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Amerada Hess (NYSE:AHC)

Q4 2005 Earnings Conference Call

January 25th 2006, 10:00 AM.

Executives:

Jay Wilson, Vice President, Investor Relations

John Hess, Chairman and Chief Executive Officer

John Rielly, SVP and Chief Financial Officer

John O'Connor, President Worldwide Exploration and Production

Analysts:

Arjun Murti, Goldman Sachs

Bruce Lanni, AG Edwards

Steve Enger, Petrie Parkman

Paul Sankey, Deutsche Bank

Doug Leggate, Citigroup

Nicky Becker, Bear Stearns

Mark Flannery, Credit Suisse

Doug Terreson, Morgan Stanley

Mark Gilman, Benchmark Company

Jennifer Rowland, JP Morgan

Daniel Barcelo, Banc of America

Paul Cheng, Lehman Brothers

John Herrlin, Merrill Lynch

Paul Tice, Lehman Brothers

Presentation

Operator

Good day, ladies and gentlemen and welcome to the Amerada Hess fourth-quarter earnings conference call. My name is Kelly and I will be your coordinator for today. At this time, all participants are in a listen-only mode. We will be facilitating a question-and-answer session towards the end of this conference. (Operator Instructions) I would now like to turn the presentation over to the host for today's call, Mr. Jay Wilson, Vice President of Investor Relations. Please proceed, sir.

Jay Wilson, Vice President, Investor Relations

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. I'll turn the call over to John Hess.

John Hess, Chairman and Chief Executive Officer

Thanks, Jay and welcome to our fourth-quarter conference call. I would like to make a few brief comments on some key achievements of 2005 and provide some guidance for 2006. John Rielly will then review the fourth-quarter financials, after which we will take questions. In 2005 we had another strong year of operating and financial performance and we continued to make progress in advancing our field developments, building a high-impact exploration program and capturing long-term growth opportunities through several new country entries. Our 2005 corporate net income was $1.2 billion. Exploration and production earned nearly $1.1 billion and our crude oil and natural gas production averaged 335,000 barrels of oil equivalent per day.

Hurricanes Katrina and Rita impacted our production by 7000 barrels of oil equivalent per day in 2005. Although our deepwater production facilities were largely undamaged, we were impacted by outages in downstream, transportation and processing infrastructure. As of the beginning of this year, we have restored 45,000 barrels of oil equivalent per day in the Gulf of Mexico, out of a prestorm total of 51,000 barrels per day. In 2006, we forecast worldwide crude oil and natural gas production to average between 360 and 380,000 barrels of oil equivalent per day, including 20 to 25,000 barrels per day from Libya. Marketing and refining also had another impressive year in 2005 earning $515 million. The HOVENSA and Port Reading refineries both underwent successful turnarounds of FCC units in the first quarter and benefited from another year of strong margins.

Despite a challenging hurricane season and warmer than normal winter temperatures, our retail and energy marketing businesses also performed well. Retail marketing experienced strong growth in 2005 with year-over-year average gasoline volumes per station increasing by 7% and convenience store revenue rising by 4%. In terms of exploration and production, significant progress was made in our major field developments, including three new field startups; Clair, ACG Phase I and the JDA and sanctioning the Phu Horm gas development in Thailand. Importantly, all of our major development projects continue to be on schedule and on budget.

With regard to exploration, we added new acreage in Libya, Egypt, Brazil, and the deepwater Gulf of Mexico. In 2006, our drilling program includes seven high impact wells in the Gulf of Mexico. Three wildcat wells are currently drilling; Pony, Ouachita, and Barossa. Results from all three of these wells are expected in the second quarter. In addition, over the past year, we established operations in two new countries; Russia and Egypt. And most recently reentered our Waha concessions in Libya.

With regard to our Samara-Nafta joint venture in Russia, in the fourth quarter, we acquired additional assets, which has brought our total investment in that country to about $400 million. On the West Med Block in Egypt, we will begin developing existing gas discoveries as well as evaluating exploration opportunities. In terms of the Waha concessions in Libya, we began booking production January 1 and will book reserves in 2006. As to year-end proved reserves, we are pleased to report that in 2005, we replaced about 140% of production at a finding, development and acquisition cost of about $13.60 per barrel. Proved reserves at year end were about 1.1 billion barrels of oil equivalent and our reserve life improved to 8.8 years marking the third consecutive year in which we have lengthened our reserve life.

With regard to our financial position, as a result of the solid operating performance of our assets and the strong pricing environment in 2005, our debt to capitalization ratio improved by 3% to 37.6% at the end of the year. In 2005 our capital and exploratory expenditures amounted to $2.5 billion, of which $2.4 billion related to exploration and production activities. For 2006, our total capital expenditures are forecast to be $4 billion, which includes about $780 million for the acquisition of the West Med Block in Egypt from Apache Corporation and our reentry into Libya. Excluding acquisitions, $3.1 billion is dedicated to exploration and production with nearly half of this amount going to field developments. This higher level of spending reflects the Company's strong portfolio of organic growth projects and attractive investment opportunities.

In summary, we are pleased with the performance of our assets and our organization in 2005 and remain optimistic that the investments we are making for the future will grow our reserves and production profitably and create sustainable 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.

John Rielly, SVP and Chief Financial Officer

Thanks, John. Hello, everyone. Our earnings release was issued this morning and it appears on our website. Please note that through a separate release, we revised supplemental pages 11 and 12 of our release to correct the summary of marketing and refining earnings.

In my remarks today I will compare fourth-quarter 2005 results to the third quarter. Net income for the fourth quarter of 2005 was $452 million compared with $272 million in the third quarter. As indicated in the table on the second page of the press release, fourth-quarter earnings include several items which affect the comparability of earnings between periods. I will address these items in my comments on segment results.

