赫斯 (HES) 2004 Q4 法說會逐字稿

Welcome to the fourth quarter 2004 Amerada Hess earnings conference call. At this time all participants are in listen-only mode. We will be facilitating a question-and-answer session towards the end of today's conference. (OPERATOR INSTRUCTIONS). I would now like to turn the presentation over to your host for today's conference, Mr. Jay Wilson, Vice President Investor Relations of Amerada Hess.

Good morning, everyone, and thank you for participating in our fourth-quarter earnings conference call. With me today are John Hess, Chairman of the Board and Chief Executive Officer, John O'Connor, President Worldwide Exploration and Production, and John Rielly, Senior Vice President and Chief Financial Officer.

Certain forward-looking information and other previously undisclosed items may be discussed during this call. I will now turn the call over to John Hess.

Thank you, Jay, and welcome to our fourth-quarter conference call. I would like to make a few brief comments on some key achievements of 2004 and provide some guidance for 2005, and then John Rielly will review the fourth-quarter financials before we take questions.

In 2004 we had a solid year of operating and financial performance and we continued to make progress in our development projects, exploration program, growing our reserves and strengthening our financial position.

In terms of our operating and financial performance, corporate net income for 2004 was $977 million. Exploration and production had a strong year. Earnings were $755 million, and production averaged 342,000 barrels-of-oil equivalent per day compared to our original forecast of 325,000 barrels-of-oil equivalent per day. In 2005, we forecast worldwide crude oil and natural gas production to average 350,000 barrels-of-oil equivalent per day.

Refining and marketing also had a very strong year, earning $451 million. The Hovensa and Port Reading refineries were able to operate at maximum capacity for the majority of the year, enabling them to benefit from the strong margin environment. Our retail and energy marketing businesses also performed well.

In terms of our field developments, significant progress was made in 2004. In April, the Llano Field commenced production and our 50 percent interest is currently averaging about 20,000 barrels-of-oil equivalent per day. This level of production is higher than our original estimate.

In August, the development plan for our Northern Block G fields which will now be called the Okume Complex, was approved by the government of Equatorial Guinea. Most of the major contracts for construction have been authorized. The development is on schedule and on budget.

In August, the scope of the project to redevelop the Gassi El Agreb Fields in Algeria was expanded from an original investment commitment of $570 million to $950 million. This change in scope reflects our success in the area. Since the year 2000 we have grown production, gross, from 20,000 barrels-of-oil equivalent per day to 55,000 barrels-of-oil equivalent per day, and we see additional opportunities to increase reserves and production.

In December, we negotiated additional gas sales from Block A18 in the Malaysia Thailand joint development area. The agreement will allow us to double our proved reserves in the JDA over the next several years and contribute significant future production growth. First sales of natural gas from the JDA are expected to begin by the end of the first quarter.

In December we sanctioned the Ujung Pangkah development in Indonesia. Gas sales from Pangkah should commence by early 2007.

In terms of exploration, successful drilling results at our Shenzi prospect in the deepwater Gulf of Mexico and the Phu Horm and Belud prospects in Southeast Asia will provide opportunities for future reserve and production growth. In addition, our prospect inventory is robust and we will drill several high-impact wells in 2005.

With regard to our year-end proved reserves, we are pleased to report that in 2004, we replaced 110 percent of our production at a finding and development cost of approximately $11 per barrel-of-oil equivalent. This result comes despite the impact of negative PSC revisions of 31 million barrels-of-oil equivalent relating to high year-end commodity prices. Proved reserves at year-end were 1.046 billion barrels-of-oil equivalent and our reserve-to-production ratio improved to 8.2 years compared to 7.5 years last year.

In terms of our financial position, our capital expenditures for 2004 amounted to $1.5 billion, of which $1.4 billion related to exploration and production activities. As a result of the solid operating performance of our assets and the strong pricing environment in 2004, we improved our debt-to-capitalization ratio by 2 percent to 40.7 percent at the end of the year.

For 2005, our total capital expenditures are forecast to be $2.1 billion, with $2 billion dedicated to exploration and production. This higher level of spending reflects the Company's strong portfolio of organic growth projects and attractive investment opportunities. We estimate that our capital expenditures and cash flow will be roughly balanced in 2005, assuming a WTI price of about $35 per barrel. And our debt-to-capitalization ratio should continue to improve through the year.

With an improving balance sheet, approximately 900 million of cash, and a new $2.5 billion revolving credit facility, our company has the financial strength and flexibility to continue to fund our developments and drilling programs.

In summary, we are very pleased with the performance of our assets and our organization in 2004, and are optimistic that the investments we are making for the future will grow our reserves and production profitably and create long-term value for our shareholders.

I will now turn the call over to John Rielly, who will provide more detail on our financial results.

