赫斯 (HES) 2003 Q4 法說會逐字稿

Good day everyone. Welcome to the Amerada Hess quarterly earnings release conference call. This call is being recorded. Today's presentation will be available for rebroadcast at 3:00 p.m. Eastern time today, running through February 4th at midnight. You may access the replay by dialing 719-457-0820. Again that's 719-457-0820 or 1-888-203-1112 and enter confirmation code 598650. Again that's 598650 on your telephone.

All media will be in listen-only mode for the duration of this call. Media questions should be directed to Jay Wilson at 212-536-8940. The Webcast of this call will be available on hess.com for 30 days. The transcription of this conference call will be available on the company's Web site for one year.

At this time for opening opening remarks and introductions I would like to turn the call over to the Vice President of Investor Relations, Mr. Jay Wilson. Please go ahead, sir.

Good afternoon everyone and thank you for participating in our earnings conference call for the fourth quarter of 2003. With me is John Hess, Chairman of the Board and Chief Executive Officer, John O'Connor, President Worldwide Exploration and Production, John Schreyer, Executive Vice President and Chief Financial Officer and John Rielly, Vice President and Controller.

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

Thank you, Jay. Welcome to our fourth quarter conference call. I would like to make a few brief comments on some of our key accomplishments during 2003 and provide some guidance for 2004. John Schreyer will review the fourth quarter financials after which we will be pleased to take your questions.

In 2003 we made a great deal of progress in advancing our strong portfolio of development projects, reshaping our existing asset portfolio, restructuring our exploration production organization, creating value through focused high impact exploration and strengthening our balance sheet and financial flexibility.

Over the past several years we have significantly shifted our exploration production capital expenditures to field developments. In 2003 we invested $707 million or 56% of our upstream capital spending in developments. And in 2004, we plan to invest approximately $900 million or about 63% of our upstream capital expenditure in developments. This compares to average annual development spending during 2000 to 2002 of $423 million or a 37% of upstream capital expenditure not including acquisitions.

We are currently funding 12 development projects, which in aggregate are expected to add new production to the company in excess of 100,000 barrels of oil equivalent per day by the year 2006. In addition, the lower costs of this new production combined with other cost cutting moves should reduce unit costs by approximately $2.00 to $3.00 per barrel of oil equivalent by 2006. All 12 of our key development projects are moving forward and should be on production by 2006. I would like to briefly highlight a few of these projects.

Development of the Llano Field is progressing as planned and we expect the Field to commence production during the second quarter of this year. Net production from Llano should average approximately 8,000 barrels of oil equivalent per day in 2004 and 15,000 barrels of oil equivalent per day in 2005.

We recently made a trip to southeast Asia and visited our operations in that part of the world. Installation of the joint development area pipeline is scheduled to begin this quarter. The pipeline will be tied into our platform in April and be fully installed by the end of the year. Construction of the gas separation plant has commenced and should be completed by the third quarter of 2005. It is important to note that we will sell our gas at the platform, and that the buyers, PETRONAS and PTT, are responsible for funding the pipeline and guess separation plant. We still expect first production to occur during the second half of 2005 at a net rate of 160 million cubic feet per day. Demand for natural gas in the region continues to increase driven by very strong economic growth, and we intend to negotiate with the buyers to sign additional gas sales agreements.

Appraisal drilling in the northern block G area in Equatorial Guinea has completed and we are preparing to move forward with the development. Currently we are in the process of incorporating the well data into our subsurface models and optimizing our development concept. We are targeting submission of a plan of development to the government of Equatorial Guinea in the second quarter of this year.

In terms of reshaping our portfolio, in 2003, we sold $545 million of assets of which $478 million were mature or high cost exploration and production properties. We also completed two significant asset swaps in 2003. In the first we swapped mature high cost assets in Colombia for a 25% interest in significant long-lived natural gas reserves in the Malaysia Thailand JDA, bringing our interest in the area to 50%. In the second transaction we transferred a 14% interest and ownership -- [operatorship] of the Scott and Telford Fields in the North Sea in exchange for a 22.5% interest in the Llano Field in the deep water Gulf of Mexico bringing our interest in the field to 50%.

