赫斯 (HES) 2002 Q3 法說會逐字稿

Please stand by. Good day, everyone, and welcome to the Amerada Hess quarterly earnings release conference call. This call is being recorded. Today's presentation will be available for rebroadcast at 3 p.m. Eastern Time today running through October 31 at midnight. You may access the replay by dialing 719-457-0820 or 888-203-1112. Again, those numbers are 719-457-0820 or 888-203-1112, and please enter your confirmation code of 701105. All media will be in a listen only mode for the duration of this call. Media questions should be directed to Carl Tursi at 212-536-8593.

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

Thank you for participating in our earnings conference call for the third quarter of 2002. This is Carl Tursi. With me is John Hess, Chairman of the Board and Chief Executive Officer; John O'Connor, President, Worldwide Exploration and Production; John Schreyer, Executive Vice President and Chief Financial Officer; and John Rielly, Vice President and Controller.

John Hess will discuss certain key items, John Schreyer then will review third quarter results, after which the meeting will be open to questions. Certain forward-looking information and other previously undisclosed items may be discussed during this call.

I will now turn the call over to John Hess.

Good afternoon. Before John Schreyer takes you through our third quarter results, I want to advise you on several key topics of a broader nature. These are, first, a revision of our current reserve base and update of our estimated production through 2005. Second, the possibility of selected asset divestitures as part of our ongoing objectives to increase reserve life and lower our cost of production. And third, our preliminary estimate of capital spending for 2003.

On the subject of reserves, since our second quarter conference call, we have experienced steeper production declines in several fields, primarily purchased in the LLOG transaction. As a result the projected cash flows on a number of fields are less than their book value.

Additionally, this field performance has reduced the number of remaining drillable prospects.

Therefore, an impairment of those fields and prospects is required by accounting rules. The impairment which reduces the book value of these fields to the discounted value of anticipated future cash flows is $394 million before tax and $256 million after tax. The noncash charge is included in our third quarter results as a special item. We believe this will reduce our proved reserves by approximately 29 million barrels of oil equivalent. This represents less than 2 percent of our proved reserves and includes the 15 million barrel reduction we mentioned in our last conference call.

Approximately 9 percent of the charge results from Gulf of Mexico fields other than the LLOG properties. Regarding production, our 2002 year-to-date crude and natural gas production has averaged 456,000 oil equivalent per day and we expect the full year average to be approximately the same. Our current estimate for 2003 is 415,000 barrels of oil equivalent per day or approximately a 9 percent reduction from 2002.

The projected reduction in production for 2003 comes from field declines in shallow and deep water Gulf of Mexico, the UK North Sea, and Colombia. However, even production expected to decline 9 percent from 2002 to 2003, our projection indicated a 5 percent compound annual growth rate from 2002 to 2005. The majority of this growth comes from increases in 2005 and is based largely on contributions from Equatorial Guinea but also the deep water Gulf of Mexico, North Sea, and Southeast Asia. Key to the timing of increased production are the Okume, Oveng, and Elon fields for which development plans are currently being submitted to the government of Equatorial Guinea for approval.

Moving to the second topic, we continue to have as two of our principal corporate objectives the lengthening of our reserves to production life as well as the lowering of our unit cost of production. As part of this ongoing effort we have targeted certain selected assets for divestiture over the next several amounts which amount to 5 to 10 percent of our current production provided of course that we can do so at attractive values. The impact of these potential sales is not included in the estimates of future production which I just discussed.

Finally, our production process is not yet complete. Our project process is not yet complete. We estimate our capital expenditures next year will be $1.75 billion. Exploration production capital expenditures are estimated to be approximately $1.65 billion. The increase in the EMP [phonetic] expenditures from this year's estimated $1.45 billion reflects higher expenditures for development and production activities in Equatorial Guinea. We anticipate we will fund all our capital expenditures from cash flow.

John Schreyer will now review our third quarter results after which we will take questions.

Thank you, John. Hello, everyone. Our earnings release was issued this morning, and it appears on our website. Our commentary today will concentrate on results of operations for the third quarter of 2002 compared with results for the second 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.

Let's turn first to consolidated results of operation and our consolidated cash flows for the third quarter. The corporation's operating earnings for the third quarter of 2002 were $121 million, a decrease of 29 percent from the $171 million reported in the second quarter.

As John explained, we also recorded an after tax impairment charge of $256 million during the quarter. Cash flow from operations in the third quarter was $550 million. We had proceeds from asset sales of $151 million; therefore, total cash available in the third quarter was $706 million.

The principal uses of cash were as follows: Capital expenditures, $345 million; debt reduction, $215 million; dividend payments, $27 million; increases in working capital and other expenditures, $119 million. Our debt to capitalization ratio on September 30th was 52 percent compared with 53.6 percent at the beginning of the year. We repaid $541 million of debt in the first nine months of 2002. We expect to meet our debt repayment goal of $600 million for the full year. Our estimate of capital expenditure for the year is $1 billion 550 million.

Turning now to exploration and production. Operating earnings from exploration and production activities in the third quarter of 2002 amounted to $181 million, compared with $198 million in the second quarter.