Thanks John. Hello everyone. Our earnings release was issued this morning and it appears on our Web site. I will compare fourth-quarter results to the third quarter and then cover several other items.

Net income for the fourth quarter of 2004 was $229 million compared with $178 million in the third quarter. As indicated in the press release, we have two exploration wells drilling in the Gulf of Mexico, with associated costs capitalized on the balance sheet at December 31 of $35 million after-tax. If either or both of these wells are unsuccessful prior to the filing of our Form 10-K, the applicable well cost will be expensed, reducing our consolidated earnings and the exploration of production results I will be discussing today.

Turning to exploration and production, income from exploration and production operations was $211 million in the fourth quarter of 2004 compared with income of $155 million in the third quarter. The fourth-quarter earnings include a gain of $21 million from an asset sale and foreign income tax benefits of $19 million from a change in tax law and a tax settlement.

Excluding these items, E&P earnings amounted to $171 million, an increase of $16 million from the third quarter. The active tax components of the increase are as follows. Average crude oil and natural gas selling prices were higher, which increased earnings by $29 million. Crude oil and natural gas volumes, net of related production costs, were also higher, and that increased earnings by $24 million. Higher exploration costs decreased earnings by $10 million. Increases in production expense and DD&A decreased earnings by $22 million. All other items net to a decrease of $5 million in earnings, for an overall increase in fourth-quarter adjusted income of $16 million.

Excluding the special items referred to in the press release, the effective income tax rate on exploration and production earnings for the fourth quarter and full year 2004 was 47 percent and 46 percent, respectively. The 2005 effective income tax rate is expected to be in a comparable range, 45 to 49 percent, excluding the effect of Libyan operations. Assuming agreements are finalized and we return to our operations in Libya, the E&P effective income tax rate would increase.

Fourth-quarter 2004 production was 346,000 barrels-of-oil equivalent per day, an increase of 7 percent from the third quarter. The third-quarter production reflected seasonal maintenance in the North Sea. The after-tax impact of crude oil and U.S. natural gas production hedges in the fourth quarter of 2004 was an opportunity cost of $206 million compared with a cost of $180 million in the third quarter. At December 31, we had 60 percent of our 2005 crude oil production hedged. The average price for WTI-related open hedge positions in 2005 is $33.06. The average price for Brent related open hedge position in 2005 is $31.17. Approximately 20 percent of the Corporation's crude oil hedges are WTI related and the remainder are Brent.

In addition to the hedges I just mentioned, we also have approximately 24,000 barrels per day of Brent-related production hedged from 2006 through 2012. The average price of these hedge positions is $26.20 per barrel. There were no natural gas hedges outstanding at year-end.

The after-tax deferred hedge loss included in accumulated other comprehensive income at December 31, 2004 amounted to $875 million. Of this amount, 195 million was realized. Approximately 52 million of this realized loss will be recognized in the first quarter of 2005.

Our total unit cost per barrel-of-oil equivalent produced for the year 2004 was $17.26, compared with $17.32 in 2003. We anticipate our total unit cost for 2005 to be comparable or slightly higher than these amounts, depending on the results of our 2005 exploration program.

Turning to refining and marketing, refining and marketing earnings were $93 million in the fourth quarter of 2004 compared with $85 million in the third quarter. The fourth-quarter results include $12 million in income from the liquidation of LIFO inventories. The Corporation's share of Hovensa's income before income taxes was $21 million in the fourth quarter of 2004, compared with $75 million in the third quarter, reflecting lower margins. R&M earnings include noncash deferred tax provisions relating Hovensa's earnings of $3 million in the fourth quarter and $32 million for the year. In 2005, deferred taxes on Hovensa's earnings will be recorded at the Virgin Islands statutory rate of 38.5 percent.

Interest income on the PDVSA note amounted to $6 million in both the fourth and third quarters. The balance of the PDVSA note at December 31 was $273 million and principal and interest payments are current.

Port Reading earnings were slightly higher in the fourth quarter of 2004 compared with the third quarter. The results of retail operations increased in the fourth quarter of 2004 compared with the third quarter, reflecting higher margins and sales volumes.

Earnings from energy marketing activities also increased in the fourth quarter. After-tax trading results amounted to a loss of $7 million in the fourth quarter of 2004, compared with income of $11 million in the third quarter.

Turning to corporate, excluding the special item, net corporate expenses were $23 million in the fourth quarter of 2004, the same as in the third quarter. In 2005, quarterly net corporate expenses are expected to be comparable. In the fourth quarter, the Corporation entered into a new 2.5 billion revolving credit facility, expiring in 2009. Capacity under the facility can be used for or the issuance of letters of credit. At December 31, 2004, the Corporation has used $570 million of the $2.5 billion facility for letters of credit. The total amount of outstanding letters of credit at December 31, including the 570 million related to the revolving credit facility, was $1,487,000,000.