Turning to exploration and production. Income from exploration and production operations was $298 million in the fourth quarter of 2005, including a net gain from asset sales of $30 million and an after-tax charge of $12 million from hurricane-related costs. Income from exploration and production operations was $235 million in the third quarter of 2005, including a $14 million hurricane-related charge. Excluding these items, E&P earnings were $280 million in the fourth quarter of 2005 compared with $249 million in the third quarter.

The after-tax components of the increase are as follows. Lower average crude oil selling prices decreased earnings by $30 million. Higher average natural gas selling prices increased earnings by $48 million. Crude oil and natural gas sales volumes were higher, which increased earnings by $8 million. All other items net to an increase in earnings of $5 million for an overall increase in fourth-quarter adjusted income of $31 million.

The pretax amount of the hurricane-related charge is $18 million and it is recorded in production expenses in the income statement. As indicated in the press release, lost production amounted to 19,000 barrels of oil equivalent per day, which is estimated to have reduced earnings in the fourth quarter by approximately $59 million. Excluding the effect of the gain on asset sales and hurricane charge, the effective income tax rate on exploration and production earnings for the fourth quarter of 2005 was 40%. The effective rate on exploration and production operating earnings for the full year of 2005 was 42%.

The estimated 2006 effective income tax rate is expected to be 50% to 52%. This increase reflects an additional 10% supplementary tax in the United Kingdom and the estimated impact of our Libyan operations. There will also be a onetime charge of approximately 40 to $50 million from the adjustment of deferred income tax liabilities when the new United Kingdom tax is enacted, which is expected to be in the second or third quarter. The additional deferred tax adjustment is not included in the 2006 effective rate I referred to.

The after-tax impact of crude oil hedges reduced fourth-quarter 2005 earnings by $268 million compared with a cost of $294 million in the third quarter. Outstanding hedges on 2006 production amounted to 30,000 barrels per day. The press release provides details on future production that is hedged and the related contract prices. The after-tax deferred hedge loss included in accumulated other comprehensive income at December 31, 2005 amounted to $1.3 billion.

In October 2005, the Corporation announced that it had reached an agreement to acquire a 55% working interest in a concession with natural gas discoveries offshore Egypt for approximately $413 million. The Corporation also announced the sale of certain producing properties located in the Permian Basin in West Texas and New Mexico. The Corporation estimates that it will record an after-tax gain of $160 to $180 billion in the first quarter on the sale of the Permian assets.

Turning to marketing and refining. Marketing and refining earnings were $229 million in the fourth quarter of 2005 compared with $125 million in the third quarter. Fourth-quarter earnings include an after-tax benefit from the partial liquidation of LIFO inventories of $25 million and an after-tax charge of $8 million from the Calpine bankruptcy. The pretax amounts of these items are recorded in cost of products sold and marketing expenses respectively.

Refining earnings consisting of HOVENSA and Port Reading operations, interest income on the PDVSA note and other miscellaneous items were $83 million in the fourth quarter of 2005 compared with $144 million in the third quarter. The Corporation's share of HOVENSA's income after income taxes of $26 million was $41 million in the fourth quarter compared with $93 million in the third quarter. Port Reading earnings amounted to $38 million in the fourth quarter compared with 48 million in the third. After-tax interest income on the PDVSA note amounted to $3 million in both the fourth and third quarters. The balance of the PDVSA note at December 31 was $212 million and principal and interest payments are current.

Excluding the LIFO gain and bankruptcy charge, marketing operations had income of $114 million in the fourth quarter of 2005. Marketing operations had a loss of $22 million in the third quarter of 2005 partially due to lower margins from the high cost of posthurricane product supply. The fourth-quarter improvement was primarily due to higher refined product margins and sales volumes. After-tax trading income amounted to $15 million in the fourth quarter of 2005 compared with $3 million in the third quarter.

Turning to corporate. Net corporate expenses were $41 million in the fourth quarter of 2005, including an after-tax charge of $19 million for premiums on bond repurchases. Net corporate expenses amounted to $54 million in the third quarter of 2005. The third-quarter results include an income tax provision of $31 million relating to the repatriation of foreign earnings to the United States under the American Jobs Creation Act of 2004. Excluding the bond repurchase premiums and tax charge, net corporate expenses were comparable in each period.

Turning to cash flow. Net cash provided by operating activities in the fourth quarter, including a decrease of $363 million from changes in working capital, was $289 million. The principal use of cash was capital expenditures of $724 million, which resulted in a net decrease in cash and short-term investments in the fourth quarter of $435 million. At December 31, 2005 we had $325 million of cash and short-term investments. Our available revolving credit capacity was $1.9 billion at year end. The Corporation's debt to capitalization ratio at December 31, 2005 was 37.6% compared with 40.7% at the end of 2004. Total debt was 3.785 million at December 31, 2005 and 3,835 million at December 31, 2004. The Corporation has debt maturities of $26 million in 2006 and $28 million in 2007.

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

Questions & Answers

Operator

Operator Instructions

Your next question comes from the line of Arjun Murti with Goldman Sachs.

Q - Arjun Murti

A couple of unrelated questions. First, any price-related revision impact on the reserve numbers that you highlighted and then secondly, now that you own Egypt, can you make any comments in terms of timing of when that may start up and any updated estimates on what it may cost to develop that? Thank you.

A - John Hess

Price effects on the PSCs were a net reduction of 34 million barrels that was offset to the extent of about plus 8 million barrels as a result of taking year-end pricing for taxable exploration and production year-end reserves.

Q - Arjun Murti

A 22 negative net impact?

A - John Hess

Exactly.

Q - Arjun Murti

On Egypt, John, any comment?

A - John O’Connor

On Egypt, we have really just in the past ten days begun to get our hands around the base data and have our technology people look into a myriad of opportunities that we see there. So it's a little premature to talk about development plans yet. We are going to be working diligently and quickly and effectively over the next couple of quarters to come up with an acceptable development plan for ourselves, for our partners and for the Egyptian authorities.