Last year we took steps to restructure or exploration production business. As part of this reorganization, we have reduced head count by about 30% or roughly 700 positions. As a result, we expect to achieve annual after tax cost savings of $30 million. 60% of these savings are expected to be realized in 2004, and the full amount realized in 2005.

With regard to exploration, our strategy is to drill fewer, but higher impact wells than in the past. In 2004, we expect to drill around 15 high impact exploration wells, including some appraisal wells. In 2004, over one-half of our exploration activity will be in the deep water Gulf of Mexico. During the fourth quarter, we announced the positive results of two significant deep water Gulf of Mexico wells. The successful appraisal of our Shenzi discovery in which we have a 28% interest and which encountered nearly 500 feet of net oil pay and Tubular Bells in which we have a 20% interest. Both Shenzi and Tubular Bells will be further appraised in 2004 and we are confident that both of these discoveries will be first developed with first production likely in 2008.

Our refining and marketing business posted its best annual results in a decade. Earnings at Hovensa, our refining joint venture in the U.S. Virgin Islands, and our retail and energy marketing businesses were strong. We believe that our downstream return on capital employed and net income per barrel of refined products sold will rank in the top correspondence tile versus competitors for 2003. The first quarter has started off well, and we anticipate another strong year for our refining and marketing business in 2004.

The company's financial position was significantly strengthened in 2003. Proceeds from asset sales totalled $545 million. We generated free cash flow after capital spending and dividends of $175 million. And during the fourth quarter, we issued $675 million of mandatory convertible preferred stock. These moves allowed us to reduce debt by over $1 billion in 2003, and resulted in our year-end debt to capitalization ratio declining to 42.5% from 54% at the end of 2002. We also had $518 million of cash at the end of the year. With the currently undrawn credit facility of $1.5 billion in negligible debt maturities over the next several years we believe that we will have ample liquidity for the foreseeable future.

In 2004 our focus will be on creating value for shareholders by advancing our current development projects, appraising our recent discoveries and growing our approved reserve base. Portfolio reshaping will continue, but more as a normal course of business, no significant transactions are currently being contemplated. Assuming west Texas intermediate oil prices average about $24 per barrel we believe that our capital expenditure and cash flow will be roughly balanced in 2004.

Total capital spending for the company is forecast at $1.52 billion in 2004 versus $1.36 billion in 2003. With about 95% of expenditures dedicated to exploration and production in both years. With regard to our production forecast, we exited the year at 355,000 barrels of oil equivalent per day which exceeded our previous guidance of 330 to 340,000 barrel of oil equivalent per day. While we are running a bit ahead of schedule thus far in January, we maintain our full year 2004 forecast of 325,000 barrels of oil equivalent per day. Year-end 2003 [INAUDIBLE] reserves were 1.035 billion barrels of oil equivalent. Beyond 2004, we believe that both our reserves and production are on a positive trajectory.

We are taking the necessary steps to shift our expenditures toward the developments, reshape our asset portfolio and strengthen our balance sheet. We believe that we are now well positioned to achieve sustained profitable future growth. I will now turn the call over to John Schreyer.

Hello everyone. Our earnings release was issued this morning, and it appears on our Web site. I will cover our usual comparison of fourth quarter results to the third quarter, and then cover several other items.

Net income for the fourth quarter of '03 was $68 million compared with $146 million in the third quarter. Earnings in the fourth quarter were reduced by premiums paid on the repurchase of bonds of $19 million and accrued severance and office lease costs of $9 million. Both of these are after income tax numbers, a combined $46 million before income taxes. Results for the third quarter include an United States income tax benefit of $30 million.