Turning to cash flow, net cash provided by operating activities in the fourth quarter, including a decrease of the $148 million from changes in working capital, was $254 million. The principal uses of cash were as follows. Capital expenditures amounted to $429 million; all other uses amounted to $4 million. We had a net decrease in cash and short-term investments in the fourth quarter of $179 million.

At December 31, 2004, we had $877 million of cash, an increase of $359 million since last year. Debt was reduced by $106 million during 2004 and the Corporation's debt-to-capitalization ratio decreased to 40.7 percent at December 31, 2004, from 42.5 percent last year. The Corporation had debt maturities of $50 million in 2005 and $78 million during 2006.

I have one last item to discuss. The Corporation is reviewing the repatriation provisions of the American Jobs Creation Act, including guidance issued by the Treasury Department in January. The Act provides for a onetime reduction of income tax to 5.25 percent on eligible dividends from four subsidiaries to the U.S. parent. The Corporation is reviewing the recently issued reinvestment provisions, and currently anticipates that by the end of the first quarter it will decide how much, if any, to distribute from its foreign subsidiaries. The Corporation will be required to record a tax provision on amounts to be remitted when a repatriation decision is made.

This concludes my remarks. We will be happy to answer any questions. I will now turn the call over to the operator.

(OPERATOR INSTRUCTIONS). Paul Ting, UBS.

A couple of questions. First of all, your CapEx increased fairly significant. Can you tell us whether any of Libya money is being budgeted for this year and any discussion about longer-term production growth rates? It looks like 3 to 4 percent in '05, but does this CapEx program alter your projection for the longer-term at all?

Paul, there is a modest amount in the capital program but it certainly doesn't speak to the increases. The capital program -- (indiscernible) say a couple of words about the capital program as a whole. This is really to continue our investment in field development that we've talked about in the past. I can give you a general spread of where the funds go. For example, the United States region is going to come out about $460 million of the capital program, Northwest Europe some $490 million, Southeast Asia, $200 million, and Africa, including a modest amount in Azerbaijan, some $900 million. The bulk of that, of course, is going to our two corporate projects in Africa, the development of what is now being called the Okume Complex in Northern Block G, which is well along in the spend phase of the field development. And also, our Phase II in Gassi El Agreb in Algeria will command significant amounts.

As to Libya, there is a modest amount at this stage in the program. And yes, there are production volumes in the production forecast for this year. On return to Libya, our 8 percent will command something like 20 to 25,000 barrels a day when that happens of the roughly 300,000 barrels a day that we think is being produced from the oasis concession areas.

Great, thanks for that rundown. Just a bookkeeping kind of a question. You gave us some indication about the reserve impact of the PSC. Can you quantify what the production impact might have been on PSC for the fourth quarter and maybe for the year?

The production impact from the PSCs -- about 20 percent from our production comes from PSCs. In the fourth quarter it wasn't a material amount of production affected by the higher prices from the PSCs.

And no material amount for the year either?

No. Really, there's some small decreases as it relates to PSCs, but not a significant impact.

Arjun Murti, Goldman Sachs.

Just a follow-up on the reserve commentary you made. I believe you said 110 percent reserve replacement at an $11 F&D cost, but I believe that was inclusive of the 31 million barrel PSC impact, which is a negative impact due to higher prices. If one wanted to look at it on a constant basis, would it be fair to add back the 31? You'd get the 135 percent reserve replacement at a $9 F&D cost. Would that be thinking about it correctly?

Arjun, I think that is the correct way to look at it, because technically, obviously, the reserves have not changed, the oil fields have not changed. It's a temporary pricing impact, perhaps, when one compares year-on-year. So I think you look at both numbers, frankly. But the pricing impact if you normalize it to the year-end 2003, then you have 170 million barrels of proved reserve adds, which would equate to 135 percent production replacement and a $9 dollar F&D, which by the way going forward is the sort of target range we're looking at, 9 to $10 F&D all in.

I guess that was really where the question was going. The capital spending is a bit higher, though, for everyone's stake in service cost inflation. But if you can do 9 to $10 F&D going forward that's probably going to be quite competitive.

That's really the basis for the capital program. We, obviously, have a significant suite of opportunities. We have high graded that suite of opportunities to target an addition of 200 million barrels a year of proved reserves, and hence the $2 billion or so capital program for E&P, with the implicit $10 a barrel F&D. We'd obviously like to exceed that, and if we had another $9 F&D year I think we would be continuing on a favorable track.

That's great. Just a final one, in terms of maybe you could flush out some of your impact exploration wells. I assume a number of those will be in the deep Gulf. I know you're drilling one (indiscernible). I don't think there's news out on that. I remember a Diamondback drilling. If you can comment on, I guess, any of those wells or any future wells, that would be great.