The components of this change, on an after tax basis, are as follows: Our crude oil selling prices increased an average of $1.56 per barrel including the impact of hedging. That increased the third quarter earnings over second quarter earnings by $29 million. We had an increase in our per barrel production expense which reduced third quarter earnings by $30 million.

We had higher exploration expense in the third quarter, reducing earnings by $34 million. Foreign exchange impact in the third quarter was $33 million, increasing earnings. We had a higher effective income tax rate including the impact of the new 10 percent United Kingdom supplementary charge which reduced earnings by $37 million, reduced operating earnings by $37 million. While other items increased net earnings by $22 million, so a net change in earnings of $17 million, a reduction from the second quarter.

Let me now provide some background information on these items. The impact of crude oil and U.S. natural gas production hedges in the third quarter of 2002 was approximately break even compared with a benefit of $10 million, which was 31 cents a barrel in the second quarter.

Turning to oil and gas production, which is shown on page 5 of the press release, in the third quarter of 2002 crude oil and natural gas liquids production was 323,000 barrels per day compared with 337,000 barrels per day in the second quarter. Production from the Ceiba field in Equatorial Guinea decreased to 39,000 barrels per day in the third quarter from 48,000 barrels per day in the second quarter. This reflects a production interruption in two of the eight producing wells.

Natural gas production in the third quarter was 703 million cubic feet a day, an decrease of 11 percent from the second quarter, primarily due to field declines and to a lesser extent bad weather, both in the Gulf of Mexico and in lower nominations and maintenance activities in the United Kingdom. These decreases were partially offset by increased production from Phase II of the Pailin field in Thailand.

Production of oil and gas on a barrel of oil equivalent basis was 441,000 barrels a day, a decrease of approximately 6 percent from the second quarter but an increase of 2 percent from last year's third quarter. As John said, we now anticipate production will now reach approximately 456,000 barrels a day for the full year and 415,000 barrels a day for next year.

Increased production expense largely reflects higher workover expense on several fields in the United States and the North Sea and generally higher insurance and transportation costs. Per barrel DD and A, depreciation, depletion, and amortization expense, was slightly lower than reported in the second quarter.

Exploration expense increased to $105 million in the third quarter of 2002 from $50 million in the second quarter. The third quarter amount includes $19 million related to a prior year natural gas discovery in the United Kingdom for which there are no current development plans so we've written off that well.

The third quarter also reflects increased drilling activity which includes the cost of dry holes through September 30th in the Faroes and Equatorial Guinea.

The effect of income tax rate for exploration and production operations in the first nine months was 40 percent, the same as in 2001. During the third quarter if the United Kingdom government enacted the 10 percent supplementary charge on profits from oil and gas production, about which we have spoken with you previously. A one-time charge of 43 million was recorded as a special item for the impact of this tax increase on deferred tax liabilities. In addition, third quarter operating results include $23 million related to this tax increase. 9 million of the 23 is the tax for the period from the effective date, April 17th through June 30th and $14 million is the tax on third quarter income.

We had an after tax foreign exchange gain of $20 million in the third quarter compared with a loss in the second quarter. The gain largely reflects the fact that the dollar stabilized in relation to the pound while it continued to strengthen in regard to the Colombian peso for the nine months of 2002 the net foreign exchange gain was $8 million.

The status of our hedges as of September 30th is as follows: For the remaining three months of 2002, we have 60 percent of our worldwide crude oil hedge and 35 percent of our U.S. natural gas. The average price at which the TI related crude oil is hedged is $25.25. And the average price at which the U.S. natural gas is hedged is $4.40.

For the year 2003 we have 70 percent of our worldwide oil hedged and 35 percent of our U.S. natural gas. The average price for TI crude oil hedges in 2003 is 24.80 and the average price of foreign U.S. natural gas hedges is $4.05. At September 30th we had $94 million of after tax deferred hedge losses. $8 million of this is realized and taken into income in future months, $86 is unrealized.

Turning to refining and marketing, refining and marketing operating earnings amounted to $3 million in the third quarter of 2002 compared with $39 million in the second quarter. The corporation share over Benzus [phonetic] results amounted to a loss of $6 million in the third quarter compared with a loss of $18 million in the second quarter.

Refining margins continue to be depressed throughout the third quarter. A 58,000 barrel per day Coking unit at HOVENSA is now fully operational. Refining marketing earnings include $9 million of interest on the Pedvesa [phonetic] note in each quarter. The balance of the note of September 30th was $395 million and principal and interest payments are current.

Retail and energy marketing operations were profitable in the third quarter of 2002, but were below the results of the second quarter. After tax trading results in the third quarter of 2002 amounted to a loss of $14 million compared with earnings of $17 million in the second quarter. Year to date, after tax trading income was $4 million. Corporate after tax corporate expense amounted to $23 million in the third quarter compared with $18 million in the second quarter. The increase is primarily attributable to higher pension expense which is recorded in general and administrative expenses in the income statement.

Now turning to the special items shown below the operating income line. As previously mentioned, the corporation recorded an after tax impairment charge of $256 million to reduce the carrying value of certain producing fields and exploration acreage in the Gulf of Mexico. The charge principally reflects reduced reserve estimates on these fields.