Net income from exploration and production activities was $83 million in the fourth quarter compared with income of $124 million in the third quarter. As I just mentioned, the fourth quarter results include an additional charge of $9 million or E&P cost reduction initiatives that were commenced in the second quarter. This charge includes severance and the cost of reducing leased office space in London. Also, as I noted, the third quarter E&P results include income tax benefits of $30 million. Reflecting the recognition for United States income tax purposes of certain prior year foreign exploration expenses. Excluding these items, E&P earnings were $92 million in the fourth quarter compared with $94 million in the third quarter. The components of this $2 million decline on an after tax basis are as follows. Our average crude oil selling price increased by approximately 70 cents per barrel, including hedging and that increased fourth quarter earnings by $8 million.

Average natural gas prices were also higher increasing fourth quarter earnings by $23 million. Sales volumes were lower reducing earnings by $5 million. Exploration expense was higher reducing earnings by $37 million. Our effective income tax rate was lower increasing earnings by $17 million and all other items net to a decrease of $8 million.

Turning to oil and gas production, which is shown on Page 6 of the press release. In the fourth quarter crude oil and natural gas liquids production was 241,000 barrels per day, the same as in the third quarter. Natural gas production in the fourth quarter was 691 million cubic feet a day, an increase of 17% from the third quarter. This increase is due to the increased seasonal demand for natural gas, principally in the United Kingdom.

On a barrel of oil equivalent basis, production was 356,000 barrels per day in the fourth quarter compared with 339,000 barrels per day in the third quarter. Exploration expense was $116 million in the fourth quarter and $369 million for the full year. Our exploration expense for 2004 is anticipated to be in the $315 to $325 million range. Our planned exploration spend for 2004 is in this same range. The affective income tax rate for exploration and production operations in 2003 was 51%. The E&P affective rate in 2004 is estimated to be in the range of 47% to 51%. The after tax impact of crude oil and U.S. natural gas production hedges in the fourth quarter of 2003 was an opportunity cost of $59 million, $2.67 per barrel of oil equivalent compared with a cost of $54 million in the third quarter.

The status of our hedges at December 31st was as follows: For 2004 we have hedged 70% of our worldwide crude oil production. For 2005, we have hedged 45%. The average price for WTI related open hedge positions is $26.24 in '04 and $25.83 in '05. The average price for Brent related open hedge positions is $24.51 in '04 and $24.41 in 2005. Approximately 18% of the corporation's crude oil are TI related and the remainder are Brent.

In 2004 we also hedged 30 % of our U.S. natural gas. The average price for this U.S. natural gas open position is $5.10. At December 31st, of 2003, we had an after tax deferred hedge loss. The total was $229 million of which $33 million is realized and $196 million is unrealized.

Refining and marketing earnings were $55 million in the fourth quarter compared with $89 million in the third quarter. The corporation share of Hovensa's income was $10 million in the fourth quarter compared about $43 million in the third quarter. R&M earning include $7 million of interest on the [INAUDIBLE] note in both the fourth and third quarters. The balances of the note at December 31st was $334 million and principal and interest payments are current.

Retail operations and energy marketing activities were profitable in the fourth quarter and their earnings were comparable to third quarter amounts. After tax trading trading results amounted to income of $2 million in the fourth quarter compared with $3 million in the third quarter.

As indicated in the press release, net corporate expenses were $29 million in the fourth quarter. This amount includes the premium expense of $19 million after tax, $31 million before taxes from the repurchase of bonds. For the full year, $34 million after taxes, $58 million before taxes of bond repurchase premiums recorded compared to $6 million in 2002. The pre-tax amount of the bond repurchase premiums is recorded in nonoperating income expense in the income statement.

Turning to cash flows. Net cash provided by operating activities in the fourth quarter, including an increase of $103 million from changes in working capital was $423 million. The net proceeds from the issuance of the preferred stock were $653 million. The principal uses of cash were capital expenditures $342 million and debt reduction $546 million, all other changes amounted to an use of $9 million. We had a net increase of cash in the fourth quarter of $179 million.