Interesting observation with respect to the Gulf of Mexico currently. We are involved in three different wells in the Gulf of Mexico, being Wembley, Diamondback, and there will be a deep tail on the Number 4 well at Shenzi which will go over the pre-Miocene.

At the present time, those three wells have drilled off roughly 60,000 feet of hole. We have drilled through about 20,000 feet of salt in aggregate. And when the three wells reach TD we will have drilled off 75,000 feet of section. Each of the three wells is currently roughly at 20,000 feet, and in the next 30 to 45 days we should have results from all three wells. So it's very exciting. Two of the wells going to the pre-Miocene and one going to the oil Miocene.

So it's still too early for news even on Wembley, which I think we all thought might have been sooner but it's still going on.

It's still going on. It's going favorably. It is on target, it's on track. It's currently drilling below 20,000 feet, ultimately headed to 25 to 28,000 feet, depending on what those measured depths are (inaudible).

I'm sorry; any thoughts on how the exploration wells progressed out for '05 after these three?

If we exclude Wembley and Diamondback from the count, and obviously they're going to expenditures and hopefully deliver positive results in 2005, we have in total 8 wells in the Gulf of Mexico that I would describe as impact in 2005. I would say 6 new and 2 that -- finding the results of Diamondback and Wembley, and 7 outside of the Gulf of Mexico in the international arena. So the other commentary I would make, Arjun, with respect to the exploration program this year -- 2004 was primarily oriented towards appraisal of prior exploration successes. In 2005, the program will actually be directed more towards rank wildcat drilling. So hopefully we're going to see positive results of that shift in emphasis towards rank wildcat drilling in 2005.

Steve Enger, Petrie Parkman.

John, in Algeria you guys obviously are increasing your investment meaningfully. Can you describe for us what you're going to get there in terms of incremental reserves and rate going forward?

Steve, this is a complicated function of the operation of the PSC in Algeria. Having said that, let me say first of all, by comparison with a number of other PSCs, this is a fairly favorable PSC. But production entitlement and reserves are a fairly strong function of capital program. So what I would say is we'll see increased volumes this year versus last. We'll see an expanded continuation of the higher plateau rate from those fields, and we will see additional incremental reserves booking.

So it's a very economically attractive project. But in addition, the operational deliveries from the spend in Algeria will be modestly higher, I would say, production volumes, but for a longer period than had previously been projected, and additional reserves being added primarily on the back of successful in-field drilling last year in 2004.

On 2004 reserve additions, John, was there some increment related to the late in the year sales agreement for additional gas at the JDA project?

Yes there was, Steve. That basically we view as a new project because it's a new gas contract, which allows us then to book reserves associated with what we call Phase II in the JDA. We booked a modest 16 million barrels, which is about 10 percent of the total reserves, which we think will flow through over the next three or four years as we conduct appraisal and development drilling in anticipation of starting up first production from Phase II in 2008. As John said earlier, the first production from Phase I will start by the end of this quarter.

So a modest amount of reserves booked in '04 on execution of the gas sales agreement, but I think you will see increased volumes flowing through over the next three years on the back of the drilling that we have to do to prepare for first production in late 2007, early 2008. But also, we will see, hopefully, additional proved reserves flow through as we see production performance from the fields coming onstream at the end of this quarter.

Okay thanks. Belud, the discovery off Sabah -- is there a market for gas if that ends up being a meaningful gas discovery?

I think of it as meaningful. There will certainly be a market one way or the other. It's an interesting question and one that we are continuing to evaluate. I will say that we have a couple of wells scheduled for late first quarter, second quarter of this year to follow-up on the success. We have a rig under contract for that, and I think the best thing to do is to -- if we can hold onto what we see just what is the size of the prize there, and then look to see how we commercialize it. But we're optimistic that we will be able to find a way to do that.

So if it's large enough you've got the LNG GTL options?

You're getting ahead of me, but there are all the viable options depending on what we find at the end of the day (inaudible) drill another wildcat and then a follow-up appraisal well.

Finally for me, on diamondback, can you tell us what you are working or paying in net interest maybe, and then, why you chose to get involved in that play? I am not aware that you have been involved (indiscernible) what you said. You certainly have talked about going to the lower tertiary at the Shenzi location. Is this some tie in that regard, or can you kind of talk about the strategy?

Absolutely. In point of fact, we were involved in the play early on. We participated in the Chinook discovery, which found a significant oil column, although we haven't talked too much about it; we're not the operator. And we has some question about the rock qualities and the fluid properties, quite honestly.

The Diamondback well is further to the West than Chinook was. We think it may be more favorably placed to give us a commercial shot in the pre-Miocene. So that's why we participated. And as I said earlier, the tail on Shenzi Number 4 is also going to take a look at the pre-Miocene. So we are very much in the play, we simply haven't touted it as such because we're primarily focused at this time on appraising our discoveries and drilling our rank wildcats to the Miocene.