In the third quarter we completed the sale of six United States flag vessels for $161 million in cash and a note for $29 million. The sale resulted in an after tax gain of $67 million.

The corporation has agreed to support the charter rate for the buyer for these vessels for a period of up to five years. A pretax gain of $50 million has been deferred as part of the sales transaction to reflect potential obligations under the support agreement.

In addition, during the quarter several small Gulf of Mexico oil and gas producing properties were sold at a loss of $25 million. As previously mentioned, the 10 percent supplementary tax on oil and gas profits in the UK was enacted, the corporation recorded a charge of $43 million to adjust its deferred tax liabilities.

Turning to some line items on the income statement, I'd like to comment on the variance in the line item other nonoperating income which is higher in the third quarter. The third quarter included a net pretax gain of $62 million from the asset sales I just mentioned. Currency gains before income tax effect are also reflected in nonoperating income.

Marketing expenses are lower in the third quarter than in the second because of special items recorded last quarter. The first was the reduction in carry value of energy marketing intangible assets, the second, an accrual for the refunding and marketing [inaudible] several, the two items total $35 million before taxes in the second quarter.

This concludes my remarks. I'll ask the operator to introduce the question period and turn the meeting back over to John Hess. If you will, operator.

Thank you. At this time if you do have an question, please press the star one on your touch tone telephone call. Again for any questions at this time, please press star one, and we'll pause for just a moment.

We'll take our first question from Stephen Pfiefer with Merrill Lynch.

Hi guys.

Hi Steve.

Could you go through in a little bit more detail exactly what's changing on the decline coming into volume expectation for next year? I think you referenced Gulf of Mexico, UK, and Colombia, steeper declines at the existing fields.

Could you give us a little more flavor in terms of the volume you're expecting, and I guess how bad do you think the U.S. gas lines will get next year to get you to a decline in that year? Is there a change in the capex as well? Are you - Is there a change in the expected capex from LLOG to other areas so there's a mix of production where you don't have the short-term startup that's going to other areas? If you could help us understand the change in the volume gross that would be fantastic.

John O'Connor is best qualified to answer the question of why this increased decline 2003 versus 2002 and also where our capex is going next year.

Hi, Steve. I think first of all what has been impacted by reserve we're talking about anticipating it probably contributes somewhere in the order of 12 to 13,000 barrels or the equivalent next year. Other than that, natural declines are in the order of 50,000 barrels per day, split between shallow, deep water and North Sea UK. Offsetting that we have about 25,000 barrels a day from newer developments or improved performance in existing assets.

In terms of capital shifts, yes, there is some capital shift obviously away from what has been contemplated for the LLOG properties primarily versus shelf for the main [inaudible] sound area but also others of our properties in the shelf and the Gulf of Mexico. I don't think that's a significant amount of capital movement, however, Steve.

The biggest change here sounds like it was in the Gulf of Mexico. I guess you did $355 million cubic feet a day U.S. gas in the third quarter. What does the expectation for next year?

We're still finalizing that, Steve, but you know, if you just take the barrel of oil equivalent John talked about and translate that to gas, I'd say part of it is the deep water, the Garden Banks 260 continues its decline, natural decline and also some of the shelf properties that we have.

Then on the divestments, if you could just update us on timing, are there dangers your mix of [inaudible]? What's the target from that program?

Yeah, the exact, the exact properties that we are going to be consider we're still fine tuning if the determination of what's going to be in that mix, and obviously in the next several months as those decisions are finalized then we will announce them in due course.

I think the important thing there is 5 to 10 percent of our current production, the reason we're doing it is to continue the process that we announced at the investor conference in May which is really to reshape our portfolio, to sustain a growth in value, focus on financial returns, not just production maximization, and emphasize the growth in our reserve to production life and lowering our unit cost.

And the majority of the properties that are being considered for divestiture in that category, I think it's also important to note that if we do not get an acceptable price, we will not make the sales, but certainly we're going to explore it in the marketplace and whatever proceeds we get will be dedicated to debt reduction.

And this is last, but could you give us any just sense of what the net income impact would be and cash flow impact of the divestments in terms of -

I'd like to give that to you. It's a little premature, but again, you can assume the majority of these properties would be some of the more mature, strategic for us, so I don't think the impact on net income would be as much as if it were something that were a little more robust. It's just a function of reshaping our portfolio to continually upgrade our assets that have a top portfolio as opposed to just a mature one.

Okay. Thank you.

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

Hi, guys. John, when you're talking about 50,000 yield per day, due to the [inaudible] on the governmental column there in North Sea, can you help us and maybe put yourself through in terms of how much of the 50 is going to be in Gulf of Mexico and corresponding the Colombia and North Sea?

Absolutely. John O'Connor, would you please address that, the major points there.

Yeah, there's a lot of offsets working in here, obviously, Paul. Deep water, which is as much oil as it is gas, is about 14 TBD down on current productions, shelf about ten, Gulf Coast about eight. Those include the effect of LLOG also. In the North Sea as a whole is it expected to be pretty flat, and so the declines I gave you are offset by other performance elsewhere.

Okay. How about Colombia?

Colombia, we're looking at this stage maybe about 4,000 barrels a day down off this year.