We issued a total of $13.5 million shares of 7 % mandatory convertible preferred stock for $50.00 per share in the fourth quarter. The net proceeds after underwriting discounts and expenses were $653 million. We also tendered for certain issues of our outstanding [INAUDIBLE] including debt assumed from Triton at the time of the acquisition. As John Hess mentioned, our December 31st cash balance was $518 million and our debt to capitalization ratio was 42.5%. The cash will be used for general corporate purposes including capital expenditures and debt repayment.

This concludes my remarks. We'll be happy to answer questions. Would the Operator please arrange for that?

Thank you, sir. The question and answer session will be conducted electronically. If you would like to ask a question, please do so by stressing the star key followed by the digit one on your touch tone telephone. If you are on a speaker phone please be sure your mute function is turned off to allow your signal to reach our equipment. Once again, that is star one to ask a question. We'll pause a moment to give everyone an opportunity to signal.

Our first question comes from Tyler Dann with Banc of America Securities.

Hi, Jay and John. How are all of you?

Very good. Nice and cold up here.

That's a good thing. Not quite as cold down here in Houston, however. I wanted to, first of all, get an update Phu Horm in Thailand, and also if you were able to comment on whether or not you have had your review with the various rating agencies, including Moody's?

The first one I'll have John O'Connor do. In fact, John and I, two weeks ago were in southeast Asia and were at the Phu Horm site and John will be happy to give you an update on our plans there and then we'll talk about the Moody's review.

Hi, Tyler. There's really nothing of substance to give you updating Phu Horm it except to say our plans previously announced are still on track. We have applied for permits to drill two appraisal wells on the structure. Of course we have had Exxon-Mobile back into the area, probably since the last conference call. We are proceeding to obtain all permits required to proceed with the development. And as soon as we have those we are fairly comfortable we will go to sanction with that projects. I think the things to look out for as a result of the appraisal wells we are drilling in the next three to four months and the potential upside in resources that would accrue in terms of successful completion of those wells. As you remember the gas is already contracted to the [INAUDIBLE] station.

Right. Okay.

And in terms of Moody's, we had our meeting last week. I feel it was a very productive meeting on both sides, and we are awaiting their review.

Okay. Thanks for that. One last question on the production forecast that you mentioned, John. The 355,000 exit rate, would you be able to just go into a bit more detail in terms of you mentioned in your comments you're a bit ahead of schedule in January. It is fairly substantially above the guidance level. I'm curious does it have to do anything with timing of sales of assets, or is it simply just better performing existing assets that aren't going to be sold any more?

It's across a number of different assets. The primary contributor if I can say, because as you know, we had planned and have, indeed implemented significant infield work so we have made provision for substantial down time in [SABA]. I'm very happy to share with you that work is completed. It went much better than prognosed. All of the subsea pumps are installed. They have been brought become on line. Indeed we enjoyed the benefits of the flush production when we brought the wells back on stream. That's about 7,000 barrels a day of that variance in terms of the exit rate. The remaining 8,000 barrels a day or so quite frankly is scattered across seven or eight fields.

In each case, in a couple of gas fields we saw better Norm nations than expected. Each of those contributed to about 1,000 barrels a day. We saw less decline in one of our Gulf of Mexico fields than we had modeled. That was another 1 to 2,000 barrels a day. So yes, it's better performance from the assets we are retaining the primary one being [SABA].

Thank you very much.

Thank you.

Next we'll go to Arjun Murti with Goldman Sachs.

Thank you. Just a couple questions. The year-end reserves of 1.035 billion barrels, a little better than we were looking for, I think though otherwise well within your range. Just wanted to confirm that no reserves were booked for the new developments in EG, and clearly not Shenzi or Tubular Bells?

No, I can confirm that, Arjun. As a matter of fact to two years ago, if I could just address the question of reserves generally. We re-emphasized the importance of consistent and accurately serves booking across the board. And you may recall that in 2002, we did have negative revisions to reserves, part of which was attributable to standardization and performance with SEC requirements.