Others are doing that, the promoting part.

I don't know what others are doing, but I'm just saying our focus right now is on the Miocene. We have our hands pretty much full with that. We are excited by our prospects and by what we have found already, but that's not to say that we want to ignore the pre-Miocene. We want to be involved in that in a judicious way.

As to your first question, we have a 50 percent working interest in Diamondback and the paying interest is confidential to -- what did I say -- 15 cents.

Jeff Dietert, Simmons.

I will shift to the refining side. I was wondering if you could quantify the change in the retail contributions in the fourth quarter relative to the third quarter?

Retail was up significantly in the fourth quarter versus the third quarter, so we were up a good 20 -- over $20 million in retail in the (technical difficulty)

(technical difficulty) Venezuela medium, 120 of Venezuelan heavy. I think you have talked about those before. Is the remainder Cabinda, or is Cabinda a good crude to use as an indicator there?

We use different African and North Sea crudes predominantly on the low sulfur variety, according to which is the most economic. And it just depends on the availability and the economics at the time.

Fred Leuffer, Bear Stearns.

A couple of questions. First, in the production forecast of 350,000 barrels-of-oil equivalent, how much if anything is in that for Libya?

Fred, as I said earlier I think that when we reenter Libya the rate will be somewhere between 20 and 25,000 barrels a day for our 8 percent working (inaudible)

Is any of that included in the 350 guidance?

Yes, it is.

All of it?

A lot of it.

John, does that suggest that base production will be down in '05 versus '04?

No, it just means that we have flexibility around the portfolio. The entry rate at the beginning of the year is about 355 and the exit rate is about the same.

If we exclude Libya, what sort of average would we be talking about for '05?

I don't really have those numbers to hand, Fred.

I think you indicated that in the CapEx program you have something for Libya. How much is allocated for Libya?

Fred, what we are doing there is because the terms are not finalized it's premature for us to give out a number. As John had said earlier, there is a moderate amount in there. We have a placeholder in the CapEx budget for Libya, but we're really just not at liberty at this point to disclose that. None of our partners are disclosing a CapEx number.

Along the lines of Libya, just for an update, negotiations of the economic terms for reentry are complete. We have been waiting for the government of Libya to ratify the terms. It is moving forward in there approval process. So while it hasn't happened yet, we do think it will be happening soon.

I guess what I am a little confused at is I would have thought that your production would be 350,000 barrels a day without any new developments like Libya. Has something dropped out of the production forecast or been moved out, or is there some acceleration in the end-of-line production decline?

I don't know what your assumptions are, Fred, but these are based upon our reserves and a lot of homework by our engineers. And we feel very good about it and it's pretty much what we thought it would be.

Just to add, we started the year at 325 with our forecast. We were talking about being basically flat in '05 when we started talking about it, because a lot of the developments, let's say at the Okume Complex, doesn't come on until 2006. So this really isn't a change in our production forecast. Sorry -- 2007 for the Okume Complex. So no real change in our forecast that we had from earlier.

Where is Sabah production currently and when do you think the decline rate may begin there?

Sabah production currently is about 40,000 barrels a day gross, which we have previously said is the maximum economic rate at which to operate that field. It may trend upwards a little bit in the first and second quarter this year as we bring a couple of new wells online. We previously said also that given that we operate the field at that rate, we would see an extended plateau at that rate. So it's far too early in the life of that field to talk about production (inaudible)

Maybe you could go through the components of unit cost in E&P, John. And I think you said that they will be flat in '05.

That's correct. Flat to -- I think (indiscernible) it could be slightly higher depending on the results of our exploration program. But for the year the 1726, we had $2.30 for exploration, lifting costs were $6.59, G&A was $1.03, and DD&A was $7.34.

And do you have some fourth quarter?

The fourth quarter numbers, I just want to say that they don't represent a run rate because as we said all during the year, we were going to be comparable on our unit cost for the year. So we knew we had a back-ended program, so I just want to give that caveat. The unit costs in the fourth quarter were above -- were $19.35, reflecting higher exploration of 260, our lifting costs of 750 had higher work-overs, the re-commissioning of the JDA, again, just timing of expenditures. Our G&A was at $1.03 and our DD&A was $8.22.

Let me just give some color commentary to the unit costs. What we are basically saying is that production cash costs are pretty much in line '03, '04, '05. They are very much under control, and to the extent we're wringing costs out of the system. We have sometimes got one-off costs as we prepare new fields to come on production. And whether that is the JDA which we had to recommission in the fourth quarter, or whether it's preparation for reentry into Libya or costs associated with the start-up of Clair next month, these are financially part of the ongoing business. G&A at $1 or less than $1 -- pretty competitive I would argue.