Q - Arjun Murti

Egypt had an old estimate of I think around $1 billion to develop it and I know that the gas price in Egypt tends to be somewhat fixed and with higher day rates and service costs you would expect a higher number. But I think you also may be looking at more than just a development plan that Apache had cited. So there may be additional development opportunities or LNG opportunities that can mitigate some cost impact. Is that fair?

A - John O’Connor

You are touching on a number of the variables that we're studying right now. Remember that one of the key appeals to us of the equity in the West Med Block is the exploration potential we saw on seismic in the data room. Now we're just getting the basic data, having our explorationists look over it and firm up wildcat opportunities on the block. So the first order of business basically is to get a better understanding of the total resource base on the block. As you also allude to, contract pricing and modes of selling the gas also need to be evaluated in consultation with partners and with the Egyptian authorities.

Q - Arjun Murti

That's very helpful. Thank you, John.

Operator

Your next question comes from the line of Bruce Lanni with AG Edwards.

Q - Bruce Lanni

Good morning, John. How are you? Just a couple of quick questions. Could you give some further clarity on your 2005 reserve booking as follows? You said 140 reserve replacement. What percent of that is organic versus acquisition? Secondly, can you break it down between international and U.S. and do the same possibly for the finding and development costs?

A - John O’Connor

I'll have a shot at that, Bruce, but let me just presage the commentary by saying that our strategy is to grow through the drill bit supplemented by acquisitions where we believe that creates value. So that's why we talk about replacement costs overall on the order of $13.5 a barrel. Having said that and recognizing that organic bookings tend to be lumpy, book some one year, perhaps more in another year, we are certainly seeing that potential effect. The organic number from the total bookings was about 68%. Of the total that we reported to you, the 176 million barrels, which goes to the 140% replacement rate, the U.S. accounted for about 25 million barrels of that, Europe 124, Africa, Asia and other 26. And that is net of the price-related adjustments for PSCs.

Q - Bruce Lanni

And are you allowed to elaborate a little bit more on what the major bookings were in these areas, which fields you booked?

A - John O’Connor

This is the way we would prefer to report the numbers by those major groupings. That is how we're going to report it later on in the year when we make the formal filing. So I would rather leave it in those groupings.

Q - Bruce Lanni

But going into '06 you did make the comment that Libya has yet to be booked and will be booked this year, correct?

A - John O’Connor

That's correct. Also remember we did not book Shenzi in '05. We had anticipated bookings Shenzi in '06. We have other developments still to be booked.

Q - Bruce Lanni

Excellent. Great quarter, guys.

Operator

Your next question comes from the line of Steve Enger with Petrie Parkman.

Q - Steve Enger

John, you talked a little bit about the strong marketing quarter, the retail quarter. Was there anything unusual? I think you, if I got it down correctly, talked about 15 million in after-tax trading profits in the fourth quarter. Is that right?

A - John Hess

That's correct.

Q - Steve Enger

And that's included in the 114 for marketing?

A - John Rielly

The trading number actually is reported separately. So I think overall, let me just make sure I….

Q - Steve Enger

That is not the energy marketing that you included…..

A - John Rielly

The energy marketing is included in the marketing and again, if we just look over the first nine months of the year, our marketing business was fighting the rising crude price environment. So obviously there was a squeeze on margins there in the first nine months. You see the easing of the crude prices in the fourth quarter. We obviously benefited from that from a margin standpoint and then also from the demand, you can see the volumes in our press release. Our volumes were up significantly as well in the fourth quarter. So with the increase in volumes and the improved margins, that was the driver for the marketing earnings.

Q - Steve Enger

You guys did a lot better in that segment than our correlations would indicate based on the geography and the markers that we use. But there is not anything else unusual impacting that fourth-quarter result?

A - John Rielly

No. Again, you have the LIFO gain out and then we did have the charge for the Calpine bankruptcy.

Q - Steve Enger

And then switching gears, you guys have been talking about Gassi El Agreb in Algeria for a number of years and I've kind of lost track with where you are at there and can you talk a little bit about the recent history and where production rate is, what you're going to be doing? That is one of the projects you have highlighted spending money on in 2006 and where that production might go?

A - John O’Connor

You're right. It is an ongoing story, Gassi El Agreb, but an ongoing success story. We did talk last year about going to Phase II of the development. So the initial thrust was basically infill drilling, some exploitation drilling and some recovery of existing production facilities in the three fields concerned. We took over the fields from production. Gross production was on the order of 20 to 25,000 barrels a day. The fields are currently producing on the order 58,000 barrels a day and we are into phase II of the expansion project. In total, with our partners, we're looking at investments on the order of $900 million now, very attractive. We have got a favorable PSC by comparison with others and the project is on track and on budget. This involves installing compressors, power generation, new oil and gas transfer lines and flow lines and continued drilling in the field. I would also say that we have found some sweet spots in the fields that have not been anticipated initially and that is contributing to the success of the project.

Q - Steve Enger

What do you think peak rate may be there, John?

A - John O’Connor

It's a good question. I guess the real interest to us obviously is the operation of the PSC. So the gross rate….

Q - Steve Enger

That's even better….

A - John O’Connor

I would need your projection on crude prices to come up with the PSC impact. So we tend to look at gross as a measure of how well we're doing with respect to redoing the fields and revamping. But I would say at this stage, the current 58 or so thousand barrels a day going to 70,000 barrels a day in a couple of years.

Q - Steve Enger

And last quick one for me back on reserve replacement details. Europe 124 and then BOE. Can you say how much is included there from purchases?

A - John O’Connor

Yes. Let me go to the net ads, Steve, because it's easier to do the math that way. So we started the year at 1,000,000,046 and we're ending the year at 1,000,000,093, which production nets out 125 and sales of property is three. Price revisions resulted in a net decrease of 26. We added 52 million barrels for discoveries and extensions, 58 million barrels for technical revisions and 90 million barrels from acquisitions.