I would also mention that C&M have long been our reserve calculators in addition to reserve auditors and this is a somewhat unique position in the industry, so we do have industry experts going all over our field reserves. Long-winded answer but again I would confirm we do not book reserves until projects have received board sanction for investment or until marketing contracts have been executed. So no reserving versus associated with the northern block G development until the board sanctions later this year. And certainly no reserves associated with exploration discoveries until development plans have been fully fleshed out and sanctioned by the partners.

That's terrific, John, thanks for the answer. And one follow-up there. In terms of any thoughts on how many appraisal wells you think you'll need at Shenzi and Tubular Bells and what might be the timing I think you have said you are expecting roughly a '08 start-up?

That's right, Arjun. Shenzi, we are currently drilling the first appraisal while our Shenzi number two. Obviously this is a partnership decision. Given the size of the structure, I would dare say we would certainly see a third well and probably a fourth in order to give us the coverage we need. I would also point to the fact that in the first well we had a little over 100 feet of pay. The second well 500 feet of pay. So we clearly have significant variation across this very large structure. Prudence would dictate we have enough appraisal wells before proceeding the project sanction on Shenzi.

Tubular is a somewhat more conformable structure. It will require an appraisal well before we go to sanction. And I would expect to see that that would probably be drilled fourth quarter this year, perhaps sliding into the first quarter next year.

That's great. Thank you very much.

You're welcome.

Next is Steve Enger with Petri Parkman.

Thanks. In the E&P segment, to get to your bottom line number and to get to the info you reported it looked like costs had gone up meaningfully versus the last couple of quarters. Can you comment on that and whether those may be carrying forward into '04 or maybe more one-time items?

Sure, Steve. If you remember on our last conference call for the third quarter, we were forecasting higher than normal exploration expenses. And I think, at that time, we were saying about $95 million to $100 million. And that was due to a couple things.

One, we had a back-ended seismic program that basically had to do with our [INAUDIBLE] bank seismic program. We also had two wells that we knew coming into the fourth quarter that were unsuccessful early in the quarter and that was the last of our Danish commitment wells in 2003, or our feel well and that was about a $14 million well. Plus we had the G-13 well. The third G-13 well which we talked about on the last call. So we knew going into the quarter that we did have an unusual amount of exploration expense in the fourth. The reason that the number is higher than we were talking about back then is typically, in connection when we're reviewing the next year's budget we look at wells we have capitalized on our balance sheet that don't have proofed reserves associated with it and the accounting rules require that if you're not going to do work on those wells to prove up the reserves within the next 12 months you have to expense them. So what happened is we had a Malaysia well which was a small oil discovery and it doesn't currently compete with the slate of development projects we had so we needed to expense that.

There was also another well which actually was promising, but it was a step-out commitment well in Algeria on one of the western edge of one of the fields, and it actually found significant hydrocarbon column, but due to the amount of work that we have going on in the core parts of the fields in Algeria, we are actually not going to get back to that area until 2005. So again we needed to expense that, and so therefore we had higher exploration expense in the quarter that drove that.

Thanks, John, I appreciate that detail. I've actually already incorporated the exploration expense along with your realization and production and beyond that, like I said I'm still to get to the right bottom line number looks like other E&P costs or other operating costs are up. Anything in that area?

No, actually our listing costs are down quarter-to-quarter and our DD&A is down quarter-to-quarter. So on a per barrel basis. So it really -- the driver on it was the exploration expense. Did you have the exploration expense up at 116? You did, huh?

I did after your report this morning.

Okay.

So that's not it. I'll talk to you guys off line about that.

The only other thing I guess I'd add is did you mention -- did you hear that John Schreyer talked about our sales volume that our earnings were down because our sales volumes were actually lower in the fourth quarter. And even though our production was up, just due to the amount of listings we had, we actually, if you want to say it had an under lip during the quarter as it compared to production. So maybe that's the factor in your numbers.

That may be it. Let me roll that through. That may be part of it, anyway.