So on a cash cost basis, the only variable is exploration. Now, unlike many of our competitors we half said that we're going to grow this business organically. We're going to do it through exploration. I talked earlier in response to the a question about the opportunity we have in our prospect portfolio in 2005 to get significant exposure to high-impact rank wildcat trailing. The costs associated with that are ones we're happy to incur because we can demonstrate value creation over the long-term.

The outcome from that at this stage we presume to be of the order of 80 percent dry, and that assumption rests (ph) into the projection of unit costs. In the event that our experience is better than that, and we expect it to be better than that, exploration unit costs will come down. As to noncash DD&A, 2005 is roughly comparable with 2004. So the variation you will see as we go through the year will be primarily dependent on the outcome of the exploration program.

Just one last one. In the reserve replacement, are there any lines for acquisitions or divestments?

There is a line for acquisition and divestments, and it's pretty much a big duck egg zero. Okay? Basically, if I could just say a word about the reserves, we have had the -- obviously, the new field start-up additions which were sanctioned last year. That was significant. But across the board, with our focus on improved reservoir management of our assets, we are seeing increased -- modest increases pretty much throughout the portfolio in the reserve base as we sharpen our pencils and increase our reservoir management skillset.

Doug Leggate, Smith Barney.

You mentioned in the release that there were some disposals in the quarter. Were they material, and if so, can you tell us the volumes associated with them?

The volumes were immaterial, real small. Two oil fields, West Delta 79, West Delta 86. Production was 752 barrels per day; it was under 1,000 barrels a day.

John O'Connor, you gave us some indication as to what you think the production share is going to be in Libya. It sounds like you guys are pretty confident in getting in there fairly soon. What about the reserves impact? Assuming you get this before you submit the K in March, would that be additive to your reserve replacement that you've already brought in for last year?

No. We're basically closing the books on last year with the numbers that we have given you, Doug. And we're not really talking a range of numbers for reserves booking, although they would be booked at the time we execute the agreement. But we would be more comfortable. And of course we have all of 2005 to do so to better understand all of the moving parts with all of the assets in the oasis concession areas, and work the data ourselves to come up with the number that we feel highly confident about.

So no preliminary estimate as to what your share might be?

None at this stage. We definitely need to get in and work the data, and quite frankly, participate with NOC in operating the field so we get a better understanding.

One final one for you, John, if I may. The exploration expenditure in '05 -- I don't think you gave us that number.

I think that may be right. We have said for some time, Doug, that we want to run a consistent year-in year-out exploration spend program of the order of 320 to 350. This year it's going to be around 350 on the spend basis, unless we find that we have incremental opportunities from that are simply too attractive to bypass. But we try to manage this program at between 320 and 350, so this year it's targeted to 350.

Just one final one for John Rielly. It's kind of, I guess, an exploratory question really. Your reserve replacement, obviously, has turned fairly positive this year. Your F&D costs are coming down. You're imminently probably going back into Libya. What is the view of the credit agencies on that? Because clearly there's a number of those metrics that they have been looking at. Are you optimistic that you might see some kind of a positive revision to your rating, and if so, what would be the impact on -- with your financing costs and maybe your refinancing plans going forward?

It's a bit premature. Obviously, everything we have talked about is good news. And we have talked to the credit rating agencies about it. They understand it. They're waiting, obviously, until the Libya deal is signed, too, and it's all positive news. Could I predict right now exactly what they will do with that news? I don't -- but obviously I'm happy we are in a position that we are coming in with good news, and we are basically meeting all expectations that we set out for ourselves and set out for the rating agencies.

I think one other thing I might say from that perspective, obviously, investment-grade rating, a BBB+ target is important to us. We have to balance that with the investment mode we are in with the attractive investment opportunities, which is priority number one for our cash. But having said that, when we started 2004 we had some major objectives on the development side. And as I recall, in some of the comments that were made by the rating agencies they were concerned about the execution of development risk.

And we said we would get Northern Block G, which is now the Okume Complex, sanctioned for development by the government of Equatorial Guinea. That happened. Llano came on in April. That happened, and it's actually exceeding our original estimates of production. The second phase of gas sales from the JDA occurred, and I would say first gas sales are certainly expected by the end of the first quarter in the JDA.

And we continue to make progress on our other developments. Ujung Pangkah got sanctioned before the end of the year. So a lot of progress was made on the development front, which was one of the major risks that the rating agencies highlighted. So we think we made tremendous progress there. We're also proud of our people's accomplishments in getting all these done in '04. So that, along with the reserve replacement and the competitive F&D -- I think it's a pretty strong story, but we'll have to wait and see how the rating agencies feel about it.

That's great. Just one very last one. The reserve replacement -- that was all organic?

It was, Doug. And in fact, I think it's the first time since the mid '90s that we have exceeded more than 100 percent production placement organically.

Paul Sankey, Deutsche Bank.