Q - Steve Enger

Great. And essentially that 90 million is probably all in the Europe geographic segment.

A - John O’Connor

Yes it is.

Operator

Your next question comes from the line of Paul Sankey with Deutsche Bank.

Q - Paul Sankey

Just more on the marketing if you don't mind. I noticed that your sales of distillates and residuals were up very strongly. What was the driver of that?

A - John Hess

Well actually our sales are up across the board. Our retail business actually grew in our number of outlets from about 1254 to 1354. So the retail business is part of it. We also had some spot sales in the quarter. That is part of it across the board. And our refineries actually in the fourth quarter ran at a higher rate in HOVENSA. So we had some more product because of that.

Q - Paul Sankey

Great. And what I'm trying to get towards here is some kind of a normalized number given the volatility in that segment. What….?

A - John Hess

Well as you can well appreciate the fourth quarter because of the aftermath of the hurricane was hardly normal. So if you normalize it, I think the best thing to do is let's start with a fresh book in the first quarter. You know the first quarter though refining margins have come down some and also we are experiencing a very warm January. So it is hard to normalize when you are depending upon the weather factor.

Q - Paul Sankey

That's what I'm thinking because obviously with the loss in Q3 it doesn't make it any easier for us to try and get to an ongoing number. Suffice it to say how is the quarter so far turning out in relation to what we saw last year?

A - John Hess

As you are well aware, we can't lean forward like that. I am just trying to comment on where we are today. Our operations are running well but because it is warmer than last year now and warmer than normal, obviously that is going to impact some of our results both in the refining area and marketing area.

Q - Paul Sankey

Okay. Thanks for that. If I could go back to first of all exploration. John, could you give us the latest on drilling progress and any other big news flow that you've got coming for '06?

A - John O’Connor

Okay, Paul. Let me start with Barossa. That is currently drilling at 6.5 thousand feet. Ouachita has just recently set 16 inch liner at 12.5 thousand feet and Pony has reached current section depth of 23,900 feet. And I think the answer to the second question is in the first.

Q - Paul Sankey

Great. Thanks a lot. And finally for me on the F&D costs, what would be, is there any more that you can give us in the terms of the way you've broken down the additions in terms of F&D costs and perhaps any outlook that you've got for that would be great?

A - John Hess

No, I don't think it's really helpful, Paul, to go any further than the numbers we have given. You have the organic numbers. You have the acquisition numbers. You have the acquisition volume. So I think that is pretty transparent. Going forward, I mean obviously we would expect and hope to do better this year but a number of factors are obviously out of our control both in terms of how the numbers fall together through the year and what the costs do from the service sector in terms of the activities we have got this year. But I would say this. We would expect to be able to modestly reduced FD&A numbers in 2006. That's just a guess at this stage and an ambition I suppose.

Q - Paul Sankey

Thanks for your help.

Operator

Your next question comes from the line of Doug Leggate with Citigroup.

Q - Doug Leggate

A couple of questions. I guess first on the cost increases. We saw some reasonable movement in the upstream costs in the fourth quarter. Can you just walk us through what those were and maybe how you would expect those costs to pan out over the next year?

A - John Rielly

Sure. In the fourth quarter, first thing I just want to make sure that you do exclude the special items. So you have the hurricane charge and the pretax amount of that of $18 million is coming in the production cost. So if you exclude those costs, production costs did increase approximately $30 million from the third quarter and the production costs don't always just work variable with production because you have got maintenance and work over costs and so just due to the timing of some of that maintenance and work over cost that fell in the fourth quarter. Production mix does have something to do with it. We had higher transportation costs in the fourth quarter and there definitely is an impact to some of our start-up activities. We are getting back into Libya now. We are getting into Egypt, as John O'Connor mentioned. So we are starting work on those assets there as well as well as Russia. So when you put all those together, that really contributed to the increase. For the full year if I could just point out from a unit cost type standpoint and I'm excluding exploration from this because obviously that is a decision on how we want to expend our exploration dollars in our portfolio. Our cash costs amounted to $9 for the year. That is our overall production cost in G&A associated with our production. Our DD&A was $7.89. So we came to about $16.90 for 2005. Our guidance for 2006 and again taking into some of the factors the John O'Connor spoke about, our cash costs on our guidance are going to be between 9 and $10 is what we see as our cash costs for production. As far as DD&A, we see between 8 and $9. So for an overall unit cost between 17 and $19 for 2006.

Q - Doug Leggate

That's very clear. Let me move onto the production guidance that you've given us. John O'Connor, you mentioned that obviously it depends on what your oil price assumption is. So what kind of assumptions are you using for the production range you've given us? I imagine there is some sensitivity to that from PSCs.

A - John Rielly

Actually for us you do see the sensitivities on the barrels because some of our PSC contracts are long-life production arrangements and so you do get a little bit more effect on the reserves. In 2005, it is under 5000 barrels a day related to the PSC and so from a pure price standpoint, there is not a real effect in our forecast there.

Q - Doug Leggate

Could you walk us through the main drivers? The one I'm specifically interested in is the JDA stocks up on time. I think there was some issue of delaying that contract to the end of last year?

A - John O’Connor

Let me try to address that. The contract really in formal terms starts the first of January 2006 and then there was a side agreement for early gas, which the buyers and sellers contracted to in the fourth quarter of 2005 with a take-or-pay volume. The volumes were not taken so take-or-pay is incurred. The buyers acknowledge that. The sellers, i.e. ourselves and Petronas Carigali, have had discussions with the buyers as plain vanilla straightforward. The way the mechanism works is they will pay us and then they have entitlement over the 20 year life of the contract to take those additional volumes once they are taking minimum daily contract quantities as contracted. So that is all plain vanilla straightforward and that is the undertake from 2005. As to the contract for 2006, the contract volumes basically lie in the range of 350 million cubic feet a day for minimum contract quantity to just over 400 million cubic feet a day for max and we speak in terms of 390 as average daily contract quantity. The average that the buyers have taken thus far through today's date is 320 million cubic feet a day. There have been days when they have taken 400. We have the well and processing capacity offshore to meet all their requirements. The plant is running well. As with all new plants, it has occasional tweaks, which result in reduction of throughputs from day-to-day. But all indications are that the buyers are taking at the contract quantities and we're very pleased with how they have put in place their processing and take arrangements.