Okay. Also John, when we're looking at clearly that compared to what you previously expected is a pretty significant decline in the production as well as anticipated the current curve, how comfortable you are now that you are ready to get to consideration of the worst case scenario, or that you think you may have still have some risk on that?

Yeah, it's a good question, Paul. I think first of all it's fair to say that we have increased the degree of confidence that we have in the production projections we're getting from the asset managers. We have raised the bar of performance. We're insisting on a higher degree of possibility that projections will in fact be met. But as you know we're looking at multiplicity of fields, we're looking at operational issues, we're looking at a portfolio that has a combination of mature assets, water movements in some key fields that are not unexpected together with new developments which are subject to the usual timing uncertainties. What's the probability, I would say, working towards an 80 percent probability that this is the number that will be developed, so we have a good reason to expect some upside about equal to the downside on the number.

Okay. Two last questions. One on LLOG, what is the current production there? And second, due to the weight and carrying force for LLOG, what is the next DD and A impact for quarter in the fourth quarter, it should be lower, right?

I think what I'd like to do on the DD and A is going to John Schreyer and John O'Connor will address the production, so -

The DD and A, Paul, will be in 2003 reduced by 40 cents a BOE for all production. By operation of this writeoff and then 35 percent in - 35 cents in 2004 and 30 cents in 2005. But 2005, three quarters of the remaining LLOG reserves will have been produced.

John, do you have an absolute dollar term?

For the reduction in DD and A? Yeah, $32 million in the fourth quarter, $67 million in 2003, $61 million in 2004 and 55 million in 2005.

On the production rates, Paul, we're currently using 135 million cubic feet a day. Turns out to an average of 133 for the third quarter. And we're probably expecting something like 120 million cubic feet a day on average for the fourth quarter.

And so in other words that John you are expecting the LLOG will be cut in half on the average for 2003 production compared to the current level, right? You think the LLOG is going to have an impact of 12 to 13 BOE per day?

Yeah, it's about 40 percent, I'm told, 40 percent decline.

If I could, last question, John, on the 5 percent annual production growth rate you're still looking for the 2004 to 2005, so that implies that you're going to raise the production from 2003, which is about 415 to about 520 by the 2005, can you maybe lay out in a little bit more detail for us what projects will be contributed that the increase and what is the underlying, the kind of curve that you are assuming for your base operations?

Absolutely. John O'Connor will address that question.

Paul, we're expecting about a plus 180,000 barrels a day from new developments that are not currently on production, and as John said in his remarks, the bulk will come in '05 itself. About a little under half of that will come from the northern block G developments and Ceiba. About 30,000 barrels a day from new developments that we have sanctioned or are about to sanction in the North Sea.

We also have close to 20,000 barrels a day in Southeast Asia, in our Pangkah, Jabung, Jambi Merang gas developments. We expect increments in Algeria. We also expect Alano [phonetic] to come on stream and to be fully producing in '05. And offsetting all of that, we'd expect somewhere between 100 to 110 barrels a day of natural decline, again about half of that in the UK North Sea, pretty much the rest of it in the U.S.

How much is the decline, John?

In the base decline it's somewhere around 10 to 12 percent without capital reinvestment.

And so what is the expected decline, then? You think that without capital investment, then. After capital investment, what's your -

It's around 6 percent.

Six percent in both U.S. and North Sea.

Yeah, you have to be careful with the North Sea because there's a variety of fields that have different characteristics, and again, I would point to the fields like Shehiya [phonetic], like Saranna [phonetic], like Valhall, all of which are on a growing trajectory. So you have a mix of properties.

Sure and in [inaudible] was your production estimate for next year is it still 60,000 barrels per day?

We - in fact one of the elements of not significant ramping up production next year is our view that we have got to manage the Ceiba field in a way that's prudent. We've got a lot of activity going on there. We have had drilling producers and injectors, we have water injection, we have installation of sub C pumps, we have installation of a combui [phonetic]. We are constantly upgrading the management reservoir management model and all this leads us to the belief that at this stage a prudent forecast and a prudent way to manage that field is not to have the ramp up in production that we previously anticipated but to have production flat certainly for the next twelve months or so. So we think we're going to average 40,000 barrels a day for Ceiba this year. At this stage of our planning we're projecting a similar number for the average for next year, which is net.

Thank you.

Thank you. We'll move on to John Selser with Johnson Price.

Good morning. I had a question will the LLOG acquisition. When you acquired those properties, did LLOG provide you with an independent reservoir engineering report, and if so, who did that? And then I guess on your side when you bought them, did you have an independent reserve engineer look at those? And if you did, again, who would that be?

I will answer that. No, I can't recall who the reserve engineer if there was one on LLOG's half, but I can assure you, Amerada Hess had Guy McNaughten [phonetic], who certified their own estimates along with our own and quite frankly we put a pretty big risk factor in it, not a big enough one as it turned out. But we did use D and M, if you will, to look over our shoulder and give us a separate third-party opinion, and we do that on any major reserve acquisitions that we do.

And where there was a failure, you kind of sum that up or -

It comes down to reservoir performance that the reserve watered out sooner than we expected and has to do with the maturity of the gulf, I guess, and we tried to put some of that factor in, but obviously it wasn't enough.

Thank you.