Your production base is shifting quite rapidly. I wondered if you could make some observations on the heavy/light makeup of that slate, and perhaps slate (indiscernible) as well.

In terms of our production base shifting, a lot of it is African crude. So we don't see a material change in terms of that mix, if you will.

So broadly speaking, you've got a fairly light slate that will remain fairly light?

That's correct.

Just on the North Sea declines we're seeing, is there anything to be added on those? They seem to be very rapid just looking at the numbers.

No. If you're just looking at fourth or third quarter on the crude, we really had mechanical issues there. Our Fife, Fergus field was done between 2 and 3000 barrels a day. We actually had our annual shutdown in the fourth quarter on Fife, Fergus, and also we had a three-day unplanned shutdown there. Ivanhoe/Rob Roy was down one for some generator repairs. Zitheren (ph) was down 1000 barrels for some compressor refurbishment. And (indiscernible) we had an engine change-out and some adverse weather affecting (indiscernible). So there really -- there isn't anything outside of mechanical happening there with the UK crude.

As the kind of detail question on that, are you finding that there's an acceleration in the number of problems that you're having in these mature basins, or is that just the normal level of outage that you would have expected to see in the fourth quarter?

That's about the normal level of outage for it. We don't see anything extraordinary happening. There were some weather related issues with respect to loading both at South Anna (ph) and at (indiscernible) for example. Weather is a normal hazard in the winter in the North Sea. And the mechanical problems are basically what we build into our forecast. And I think that the validity of this is the issue that we have projected 340,000 barrels a day in June. And we exited the year -- the full year at 342. And that tells you there's nothing unpredictable or unforeseen happening. We make provision for routine outages from these fields. The operators are paying close attention in this multi price environment. So there's absolutely nothing.

And just on Hovensa, I was wondering about Venezuela and if you could make any comments about perhaps if you'd been in any way impacted by management changes at PDVSA, or any other for-the-record type comments you could make to me?

Absolutely no. Our Hovensa joint venture continues to work in an excellent fashion. We had a great year of operational excellence where both sponsors contributed in that success. Crude deliveries are on time both for the heavy and medium crudes that are 60 percent of the supply, and the Venezuelans are current in all their payments. So whatever may be going on in the country politically, I think this partnership is important to them; it's certainly important to our company, and it is working well.

Thank you. Finally, the repatriation act -- you specifically chose to raise that issue without kind of saying why in many respects. I'm not quite sure what the point is there. Are you saying that you may make a major repatriation and it may be beneficial, or what?

The repatriation provisions are definitely beneficial for us at giving us a onetime opportunity to bring back foreign cash at a less cash cost than it would cost us normally. The reason I was bringing that up is we are likely to make a decision in the first quarter, and as a result, we would book an associated tax charge on any repatriation decision. So that is going to happen. It will happen in the first quarter.

There also is a possibility that, especially with prices staying where they are right now, that if we have excess cash flow later in the year we could make another dividend later and have another tax charge associated with it. That's the only reason we brought it up.

So does that become a balance sheet benefit and an earnings charge, or how would that work?

I mean, it is an earnings charge. But ultimately as that cash would have been brought back, if the law had never been put in place as onetime opportunity, it would have cost us more in the tax line over time.

I'll not try to go into too much detail on that. Thank you.

Paul Chang, Lehman Brothers.

John, when I'm looking at your capital spending, 2.1 billion for 2005, looking out for the next two or three years, should we assume that that probably will be the minimum that you're going to spend given you still have some pretty large projects that continue to spend?

Paul, we basically have a philosophy of managing the capital spend for the Corporation within the cash flows of the businesses' trough (ph). So we think the opportunity set could command around $2 billion a year and that it would add significant shareholder value. However, outside of the projects that we're committed to there are discretionary elements in the capital program which we can vary, depending on the cash flows that the businesses generate. I would not like to make a forecast beyond '05. I would say that we expect to have an opportunity set that could command that level of investment spend and generate favorable returns.

John, your drilling program has been quite successful over the past two years. Congratulations on that. Based on your best guess, what has been the finding costs over the past two years for you?

First of all let me say, Paul, that I appreciate your observations, and so do our explorationists (ph). The second thing I would say is that we keep a running track of each well we drill and each seismic program we acquire of the cost versus the value we think we generate from discoveries. And I'm happy to tell you that as a result of the program that is very much in the positive; that is to say, we have created more value than we have spent on the program.

Finding costs are a bit of a difficult animal to tie down, quite frankly, because the issue is what denominator do you use. Do you use P plus P? You know? If so, on a P plus P basis, my guess is it's somewhere between 2 to $3 dollars a barrel, frankly. Other purists will demand that you use proved reserves. And as we know, the problem with that is they only get booked over an extended period of time.