Secondly can you give us an update on the results from the northern block G appraisal and exploration program, please?

Yeah. I think that, Steve, the drilling results have basically confirmed our picture of northern block G. I think the important outcome is we have confirmed the significance of the Elon Field which is in shallower water. That will provide us with the opportunity to optimize the department as we had hoped. So I would say that, as we said before, the drilling results from northern block G on the whole are favorable.

Fair to infer from that, John, that your appraisal activities, I think as you just said were positive and gave you more confidence on Elon, you also had some true exploratory components to that. I think some of those were in deeper horizons, were those unsuccessful in adding reserving versus?

I think you're absolutely right. The important thing to concentrate on now is the degree of confidence we've gotten as a consequence of the drilling result and that's really what it's all about. We were trying to reduce the uncertainty around the range of reserve outcomes and we have succeeded in doing that. So we are very comfortable that we have increased confidence in the development scenario for northern block G.

We did drill one exploration well as you recall the KBD, which unfortunately was a dry hole. There were a number of exploitation wells which had a mixed result I would say. Of the other wells, half were successful, half were not.

Thank you.

We'll go next to Paul Cheng with Lehman Brothers.

Good afternoon, gentlemen. Several quick questions. John, when you talking about EG, you saying that you have a higher now on the reserve. What's the latest estimate of the reserve range?

I have higher confidence, Paul, but I don't have a reserve range that I feel comfortable with discussing right now. We have just taken the results of the drilling we are putting them into our sub surface models. That work has to flow through and out of that will come a range of reserve outcomes. So I would think in a month to six weeks we would be in a much better informed position to discuss a range of likely outcomes.

Okay. John, can I ask that I think previously that the number that has been following around may be about 500 million barrels net to the companies. Based on what you see, do you think that is a reasonable possibility, conservative or optimistic?

First of all, Paul I have not heard that number floating around. I don't think that is a number we would assign any credibility to with respect to the northern block G development per se. It may be that was a number -- in the total of Equatorial Guinea and that might be closer to the mark.

Mmmm-hmmm. Okay. Thanks so much. And in the sea belt, can you tell us what is the current one rate?

Yeah, sure. We are running at about 40,000 barrels a day -- gross a day. I'm going to have some variation around that. We have a drilling rig working in the field. We have some more wells to be drilled this year. So you're going to see the rate fluctuate somewhat. But I think for planning purposes what we're looking at on average for full year basis would be on the order of 25,000 barrels a day net to us. In addition to that, I would say the field is performing as expected. We are very happy with the way it's performing.

All right. John, when you say 25 net to you, the gross is it 45?

No, it's more of the order of 40, Paul.

Okay.

The net to us is roughly, rule of thumb, about 71, 72% of the gross.

Okay. So, in other words you expense 40 is probably about a peak of the [INAUDIBLE].

At this time, for this year. I think as we see how the field performs -- again, I would emphasize it's important to get some more production history from this field. We will get significant information through 2004, so for the time being, that's the rate we're targeting.

Okay.

We want to optimize recovery from the field. So it's conceivable that the rate thereafter would change.

Okay.

Hopefully positively, just in case anybody misinterprets what I'm saying.

And John, are you still targeting a full year basis exploration expense somewhere in the $250 to $300 million a year going forward?

Yeah, for this year I think the number that John Schreyer mentioned was in the vicinity of $315 to $325 our exploration expense this year. We would hope to beat that in terms of exploration expense and come in somewhat lower depending on drilling results.

Okay. But how about beyond 2004 and on a longer term basis, I think that one of the target or the hope is that the exploration expense is going to be lower. Is that still the longer term objective?

Let me just give some color commentary on that, Paul because in exploration expense, as you know, we have got both Wild Cat Exploration, together with appraisal, which adds exploitation drilling. So you've really got three different categories. In the past we have talked about exploration expense, we've talked about it being in the order of say $220 to $250. That was with respect to rank exploration, did not include exploitation. As we go over the assets and comb through them, we are surfacing good exploitation opportunities which is really additive to the base rank Wild Cat Exploration program. I think if you look at it in that context, probably rank Wild Cat exploration will run in the order of $230 to $250 and the difference between that and the additional exploration expense that we project will be for exploitation drilling where those opportunities are worthwhile.