And we'll move on to Arjun Murti with Goldman Sachs.

Thanks, a couple of questions on EG. What hurdles remain from an approval standpoint to getting the Okume, Oveng, and Elon fields on line? I know there's been some talk of the government slowing developments. Are you authorized currently to move forward, or might we have some risk of delay on that one?

Arjun, I think the process is working just as we expected it to do. In a nutshell, what we do is plan fairly detailed plans for each of the fields. We're planning to submit for Okume and for Akom this year. We have got to have consultation with partners with the Ministry of the National Oil Company [inaudible]. All of this is proceeding as expected as normal. As a matter of fact, there is a meeting of all parties which will take place in London tomorrow. Part of the process.

The first field has gone to the government for review, the second will go in shortly, the third one will be in the middle of next month. So right now we are - the process is working without any distraction or any bumps in the road. As would whether we'll get all the approvals by year end or not, we have been pushing for that. We recognize that is an aggressive scale. It may or may not happen, but we don't see anything to believe the due process isn't working exactly as it's supposed to.

And in terms of some of the rumors, Arjun, that came out, they were unauthorized statements and we've been given assurances from the highest level of government that they want our investments and they will handle the development proposals in the normal course of business. And everything we've seen so far they're acting very responsibly in that regard, and when they make their decision they make it, but everything's moving forward pretty much on schedule.

Thank you. And in terms of the U.S., you've highlighted the declines for '03. What new field startups do we have in '04 that might help offset the further declines in '04, or are we looking further declines there?

We expect to see some modest growth in '04 versus '03. The key in the U.S. will be the Lionel [phonetic] start up, which is operated by Shell. We still think the process is on track fairly aggressive startup of first quarter '04.

First quarter of '04. What else have you got coming out of the Deep Gulf?

At this stage, nothing in particular.

So '05, you know, we build up in '04 and you annualize it in '05, but we need to do new discoveries?

Absolutely, and you heard John O'Connor say modest growth in '04 and all of those developments, God willing, will come on in the '05 range.

Thank you very much.

And moving on to Bruce Lanni with AG Edwards.

Yeah, good morning, gentlemen.

Good morning, Bruce.

Just a couple of follow-up questions, I tuned in a little bit earlier, but going on to LLOG and the writedown that you took this quarter, would you anticipate that there could be potential writedowns in the future or do you think it's pretty much it for LLOG?

I'll let John Schreyer address that.

We think it's pretty much it, Bruce, but let me tell you the parameters. We have now written the investment on the books down to $215 million. We think there are still 16 million barrels of oil equivalent reserves there. If - we have valued those at strip prices, but much of that is hedged so it's likely we will get those prices. If we - if that happens and we run out those reserves as anticipated, they'll be because of the discounting that goes into this process they'll be at least a break even from now until the time the reserves run out and three-quarters of them will be produced by 2005.

Okay. And then one other question, then, and in regard to you addressed the issues about DD and A pretty clearly about the reductions, what we're going to see over the next three years. Can you answer the same questions or potentially guide us in a direction if you were to make the asset sales that you're talking about, the 5 to 10 percent of current production, what would the potential change in your operating cost, your DD and A be in the 2003 to 2005 time frame?

It's a fair question, Bruce, but it's a little premature in that the final determination of the asset details have not been made. But some of the earlier modeling that we've looked at that's very preliminary obviously would be a downward movement. As I said before, our goal is to reshape our EMP [phonetic] portfolio to sustain a growth in value, and part of that is to lengthen the reserve life but also lower the unit cost. Those asset divestitures for the most part will help us continue on that direction.

But I guess it's safe to assume, though, from what you've said they'll have a minimal impact or small impact on earnings, so it should be a pretty significant contribution to your lowering operating costs.

Right. I would rather not speculate on what the potential impact is, but directionally it would help the unit costs go down.

Thank you very much.

And we'll hear now from Paul King with Saloman Smith Barney.

Good afternoon.

Good afternoon.

Some quick questions. First of all, on your divestiture, the stated goal for the divestiture is to use the high cost field and increase the reserve life. I'm wondering if you would give us the metrics in terms of whether that translates to some kind of a [inaudible] target or reserve life target? Any metrics you can share with us on that?

Well, our long term targets and it's a very fair question, Paul, we're not going to get there overnight and we're going to be very focussed in getting in the directions of these targets is to have ten reserve to production life and a $12 unit cost target and that's the trajectory or direction that we're going to be moving the company in.

Again, I repeat, we're going to run our company on the basis of financial returns, not just production maximization and to do that we have to reshape our EMP business. We talked about that in the May investor conference and the asset divestitures are part of that initiative.

And the cost, unit cost, can you translate that to a millions of dollars in terms of absolute dollars target for us?

No, I can't at this point in time. Again, it would be premature.

John, I'm going to put you on the spot on the next question. I'm looking at the production profile. I know a lot of people asked questions about the production profile, but I'm having a hard time getting to about 520,000 barrels a day by 2005. You know you said this year is 456 and this year you're likely to go 415.

That's correct.

Without the effect of asset divestitures, which could be 5 to 9 percent incremental. Am I right therefore your '03 is going to be like the 380, 390 level?