Q - Doug Leggate

Thanks, John. Just one final one. What is the contribution you expect from Russia this year with the additional acquisitions?

A - John O’Connor

We're talking about 15,000 barrels a day average through the year. It does vary seasonally from the far frozen winter to the warmer summers. So it is quite seasonal in terms of moving the production out to market. But average included in the number of the range that we gave you, 360 to 380 is about 15,000 barrels a day. I think that contrasts with about 7000 barrels a day on average for the period of 2005.

Operator

Your next question comes from the line of Nicky Becker with Bear Stearns.

Q - Nicky Becker

Thanks for the additional detail on the marketing. Just to really irritate you, I wonder if we could get some numbers on what the marketing margins look like just for modeling purposes.

A - John Rielly

No, we don't go to that level of detail.

Q - Nicky Becker

Just switching to the upstream, your tax rate on the upstream was a little lower than we had modeled in. What does that reflect? Is that the repatriation?

A - John Rielly

No, it is not, Nicky. When we try to give guidance on our effective tax rate, we try to give it on a yearly basis. So at the beginning of the year, we said we would have a tax rate of between 43 to 45% and we came in for the year at 42. What happens is from quarter-to-quarter, it really does, the production mix does impact us as various countries with very different rates and so the mix will just come in differently quarter-to-quarter but average out through the year. So in the fourth quarter, when we exclude these special items, we came in at 40%, just slightly below our guidance and then we came in at 42 for the year. But there is really nothing unusual in the quarter except production mix.

Q - Nicky Becker

And so how do we look at 2006?

A - John Rielly

Now in 2006, as I mentioned earlier, we will have a significant step up in our effective tax rate. We are giving guidance of 50 to 52% and again that reflects the Libyan operations now starting up on January 1 with a much higher tax rate and also we are expecting the U.K. to implement the supplementary tax announcement that they made somewhere in the second or third quarter but still being retroactive to January 1. When you combine those two tax increases if you want to stay in our portfolio will come to about a 50 to 52% effective rate.

Q - Nicky Becker

Okay. So obviously that ramps up towards the end of the year?

A - John Rielly

No, it will start up, Libya is starting up, as John Hess mentioned earlier, right on January 1. We're booking production right from that. So it is going to start up right away on the Libyan. You are right on the U.K. The U.K. could start up in the second quarter or the third. So depending on when that comes in, that is when we'll get the full effect of that rate increase.

Q - Nicky Becker

Thanks. That's very helpful.

Operator

Your next question comes from the line of Mark Flannery with Credit Suisse.

Q - Mark Flannery

I have two questions. One, John, is on rig availability. I think John Hess mentioned that there are seven essential high impact wells to be drilled in 2006. Three of them are obviously drilling so they have rigs. What is on rigs for the other four? Are you having a problem or is that all contracted out?

A - John O’Connor

Without being complacent, Mark, I think we are in relatively good shape for 2006 and indeed as we project forward for 2007. You may recall that we contracted the Ocean Baroness, a 15K 2 million pound hook load capable rig, which is currently drilling the Pony well. We also have the Voyager. We also have the Max Smith. So certainly for all of the Gulf of Mexico work we are covered. I think the area where we are uncovered is the opportunities we have in the Mediterranean. As I mentioned earlier, the prospects that we see and are firming up and generating in West Med together with some expectation around the turn of the year late '06, early '07, we would like to be in a position and have the equipment to drill the first wildcat block 54 offshore Libya. The seismic acquisition there is essentially complete and once we've processed and interpreted, our thoughts will turn to working with our partners in Libya to a particular location and securing the equipment and going ahead to build the wildcat. So at this stage, the wells that John talked about, the high impact wells in the Gulf of Mexico are covered between ourselves and our partners. That's not to say that there won't be some movement around with respect to timing as current programs impact both ourselves and our partners. But in terms of having contracted the equipment, I think we are in acceptable shape and a little coverage for the Mediterranean is what we're now looking for.

Q - Mark Flannery

And just a quick one on gas prices. I realize gas prices were pretty strong for you this quarter. Is that simply a bid weekend effect or 1175 in Mcf I think for the U.S. gas, which is above the benchmark level. Normally you come in just below. Is that just because of the crazy movements during the quarter?

A - John Rielly

Well for the U.S., actually in our differentials, as we look at it, came in right around where we would expect it. So we usually do come in slightly below it and I am not sure exactly what benchmark you're looking at. We are seeing that we came in slightly below our benchmark and so there really wasn't that much of a change. Now the only thing that impacted us a little in the fourth quarter is the hurricanes. So we had some of our gas that is just offshore being shut in, as John Hess had mentioned, which can affect our differential a little bit. But we didn't see any big swings from that.

A - John Hess

As you know, two big drivers of gas price in our revenue stream are the U.S. and the U.K., which were very strong at the end of the year. So that had a big impact on what we realized.

Operator

Your next question comes from the line of Doug Terreson with Morgan Stanley.

Q - Doug Terreson

Congratulations on another great quarter. John, you may have touched on this and it may be too early to know the answer anyway but from the starting point in Libya this year of about 45,000 barrels per day, which I think was the number you used, I wanted to see if you could relay your initial projections for output growth for instance during 2006, 2008 if you have an idea at this point?