Okay. The final two questions I think is for John Hess. John, on capital spending for 2004, can you refresh my memory what's that number? You say based on a $24.00 [INAUDIBLE] -- So you will have positive cash. Will you intend to increase your spending, or go to pay down further the debt? It doesn't look like you have a lot of debt for you to pay down, anyway.

Yes. In terms of our capital expenditures, we are forecasting $1.52 billion versus the $1.36 billion in 2003. Again 95% going to exploration production in both years. Using 24 WTI, you're right the cash flow coming in versus the capital expenditure dividends going out. We are estimating to be roughly in balance. I think the key point there is if we come in higher than that, the first priority as we've said and both John's comments and also comments I've made over time our first priority is to fund these developments in the heavy investment mode and then whatever surplus there is obviously we will consider paying down debt further as the year goes on according to how the cash flows come out.

Will you plan to increase the spending beyond the current budget if you have more free cash?

Well, Paul, I have to tell you, we have a full set of opportunities that going to create a lot of value shareholders the next two years and we are focused 100% on executing and delivering those results. So we're looking at our budget and sticking to it because we have plenty on our plate with these 12 developments and we certainly intend on bringing them across the finish line by 2006.

Okay. Finally, John, on the hedging program the strategy, given the company financial position much stronger today, going forward, will you scale back your hedging program so that -- I mean because you really don't need to have such an expensive hedging program any more.

Right.

So what is your overall plan on that?

Right. Between now and 2006 when the developments come on stream, obviously we are in the heavy investment mode and we want to protect the revenue side of our cash flow to make sure we have the funds for those developments. Obviously the mandatory convert gave us that much more breathing room, financial flexibility to get the developments done and really have a strong financial balance sheet. After 2005, 2006 comes on, we'll go back to where we were in hedging which is, you know, basically to lock in superior returns, but looking at a more modest program to protect our risk -- to reduce our risk, but certainly not to the level of the percents that we have right now.

Okay. Very good. Thank you.

We'll go next to Gene Gillespie with Howard, Weil.

Good morning.

Good morning.

John, in your comments you indicated that you are working on developments which would add about 100,000 BOEs a day to production.

Of new production.

I'm sorry?

Of new production.

Of new production, yes. You identified Llano and the JDA, which is about 40,000 BOEs a day in total. Could you identify the remainder of that?

That's question number one. Secondly, it seems to me that your predecessors had a take or pay contract for the JDA in the area of $2.50 to $2.60, is that still operable? Or is that not correct information?

No, no. Repeat the second piece of the JDA question on the take or pay, I want to make sure I understand exactly your question.

I believe, if I remember correctly that your predecessors had a contract from Malaysia and from Thailand, either/or for an amount at about $2.60 a MCF.

Right. Okay. I'll answer the take or pay and then ask John O'Connor to address the developments and give you a little more texture on that and details on that.

On the take or pay, we as sellers with PETRONAS and the MTJA, there is a take or pay the current price I think is closer to $3.00 right now because there's an escalator in the price and that's at the platform where the transfer occurs. We and the other sellers, you know, it's a contractual issue. We are going to protect our contractual rights and are moving forward to issue an invoice for the take or pay. And it's a matter that is being discussed now with the buyers in terms of how to address it. And I think the real take away here is everything's looking, you know, encouraging on first sales the way I described in my comments, but in parallel and separate from that the take or pay issue is one that is being surfaced with the buyers and will be an issue that we will be working with them on during the year.

Is $3.00 consistent with the current market?

Yeah, $3.00 is what the price is at the well head. You know, Thailand's got based upon the field and where the market is, has some other prices, but it is consistent with the market as we take it into Peninsular Malaysia and ultimately Peninsular Thailand.