I'm looking at, say, on a full cycle business that what is your best guess -- that's why I was asking (multiple speakers)

I think that, you know, what we are really targeting with the 300 to $350 million program is to find 200 million barrels of commercial reserves every year. So that sort of implies $1.50 to $2, that range. And I think we're getting close to that.

John, can you remind me when the gas sales contract, too, for JDA is going to start?

As part of the contract it is not later than the beginning of 2008.

Is that also 395 million cubic feet?

It's actually a 400 million cubic feet a day, but whose arguing about 5 million cubic feet a day (inaudible)? So we would expect certainly by January of 2008 that that joint venture, where we are with 50-50 Petronas Carigali, would be moving 800 million cubic feet a day of gas (inaudible)

If we are looking at your portfolio today, and let's for a minute exclude (indiscernible) and just look at your current production in (indiscernible) -- should we -- on a going-forward basis should we assume a natural decline rate somewhere in the 8 percent a year before we, say, add back the major projects? (multiple speakers) a reasonable assumption?

I think that's a good assumption, Paul. That's what we have seen. I'm glad you brought that up really, because there were some inferences earlier that maybe there was something unexpected happening. That is not the case. Quite frankly, if you picked up on my observations with respect to reserves earlier that across all of our assets we have seen an increase in proved reserves -- which means that the assets are somewhat more robust than we thought 12 months ago, which implies that production is not going to decline at the rate we might have thought 12 months ago -- all of this leads you to an underlying decline in aggregate for the portfolio of somewhere between 7 and 8 percent.

Excellent. My final question is on the downstream. John, I'm wondering if you can just comment -- the (indiscernible) refinery that turned around for 2005 -- is that going to be comparable to 2004, or it is going to be lighter or heavier?

The major work in Hovensa this year is (indiscernible) of our cat cracker. It was taken down last week. It should take 40 days or so to complete the work. So it is underway as we speak. That is the major work. I think there's one crude unit as well that is being planned. That is the scope of work to the best of my knowledge for 2005.

Jennifer Rowland, J.P. Morgan.

Just a quick question on the deferred hedge loss. How much did you realize in the fourth quarter? And of the remainder I believe you said was 195 million to flow through in '05. Should we assume that that flows relatively evenly throughout the quarters?

Yes. Let me just answer you second one. As far as the 195, you can see 52 million is coming in the first quarter. Right now I would say go head and do the straight line, and we will constantly update you on each quarter's conference call and provide you with the amount that's going to flow through in the following quarter. And I'm sorry; your first question was?

How much was in the fourth quarter?

In the fourth quarter we actually realized a total of 206 million of our hedges. Are you trying to say how much was from the realized from the prior quarter?

Right. I think your guidance had been for 80 million.

Yes. So it was 80 million that flowed through. So 80 of the 206 was from that realized loss.

I'm wondering if you could give us your oil realizations, excluding the impact of hedging, if you have that handy?

Yes. Hang on one second. So basically you are looking for the differentials in the fourth quarter?

Correct.

On a WTI basis, it was just over $5 differential in the fourth quarter. Again, I think our sweet, just like everybody else's, was the light heavy and the sweet versus crude spread widened in the fourth quarter. And ours did from -- it was about $3.36 in the third quarter -- went to $5.07 in the fourth. On the Brent side, we went from a 14 cent differential in the third quarter to a $2.23 differential in the fourth quarter.

Mark Tibble (ph), Barclays.

I was just wondering if you could tell me what was the PUD percent at the end of the year, and how many reserves are booked for Block G, if you booked any at all?

Let me answer the second question first. We booked about 48 million barrels associated with the plan of development for the Okume Complex, which is now the current name for what was previously called the Northern Block G fields. We think that is about a third of net ultimate comparable reserves. So as development drilling proceeds we'll have reserves from drilling, and then as we see performance over time, we will get the rest of the reserves that we expect there. In terms of PUDs, I believe -- although I don't have the figure (indiscernible) -- that it was 37 percent or thereabouts. So it's been consistent over the past three years or so.

One last question. On your bank facility, was it roughly 1.5 was drawn on the facility?

No. The 2.5 billion revolver -- what we have utilized of it is for letters of credit, and we used $570 million for letters of credit.

Was drawn?

Correct. For letters of credit.

If you do get upgraded, do you need to use letters of credit anymore? Is that because of your ratings?

You still will need to use letters of credit. The amount of letters of credit could change depending on the counter-party margin requirements. But if you are upgraded -- if we are upgraded by Moody's to investment grade, it could lower the amount of LCs that we have outstanding.

That concludes our question-and-answer session. Gentlemen, please feel free to continue with your closing comments.

Thank you, everybody, for your interest in our company and attending our conference call. And we look forward to updating you as we make progress in 2005.

Ladies and gentlemen, thank you for your participation in today's conference. This concludes the presentation and you may now disconnect.