A - John O’Connor

Doug, hi. Actually I think that perhaps you misheard what John talked about with respect to Libya. In point of fact, at this stage, we are estimating because we don't have actual real life data. A range of 20 to 25,000 barrels a day being our share. This comes off a nominal advice to us from our partners, the National Oil Company, that the total production from the Oasis concessions are around 350,000 barrels a day. Our entitlement is a little over 8% hence the number that we're working with right now. We expect as processes fall into place, we have production accounting information, we will come up with a firmer number but for now I think that is a good number. It's in the range of 20 to 25. That is what we're carrying in the range of production volumes we provided for this year. If there is any material adjustment to that we will advises. I don't expect that there will be. As to the growth projections, I think that we and our Oasis partners and the NOC will probably spend much of this year trying to get reality and firm business plans with respect to the growth opportunities. Clearly the growth opportunities are there and we have spoken to this on previous calls both in the existing production asset base and in exploration and in development of undeveloped but discovered resources on the concession areas. So we are looking to future growth projections but we have not projected them yet internally until we deal with hard facts on the ground.

Q - Doug Terreson

Thanks for clearing that up. Congratulations again.

Operator

Your next question comes from the line of Mark Gilman with Benchmark Company.

Q - Mark Gilman

Guys, good morning. A couple of questions if I could please. Just sticking with Libya for a moment, John O'Connor, I wonder if you could talk about what an unrelieved decline rate looks like with respect to the Waha field and also what level of capital spending you might envision for Libya this year and whether it is in the budget as specified?

A - John O’Connor

You're actually asking a tricky question with respect to unrelieved decline rate because that assumes that we have our arms around the work over activity, infill drilling activity, etc., etc. What I would say is that we use, as you know, GNMs to do our reserve calculations to come up with current numbers. What we have gone to is our historical records from those fields, taken those decline curves and projected them forward. So at this stage, until we get our arms around ongoing costs, now we know from our conversations with our partners, the NOC operating the fields very effectively in our absence since '86, that this is low-cost production. Also that the philosophy of Libyan resource management is modest depreciation or decline of production with respect to the underlying reserve base. So although I have not seen and I don't have data on the actual field declines related to capital, we will get that and hopefully by first quarter, second quarter conference call again to give you some insight into that market.

Q - Mark Gilman

The spending level?

A - John O’Connor

Given the fact that our share of the spend now becomes 8%, it's really, really quite modest. I think we have got an immaterial 20 to $25 million as the plug number in the budget for this year.

Q - Mark Gilman

I wonder if I could go back to the reserve replacement for just a minute. What is in the technical revisions category? Where is that sourced to and I assume Phu Horm is booked as a discovery and extension?

A - John O’Connor

You assume correct. Ask me the question again, Mark.

Q - Mark Gilman

What is the source of the technical revisions? What areas, what fields, John?

A - John O’Connor

North Sea and the U.S. and also West Africa.

Q - Mark Gilman

The production number that John Hess quoted for '06 is frankly a little bit lower than what we're looking for. Are you assuming Llano goes into decline this year?

A - John O’Connor

We have given Llano a little bit of a moderate reduction in volumes by comparison with last year because our models indicate that we should see modest ingress of water in the existing wells.

Q - Mark Gilman

With respect to the shut-in production numbers, can you split out between oil and gas the 19,000 in the fourth quarter and if I interpreted your comments correctly, the 6000 shut-in as of the first of this year?

A - John O’Connor

The shut-in with respect to the beginning of the year is actually about 5000. I think we talked about 45 restored versus 51 prior. I think if you expect normal field declines in the offshore, the true comparison post the shut-in time would be 45 versus 50. So you're looking at a range of 5, of which 2.5 is predominantly net gas in the Main Pass/Breton Sound area and 2.5 is predominantly oil in the deepwater offshore.

Q - Mark Gilman

And relative to the 19 in the fourth quarter, John.

A - John O’Connor

Nineteen in the fourth quarter? That would've been predominantly oil because it would have been contributed predominantly by our 20 TBD oil equivalent that's predominantly oil from Llano, which only came back on the 27th of November.

Q - Mark Gilman

Just one more if I could. The U.S. DD&A rate in the fourth quarter looked very low to us. Was there an adjustment of any kind built into that?

A - John O’Connor

John Rielly is going to talk about the market.

A - John Rielly

No, there's no adjustment. Again you have to look at the mix and as John mentioned, Llano was offline in the fourth quarter and so Llano is deepwater asset, has some purchase cost also associated with it. So that is the only change. Again it is just pure production there.

Operator

Your next question comes from the line of Jennifer Rowland with JP Morgan.

Q - Jennifer Rowland

Another question on the production guidance. When you've given your capital spending guidance a couple of weeks ago, there was a significant increase in the capital associated with production for the upstream. I'm just wondering if you could quantify of your guidance range for '06 production, how much of that relates to either accelerated drilling or just opportunities that you see at the existing fields that would explain the higher increase on the production CapEx? If you could just bring it back to the guidance that would be helpful?

A - John O’Connor

Very difficult to bring production volumes to capital spend because of the time lags that occur between the spend and the production obviously. I mean some of the key moving factors in production in '06 versus '05 will be the addition of the 20 to 25,000 barrels a day from Libya from the beginning of the year, about 120 million cubic feet a day net to us or say 20,000 barrels per stream day from the first of April for the streaming of the Atlantic Cromarty net gas production in the U.K. sector of the North Sea together with a full year of production of contract volumes from the JDA. So those are the three big pluses. There are obviously some modest pluses elsewhere from the fields that started up in the first quarter of '05, namely Clair, ACG Phase I, those being the two main contributors. If we now turn for a second to the production increases and where is it coming from. It is up above 460 million year on year. Of that, some of it is definitial change. For example, last year, Gassi El Agreb was in the development stage and so the expenditure there was in development. We have now moved it into production and that adds about $100 million or so to that particular area. We continue to develop Valhall but now the stage of development of Valhall is such that we now include that under the development or the production grouping. So that is part of it. So the work is the same. It is categorized in different buckets so to speak. Russia of course is a new ad really as we get our arms around the expanded asset set there. We're up in deepwater. We are up in Saba, in Bara, South Arne, Schiehallion and number of other opportunities. I would say with respect to production as a whole what this investment does in the mature fields is it reduces the rate of decline which otherwise might occur. So it does help with the foundation.

