of the post-acquisition ones, there was a piece booked, and the rest of the 60 will be booked this year.

Is that how much was booked last year?

There was about six last year, and so four will be booked this year.

I am sorry?

I'm sorry. I did BOE's on ya. I did 6 barrels oil equivalent was booked so 60% of it was booked in last year. And 40% will be booked this year.

With the drilling program still to continue and hopefully more to add over and above that.

Exactly.

At this rate of activity, what do you see as the production profile there?

Currently we produce 150 million cubic feet a day net to Hess. That will probably be sustained. Is my expectation.

You can sustain it with one rig?

You are talking about for the rest of this year or next year too?

'02.

I think the expectation -- we haven't come out with a production forecast for next year but there is the expectation that that will be reduced next year. It could be in that 20 to 30 M level next year. But for the remaining part of this year we are in the 140 to 150 range.

And I'm sorry, at that -- you know, from what you know right now, it would be reduced next year by how much? By 20?

20 to 30 M.

Yeah. As a matter of fact, I would even say it is 15 to 25.

There you go.

Obviously we haven't done final final planning on 2003. We are looking in the order of 125 million cubic feet a day for next year.

That would be an early estimate.

That is a function, it is not lack of reserve opportunities, that is a function of the activity, I guess; right? Which is a function of the price? You could run --

It is a combination of the two things, I think. As we develop the prospects we think an efficient way to run the exploitation program is with a one-rig program.

I mean, obviously if you had significant economic incentive to increase it, you could probably mobilize more equipment. But you also have, you know, people issues, and geo-scientists and engineers to think about in terms of developing and furthering the prospect.

Okay, great, thank you.

All right, Fred.

We will go to Myron Caplan with Caplan Nathan. [pause] Mr. Caplan, your line is open. Please go ahead. Mr. Caplan?

It sounds like we had better move on to the next call.

We will take a follow-up from Paul Cheng.

Hi guys. Actually this is for O'Connor, John, do you have a -- an early feeling in terms [INAUDIBLE] that whole development project, when that is going to come on stream and what kind of production, peak production that we may be talking about? Are we still talking about to come on stream by the late 2003, early part 2004?

Yes. Is the answer, Paul. I think that we -- the most important thing is that we are still on track to submit a plan of development to the government authorities in Equatorial Guinea in September. I think that once we have had that discussion and submission to the government we will be in a better position subsequently to give you more definitive projections both with respect to quantity and timing but 2004 is when we are looking for first production from the northern block G development.

Okay. John, in the -- if we are looking at L-log, I understand you have 60 BCF of new gas, but at the same time you are way off 90 BC fwz now, when we are looking at this whole deal on the going -- you are looking into the future, is this kind of acquisition or target that you may still be interested, or that perhaps that this is not really going to fit into your overall strategy going forward?

Well, two things to bear in mind, I guess, Paul. First of all we tend to overlook the fact that at the time of the acquisition, it was possible to hedge the production from L-log at very, very good prices, and I think 2001/2002 production, average gas priced realized for the production was $4.75 an M. We need to keep that in mind. With respect to materiality, I think so long as we see opportunities that we can create value from acquisitions, particularly in the United States, we'll be looking at them carefully to do so. I think it is fair to bear in mind despite the ins and outs of what are relatively modest amounts of reserves, both with respect to negative revisions and additions, this is still a paying proposition, as we look at the full life on the L-log acquisition, this is making money for us.

Okay.

So, you know, with respect to the type of properties and so forth, yeah, we would look at that carefully.

Maybe if I can ask, what kind of return that we get from L-log if you are looking at based on the current futures rate on the gas price, on a full cycle what is the expected return?

The acquisition at the time, I think, was announced as a double digit return, and currently, as things have unfolded we're looking at single digit.

So when you talk about single digit, like what, about 9%, 8%?

I leave you there. I think that is the precisest I can be Paul.

What I am trying to say, though, is that your cost of capital is it 8 to 9%, and if you are getting a single digit return from that acquisition, it doesn't appear to be really creating value in the first pace, is it?

It is not -- it is certainly not strikingly value-creating, I agree.

Lastly I just want to understand a little bit when we do the reserve weight down on L-log, I think John Schreyer you indicate we have a $17 million loss, is that a one-time loss you wait on the reserve or is that talking about increasing the DD&A resulted in a lower earning by $17 million and that will have an ongoing continuing impact on the future earning?

That is the quarterly amount. As I -- I mentioned $28 million pre-tax, and $17 million after-tax.

That is ongoing.

That will go on. At this level of production, as John Riley said, as production goes down, that will go down an amount but you can expect for a year or maybe a year and a half, this kind of impact on DD&A from the loss of the reserves.

I see. Ok. Thank you.

We will take our last question from Ray Deacon.

Hey, so, John O'Connor, does this mean you you may be able to book some reserves at [Lion] without any further deliniation drilling this year, I guess?

Yes. I believe the answer is yes. Assuming that all the partners agree to the development and assuming we sanction the development, that will be the trigger to book reserves.

Okay. And just how confident are you that in 2004 you will be able to get some production off East Java, is that still too early to say, or --

No, I don't think it is too early to say. I feel very confident we will get it, for a number of reasons, to do with industrial demand and power gen demand in the East Java area, and the fact that our reserves there probably lead to queue in terms of attractiveness to make the next sale.

Have you any idea what the gas price would be at this point?

Don't really have, and given that, you know, commercial negotiations have not really matured there, rather there is an indication that the market existing, it certainly would be premature to comment about contractual aspects of the gas sale.

If you were -- I mean, actually, it seems like your U.S. gas production was up, you know, 30 -- almost 30 million a day.

Right.

What was -- was that all L-log properties coming online, drilling on the L-log properties or --?

No, it was not. It was quite a mix. John Riley alluded earlier to the fact that we had some production from Tulane, we have production from South Tim properties, so the mix changed significantly, and basically there's a lot of ins and outs. New production was 50 to 55 million cubic feet a day offset by netted-out 20 from decline.

Okay. As far as, you know, Indonesia production, it looked like it went down about 3,000 barrels a day. Is that -- you continue to produce at about 3,000 barrels a day?

I am not aware of any permanent decline in Indonesia, I would have thought that -- book adjustment to entitlement rather than operational issues.

Okay, great. I guess maybe, Carl, one quick question, so far the downstream in the third quarter, fourth quarter, would you expect results are continuing to improve from the second quarter level or about the same type of contribution there?

We would say about the same. But, you know, marginally profitable. Obviously we are expecting better results than the first quarter. And obviously like I said, marginally profitable going forward.

Okay, great, thanks.

That is it. We thank you all for listening in, and we will see you next quarter.

That does conclude today's presentation. Thank you. You may disconnect at this time.