Again, as I mentioned in the conference call, the 415 is without the divestitures. Your number is directionally correct if we make the asset divestitures, again, we'll only be doing it if we get attractive values, but we have a very healthy portfolio of developments, good use of our cash to create future value for the cash.

And John O'Connor pretty much outlined, you know, the significant amount of barrels per day that we'll be adding in 2005 on top of whatever the new base is, be it revised base or the one I just mentioned.

Let me zero in on that. If I understand what John said, that new production increase, 180, the decline is going to be 110, implied a net increase of 70, if I superimpose that on top of 380, 390, I don't get to the number of 520ish by the year -

You have to compare it to where we were in 2002.

Ah. So it's your starting point this year.

Yes, and I was pretty clear on that on my comments, but I'm glad you brought it up for clarification because I didn't want to confuse anybody.

That's a good clarification on your point. Last, debt ratio, what is your debt target, if any?

Our debt target we want to get to the range of 45 percent, and really the range of our debt target is 35 to 45 percent debt gap. And as I mentioned before, should we be successful in our asset divestitures, they will be dedicated to the pay down of debt.

Thank you very much. Appreciate it.

Thank you. Good question.

And Mark Gilman with First Albany has our next question.

All right, guys, I got a couple of things. Regarding the oil and gas reserve adjustments, can you comment on what the impact is on probables pursuant to some of the slides you've used in recent presentations?

Mark, hi. If you're talking about LLOG, which I guess you are talking about -

John, I'm talking about any probables that contributed on properties contributing to these decisions.

Yeah, that's - $13 billion [inaudible] of equivalent, yeah.

Production and probables over and above proven?

Yeah, that's right.

Okay. John, in your discussion regarding Ceiba, you used a lot of qualitative observations, and we're at a fairly critical stage in terms of the performance of the water flood. Would I be reading too much into your remarks to say that that water flood based on the data that you have has not performed up to specs?

On the contrary, Mark, I would say it's performing as expected at this early stage of injection. Obviously the ultimate performance is going to depend on surveillance and further optimization as we go along. So I hate to have to tell you the same thing I told you last quarter but that's actually the reality. In terms of ultimate recovery from this field, we're about at 10 percent from the ultimate recovery so you can see it's early days here.

I think in that instance I don't quite understand, you know, backing off on the basis of quote/unquote prudence.

Well, we have a number of things going on. Remember, we had a couple of wells go down because of failed sand screen. We have another couple of wells that are impacted which were impacted by water load up in the well before water injection commenced. We're going to be putting subsea pumps in, they're in, and we're going to start commissioning next month. Let us see how that goes. Let us see how the repairs of the C2 and C7 go, let's get some more data on the water injection, then we'll be able to answer it more effectively.

Ten percent recovery rate, is that anticipated to be with water flood or just primary?

That's accumulated production of the estimated ultimate recovery. What I'm saying is the amount of depletion what is seen in a very sizable oil field is at the early stages of depletion.

Okay. Shifting gears just a little bit, I did not hear you mention either Valhall or Devil's Island in terms of contributors to the 5 percent growth going forward. Is there any change with respect to either of those projects?

No, there isn't. Valhall is certainly a contributor and I think I did mention in the context of the North Sea growth, Mark, but yes, it is one of the mainstays of our North Sea production. We're very pleased to have it and to be a party to that development.

I think in terms of Devil's Island, that is a commercial discovery. We announced it as such. What we're looking at doing is optimizing the development in the event further drilling in the vicinity leads to a greater volume to be developed. So we haven't included it. We haven't talked about it. It is commercial; it will be developed. The issue is how big the development will be, and that's dependent on drilling over the next six to nine months.

Okay. The LLOG net investment number, I think you said $215 if I noted it correctly, my arithmetic says that's about $14 and equivalent on remaining reserves or very close to that, sounds very, very high, even taking into consideration whatever you've been able to hedge going out through '04 and '05. How are you comfortable with a $14 kind of investment level given that the writeoff, I believe, has to be taken on a [inaudible] present value basis?

You have good math. It's $13.50 a barrel. The writeoff was taken with a 10 percent discount and the math just flows from that. It is - as I said earlier, it's the forward curve for natural gas and oil with the hedges included in it, significant amount of hedges, discounted at 10 percent compared to the book value, and that does reduce as you're pointing out the book value of $215 million.

So, John, I guess the point is if the forward curve were to deteriorate for whatever reason from the point we're at right now, we're not finished with this story.

Save for the hedges. Yes, there would be some decline, but a significant amount of this is hedged.

Finally, just one more. You referenced a UK gas property as part of the exploratory gas writeoff, $19 million, I believe.

Yeah.

Could you identify what it is? And I guess I'm a little bit struck by the fact that capitalizing these kinds of things has never been the company's style in the past.

It's the York [phonetic] field in the UK. It was a successful well, has proved reserves but doesn't meet our requirements for capital expenditure. Our policy is that if we have capitalized the well but in twelve months we aren't moving forward with it, we write it off, and so the York well was written off.

Okay. Thanks a lot.

We'll hear now from Fred Leuffer with Bear Stearns.

Hi, John.

Hi.