Q - Jennifer Rowland

Okay. That's very helpful. Just a question on Port Reading. This is the second quarter in a row where you've posted some pretty strong results from Port Reading versus history. So I'm wondering if there have been any changes there, if you're seeing efficiency gains from some work that you may have done there or is that just solely margins.

A - John Hess

It's really three pieces. Yes, with the turnaround we did at the beginning of the year, we did get some improvement in conversion and ability to have a little more flexibility in peak stocks and also run at a higher rate. So that was number one. Number two, during the year, we did run at higher levels because of that and number three, we had a strong margin environment. So all of that together made a bigger contribution in 2005.

Operator

Your next question comes from the line of Daniel Barcelo with Banc of America.

Q - Daniel Barcelo

I think you touched on the U.K. a bit before but I didn't know if you could expand a little bit about your exposure there to nat gas and specifically what percentage of the sales would really be under contract versus spot and the contract, the timing of it, is it more of a monthly contract in timing? And then also in the North Sea, any update on the timing for Atlantic Cromarty, which I understand to be starting in late first quarter?

A - John Rielly

On the marketing of natural gas, over 60% or so of our sales right now before Atlantic Cromarty are exposed to the spot market. The balance being the longer term.

Q - Daniel Barcelo

The timing for Atlantic Cromarty.

A - John Hess

Atlantic Cromarty, John will handle.

A - John O’Connor

Atlantic Cromarty is currently in the commissioning stage. We're past mechanical completion. We expect first gas towards the end of March.

Q - Daniel Barcelo

And one other quick question on the cash flow statement. It seems that working capital movements were perhaps bigger than what I would have expected. I didn't know if you can give any color on that.

A - John Rielly

It's just again timing of working capital. If you looked last year we got a positive increase from working capital for the year. This year it is a decrease. There is nothing unusual and you should expect some of that to reverse in the first six months or so of next year. But that is just normal changes. As prices go up we get a little bit more of an impact on working capital, decreasing cash flow. But again it is just pure timing.

Operator

Your next question comes from the line of Paul Cheng with Lehman Brothers.

Q - Paul Cheng

Congratulations on a good quarter. I know that it's probably a bit premature but, John, whether you can give us a rough idea of what is the unit operating cost for that. I know that there is no cost but any number that you can share?

A - John Rielly

In Libya, I mean I can't give you any specifics right now, as John O'Connor was saying, they are really still getting their arms around what they are going to do and how they're going to develop the current production and obviously the discoveries. So it is a relatively lower cost producing area and so it is included, as I told you, the cash costs for next year of that 9 to $10. We do have Libya factored into that.

Q - Paul Cheng

Right. But you must have a number that you assume.

A - John Rielly

Yes, we do have a number. But again we're early days on Libya. Like we said, we have only $20 billion of CapEx associated in there. So again from a standpoint, it is lower than the 9 to $10 range but until we get specifics and really get our hands around the development, I'd really rather not say anything at this point.

Q - Paul Cheng

And John, when you are talking about a onetime hit in the U.K. tax increase that defers a 40, 50 million by the second quarter, is that a hit just on the cash flow or is the hit actually on the income statement also?

A - John Rielly

It is a non-cash charge that will be on the income statement and all we are doing is setting our deferred tax liabilities that were now set at 40%. With the additional 10% we have to put it to the deferred tax liability at a 50% tax rate. So again, it is just a non-cash charge that will come in on our income statement but it was not included in that effective rate I quoted earlier.

Q - Paul Cheng

When exactly is that income tax increase actually being activated or exercised by the U.K. government? That's why you don't know whether it is the second or third quarter.

A - John Rielly

Exactly. It actually requires royal ascent. So whenever that does happen is when we will record it.

Q - Paul Cheng

John, wondering if you can give us maybe some color in terms of what is the heating oil contribution in the fourth quarter in the wholesale operation and wholesale operation, I assume you're recording in your marketing results?

A - John Rielly

I'm sorry. I didn't understand, could you repeat that question?

Q - Paul Cheng

In the fourth quarter, you have residential heating oil and I think the margin there is very good. I am wondering if you can give us an idea out of the 114 million, how much is related to the home heating oil business and also the wholesale margin I believe in the fourth quarter has jumped quite substantially. I want to see if the wholesale profit you are seeing under the refining or under the marketing and how much is that roughly?

A - John Hess

Paul, as you're probably not aware, we don't sell residential heating oil but we do sell it wholesale to distributors who in turn sell it to the homeowner.

Q - Paul Cheng

That's what I'm referring to.

A - John Hess

Incrementally we did have some increased sales of heating oil during the quarter and as a consequence, part of our increase in our sales was because of that.

Q - Paul Cheng

John, any kind of number that is a 10, 20, 30 million benefit because heating oil margin is pretty strong for your business I think during the winter?

A - John Rielly

Well quite frankly right now with the weather being anemic, it actually works the other way. But part of the results definitely were impacted by increased sales and increased margins in the aftermath of the hurricane and some of the profits we got in the marketing division were because of it.

Q - Paul Cheng

And John, how about wholesale? You said wholesale is being recorded in the marketing or just…..

A - John Rielly

That is in the marketing.

Q - Paul Cheng

That is in the marketing.

Q - Paul Cheng

John, wondering for the 360 to 380,000 barrel per day for 2006 forecast, can you, pardon me. I came in a little bit late and maybe you already did, can you give us a rough breakdown between oil and gas and also by region?