A couple of questions. First, you've taken negative reserve revisions of $29 million BOE in total; is that is? $15 million for LLOG in the second quarter?

Yes, that's correct.

And how much of the difference between the two, $14 million is more LLOG here in the third quarter?

10 million. And 4 million is for other properties in the Gulf of Mexico.

Okay. And how much of the charge of the $256 million is for LLOG?

All but $35 million pretax, $23 million after tax.

Okay. I'm having trouble getting some of the numbers up in terms of lower than expected production. In part because you guys never gave an official 2003 forecast up until now, but if I back up a ways and look at the forecast that was made last July when you bought, made the announcement on the purchase of Triton, you had said that 2002 would be 535,000 barrels per day so just taking that original forecast again for 15, that's 120,000 BOE equivalent less.

If we - last December you had lowered the 2002 forecast to 475, and again, if we just applied that to next year's forecast of 415, that's a 60,000 barrel of oil per day. And John O'Connor went through the sources, deep water LLOG on shore and Colombia changes to the forecast of 2003 which we didn't know what they were for, but that only totalled 36,000 barrels of oil equivalent per day.

So going back about a year, we're missing something like 20, 40,000 barrels of oil equivalent per day of expected production. Can you reconcile, where all the stuff went?

Yeah, Fred. There are two things that obviously have happened that we've had acceleration of production declines in some of our more mature properties, so it's a performance issue that is accelerated. Obviously LLOG is one piece that we wish had never happened, but also I talked about the deep water gulf, the shallow water gulf, and some of the other properties we mentioned and also there's been a deferral of some of the exciting developments we have and, you know, a bigger gap in between the time that when we anticipated they would come on over the last twelve months versus being able to give our investors the latest update on that.

So the two moving pieces, and it's just how it's worked out in terms of the specifics, I think John O'Connor did mention the major changes, be it from current production, or even we can take you from the 475, if that would help.

Yeah, from the 475 would be good.

Okay. He's going it refer to that right now.

Okay. What I would like to do, Fred, is just take you from the 475 original for this year to the 455 because I've already gone from the 455 to next year, and that happens to be the way I've got the data. So about eight associated with the reserve reductions between the 475 and the 455, about 18 associated with operation issues, by that I mean drilling slippage to Faroe other delays.

And if you want a breakdown of that, it's all over the place, frankly. It's in mature fields in the North Sea, it's in Ceiba, it's in a small number of properties, small contribution of other areas. Offsetting that is about an increase of 10,000 barrels per day. Better than we had built into the 475, primarily in the U.S. deep water, but also a little bit in Algeria.

Okay. What have you - what have development expenditures been in LLOG since the purchase?

I have the number for - since the purchase and including going forward and the development expenditures for that period will be $200 million.

All right, John, that's helpful. For LLOG, you gave us the decline rate for 2003. What would you expect to be the decline rate in 2004?

In production?

We'll try to get that for you.

The production in 2003 we said on a BOE equivalent will be 14,000 barrels a day. In 2004, it will be 11,000 barrels a day for LLOG.

Okay. All right, gentlemen. Oh, just one last question, John, do you have any hedges that - here you mention it, but do you have any oil and gas hedges out for 2004?

Yes, we do. 5 percent of our production for 2004 is hedged.

Of oil production?

Oil production, yes.

At what price?

About $24.

Thank you.

I think we have three more questions that I can see, so we should take them. I think Mark Flannery is next.

Please go ahead, Mr. Flannery.

Yes, just a question really on the target for '05, and I guess it's been asked in a few different ways, but how much slippage room is there in this target for 2005? I know a large chunk of it's going to be the Okume, Oveng, and Elon approvals which you're targeting for the year end.

Maybe one way I could ask this is when do they have to be approved by those three fields for the '05 number, to be safe and in general terms, can you give us some comfort on how much wiggle room is in that target?

Okay, John O'Connor?

Well, I think Mark, given that a significant component of the total increase in '05 is associated with an oil block [inaudible], as John said in his remarks, critical to achieving that increase is having government support for the development and executing the development in a way we see.

I'm not sure how to answer the question with respect to timing because this could turn out to be a self-fulfilling prophesy if one said there was a lot of slack in the schedule. But I would say the end of the year is not a deadline which then if not achieved would cause us to slip on the '05. We have built-in allowance for the normal course of events, delays in various items that go toward this, whether it be in approvals or execution.

Right, but if we're still sitting here as sort of the end of the second quarter talking about approval, that's a different story.

That's a different story, Mark, I agree.

Okay. Thank you.

Good.

And moving on to Matthew Warburton [phonetic] with UBS Warburg.

Good afternoon, gentlemen. Just a couple of questions. Obviously taken a bit by surprise in the substantial growth in hedge position for next year, obviously, somewhat to do with the high prices we've had for longer than most of us expected. How much did that play into the fact that with the production downgrade there is some nervousness about the cash flows into next year and the balance sheet position? And to follow on that the degree to which the 1.75 billion you outlined for capex, how much of that is absolutely required and how much discretion do you have in terms that you'd be expenditure if prices fall faster than maybe the industry expects?

The hedges, good question. The hedges have been put on not incorporating the fact that in the last quarter we've had more accelerated decline in some of our mature properties, basically it's the lock-in, the cash flow to ensure we meet our capital programs the next couple of years for the developments that we have.

So the production decline wasn't the driver; it was just making sure we protected the revenue line. Obviously the exact percent has gone up a little bit because the production is less, so the math is a little higher. So hopefully that answers your questions.

In terms of capital expenditures, where they finally end up, obviously will be focusing on the next several months, there may be some further reductions. And also if we end up making some of the asset divestitures we talked about, that in and of itself will help bring the number down. So, you know, there are a couple of moving pieces here. It's still preliminary, but directionally, I can assure you, we will be as disciplined an the capital expenditures as we can be and still build the company for the long term.

One final question, if I may. In the UK on the liquid side, obviously there's some operational problems that you had during the quarter. I think rights are being severed yet, your UK liquid seems to be relatively stable quarter on quarter. I was wondering if any things [inaudible] had anything to do with that, the numbers remained relatively stable.

No, I think that it's the net effect of a lot of moving parts. Matthew, basically first of all the operator was very expeditious in getting that production back on. We had a tally which was new production. We've had a couple of fields where we've had better than expected performance from infield drilling. So I think, as we said earlier, we talked about holding the UK production constant, and it's pretty much happening, although it's a bit lumpy.

Okay. Great. Thanks very much.

And our final question will come from [inaudible] with Petrie Parkman Companies.

It's actually Steve Enger. Hi, guys.

Hi.

I'll limit it to a couple of test ands Equatorial Guinea. Just to be clear, John, I think you said Okume, Oveng, and Akom are the first three fields -

We meant to say Elon, and I think the exact order we're going in is Okume first, Oveng second, and Elon third, but they're all within the next month, and the Okume actually has already been submitted. And as John O'Connor mentioned, we're meeting with government officials tomorrow in London to move this process forward in the normal course of business for them and for us.

That really answers our first question. Can you update us Equatorial Guinea exploration, give the results on G11 and/or G13 wells, and where do you go from here in that process?

Yeah, sure. The G11 was a disappointment. It was not successful. We did find uncommercial gas and we also found indications of liquid hydrocarbons on that well. We're currently drilling two wells in the same general vicinity as the G11, one in deeper water which got a couple of objectives, and one on the platform.

The G13 is in the deeper water. We are not at the primary objective in that yet. In fact, six or seven days to get to the primary objective on that. On the G12, that's also about five days and currently drilling 70 1/2 holes and it's also above target horizon.

And just to recall, that our program in EG has been focused on the requirement for relinquishment rather than on the requirement to add substantial new discovery. We'd like to do both, obviously, but we'd have a predicament if that were the outcome. I think we still have a significant inventory of high potential prospect left to be drilled once we get the [inaudible] relinquishment behind us.

Can you find of flush that out because you've drilled two unsuccessful wells in the northern part of block G and now an unsuccessful well in the southern part - excuse me, northern part of block F - and I'm sorry, an unsuccessful well in the Toe Thrust Play [phonetic] in the southern part of block G. Where can you see the potential, what's the nature of the potential given those results?

First of all, the southern Toe Thrust [phonetic] in the southern part of block G is G13 we still haven't tested, so I hope that that works. We tested a couple of fairly obvious fairways in the two wells in block F and we had technical encouragement in those. We are learning.

I would say that, you know, we had an exceptional run of success with the wildcats hitting one after the other, the first half of this year. So probalistic [phonetic] approach to this on balance we're going to come out winners, we think. We learn from every well that's drilled.

There were a couple of wells drilled before Ceiba was discovered all part of the exploration process. It just happens very quickly here for the reasons we've talked about in the past. There is still significant running room involved in northern block G and in block F and not to forget about block L where we will be drilling next year. We're got a couple of key wells where we will be drilling.

After the southern campaign in block G this year, one in F, one in G and we'll see where they go, but the results are helping us to build the model where we expect the high grade of prospectivity, and we would expect going forward to drill higher probability of success prospects, as I said once we have the relinquishment behind us.

Fair enough. And last could you give us an update on Shinzee [phonetic], and when we might expect results there?

And finally, John, and your Atlantic margin drilling you're going forward with Campos. Is there another well to drill after Campos or will that do it for this year.

We'll start at sort of the back under. Campos has a spot and is drilling, obviously four or five days into that and that will be it for this year, at least in that vicinity. There is another well where we have a small interest called Annatayas [phonetic], and that's more toward the rock [inaudible] and that's, you know, it's a toss-up whether it gets drilled at this point. It depends on the operator. We're not an operator interest in that.

As far as Shinzee [phonetic] is concerned, we are drilling ahead. We had mechanical difficulties with the well with a cement plug. We're drilling ahead, we're within about 2000 feet of planned next casing season. I would expect that we will be into the objective section in about 8 to 10 days after setting casing.

Great. Thank you.

Okay.

Thank you very much.

And that was our last question for the Q and A session this afternoon.

Thank you very much, everybody for joining us.

And I would like to remind everyone that you may listen to a rebroadcast of this conference at 3 p.m. Eastern Time through October 31st, midnight, by dialing 719-457-0820 or 1-800-203-1112, and enter confirmation code 701105 on your telephone. Thank you for joining us today.