A - John Rielly

Paul, if you don't mind, if we could do that with Jay Wilson after the call. We will get into that detail.

Q - Paul Cheng

I will do that. And final one, Pony, is it still going to be finished by March?

A - John O’Connor

Based on the spud date, Paul, and the estimated time to TD, it should be. You are drilling in one of the deepest targets ever drilled in the Gulf of Mexico. So far be it from me to forecast when it will be completed but the plan is to have it down to TD by the end of March.

Operator

Your next question comes from the line of John Herrlin with Merrill Lynch.

Q - John Herrlin

Just one quick one. There's a fair number of leases that are going to be relinquished in the Gulf of Mexico this year. Are you going to get more aggressive with you deepwater program here and that's it for me?

A - John O’Connor

John, you know we have an ongoing multi-year program to both build and maintain an appropriate inventory of opportunities in the Gulf of Mexico and in other prospective basins around the world. We have a high-class, high-quality team working the Gulf of Mexico. We are always aware of which leases are coming up for relinquishment and where we believe there may be prospectivity and we look at all leases available frankly in the Gulf of Mexico and high grade the ones we think we want to go after at the lease sales.

Operator

Our last question comes from the line of Paul Tice with Lehman Brothers.

Q - Paul Tice

Good morning. Just a handful of questions. I've got your full year production guidance. Any guidance range that you'd like to provide for the first quarter of '06?

A - John Rielly

No, not at this point. And again, as John O'Connor mentioned, we do have the Atlantic Cromarty that's going to start somewhere in we're saying right now at the beginning of the second quarter. You don't know. Some of these could come in earlier. So we would rather not say anything about the first-quarter guidance on this. Again we're still getting our arms around Libya at this point. I'd rather not just yet.

A - John O’Connor

It's early days.

Q - Paul Tice

And just second operating question, in the first quarter of '06, can you just walk us quickly through the project milestones? I know there's a sail away target for Okume, anything else to be looking for?

A - John O’Connor

Well Okume of course is the major project that is occupying the front of our mind right now in this quarter. We have a heavylift vessel en route to Equatorial Guinea, which will help with the installation. We have the central facilities, jacket, we have the satellite jackets loaded out on barges and they are getting ready to set sail. TLPs have been formally launched in Pusan in Korea and they are in the water. They will be making their way through. So what I would say is we have a lot of tip on the water right now and it is going to be making its way. Sail times from the Gulf of Mexico 30 to 35 days to West Africa, roughly the same, a little bit longer from South Korea. So March, April are going to be very busy months with a lot of activity going on in the waters offshore Equatorial Guinea and that's where we are primarily concentrating that. That is not to say we don't have construction ongoing elsewhere. We do. We have construction on the ground in Northeast Thailand in Chumphon. We have construction on the ground and offshore at Pangkah, all in the construction stage right now.

Q - Paul Tice

And then just two quick ones for John Rielly. John, in the last quarter, it looks like you repurchased about 497 million of bonds. But if I look at your debt balance it was unchanged. Was that all because of the working capital requirement?

A - John Rielly

No it wasn't. As we said earlier in the year, we were repatriating foreign earnings in accordance with the American Jobs Creation Act and what was happening was we had $1.9 billion to be allowed to be repatriated under the law and we had talked about this that we were going to fund that from cash flow as much as possible but then to also get up to the 1.9 billion we may need some foreign debt. That is what happened. So we took out some foreign debt to help with the repatriation and then we paid down just the same amount of U.S. debt. So that is the reason why the debt level stayed the same, which was along with our guidance that we gave earlier in the year.

Q - Paul Tice

The foreign debt is bank debt?

A - John Rielly

Yes, it is on the revolver.

Q - Paul Tice

It is on the revolver?

A - John Rielly

Yes.

Q - Paul Tice

Okay. And then around your 2006 CapEx plan, how is that going to breakdown quarterly? Is that going to be fairly evenly split through the four quarters or is it going to be lumpy?

A - John Rielly

Well it'll be lumpy to start out. As John Hess had mentioned, we have to the West Med deal, which actually closed, the purchase closed already. So we have $400 million associated with that. Libya actually has already happened. So you have a portion of that purchase price being paid approximately 260 million in January. So that has already happened. So just based on those acquisitions, it is going to be lumpy and a little bit front loaded.

Q - Paul Tice

Away from the acquisitions on the organic side, is that going to be fairly evenly split or will it be front-end loaded?

A - John Rielly

I would say for the most part you could say the exploration, as John O'Connor mentioned, there are three wells drilling right now. So we will be a little bit more front loaded on that because there is the deep Gulf wells being drilled there. And then outside of that, it would be difficult for me to tell you for the most part.

Q - Paul Tice

And then based on your internal price stack, do you expect to cover basically all of your CapEx with internal cash flow?

A - John Rielly

Yes, as we look out right now, we expect to cover our CapEx program with cash flow and I should point out don't try to look at that CapEx number as absolutely fixed. I mean it is clearly something that we look at. There is flexibility on that. If business conditions change, we could make changes appropriately. But we will take a look at it at that point. But again we do expect to fund the CapEx program from cash flow.

Q - Paul Tice

What oil and gas prices are you assuming?

A - John Rielly

There is no set, as I said, try not to look at this as an absolute fixed number as we run various cases on price stacks. If there was some changes in prices, we would look at it and maybe we'd continue on, maybe we wouldn't based on the opportunities that we have. We have a very strong balance sheet position actually right now. You could almost pick any price that you want and even if it was a fixed, our debt cap ratio would reduce. But again, we feel very comfortable with the program and our cash flow to fund it.

Operator

Ladies and gentlemen, this concludes your question-and-answer session as well as your presentation for today. Thank you very much for participating and have a wonderful day.

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Source: Amerada Hess Q4 2005 Earnings Conference Call Transcript (AHC)
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