Thank you.

And John O'Connor is going to address the points on other development that we have.

Before I -- numerous rate specific fields, Gene, the impression I would like to leave with you is we have both a geographical variety and a variety of operators and a variety of development types, included in the 12 fields of developments that John has talked about. And I mention that only so that people get a clear understanding there is a balanced risk it's a portfolio approach. In some cases we operate in some cases whether BP or Shell operate and other partners beside. Having said that the significant increases between now and year 2006 will come from streaming the JDA, we just talked about. Will come from northern block G coming on stream. Will come from increased delivery from our gas sale [INAUDIBLE] joint venture with [SONITREC]. Will come from the Llano Field start-up which John alluded to starting up where we have 50% interest starting up in the second quarter of this year. Will come from initiation of gas sales from [INAUDIBLE] and onshore Thailand and from [PONKA] in shallow waters offshore of east Java. We will also see streaming and full deliverability from our Atlantic development the natural gas development high rate, high deliverability in the North Sea the U.K. sector of the North Sea.

Thank you, John.

You're welcome.

Wheel many go next to Jay Saunders with Deutsche.

Thanks. Just a couple quick ones. Can you give any guidance on Cap Ex on '05 at a group level? And the second one would be turn around in the downstream if you can tell us what the schedule looks like for this year?

Yeah. No we're not giving guidance for Cap Ex for '05. And in terms of turn around, no major work at Hovensa to speak of. Right now Hovensa is running about 500,000 barrels a day pretty much maximum rate. The cat cracker is at about 146,000 and the Coker is about 60,000 barrels a day. It's maximum capacity and we are happy to be experiencing the margins we have right now.

Sounds like you are mostly finished with clean gasoline?

Actually, no. Hovensa will be dealing with low sulfur gas rigs and low sulfur diesel rigs between the 2004 and 2006 period. But all of that has been in our plans for awhile. The expenditures in the range to Hovensa's account, not Hess's's account because it's a joint venture investment about $450 million. Between the cash on hand at Hovensa as well as expected cash flows, no major debt -- no debt is going to be needed, we think between the cash and cash flow all the funding for about $450 million will be able to be handled by the join venture.

Okay, great. Thank you.

Next is David Wheeler with J.P. Morgan.

Hi, two questions. First you mentioned unit costs, target of bringing them down $2.00 to $3.00 by '06. What's the starting point?

Let me understand what the -- when you say starting point I need to understand what you mean by that.

Are you saying from 2003 levels?

Yes. That's from the 2003 levels.

Which what were the costs?

1730 for the year.

1730. Okay. And that's a combination of bringing -- what's the driver there production costs DD&A versus exploration? Is there any break-out that you can give us?

It really is a combination of all three. The newer production that's coming on will reduce our costs on both the DD&A and the listing cost line, and then as John O'Connor mentioned there could be a slight reduction in exploration expense as we move forward. Our unit costs, we are including exploration expense in that as well.

Right. Right. Okay. All right. Second question. The comment about balanced cash flow and Cap Ex in 2004. I guess I'm a bit puzzled by this. Maybe you can help me out with my arithmetic. The Cap Ex is 1.5 you have dividends of 150 if you include the new preferred. And in 2003 -- so that gives you about 1.65 in outflows. Your '03 cash flows from operations looks on the press release to be 1.6 billion and I'm thinking as you go from '03 to '04 your production is down 10% you're assuming a lower oil price you mentioned R&M is the guest it's been in ten years I wouldn't assume that's your assumption in '04 so I'm' not sure how you're not bleeding a few hundred million dollars in '04 how your cash flow is going to stay up at that level. Am I missing anything in my --

Yeah it may be your assumptions versus ours. I think the real take away is our focus is investing all our cash in these developments which are the bulk of capital expenditure and assuming WTI prices of $24.00 per barrel, and other assumptions that we have in other parts of the company, we believe that our capital expenditure and cash flow will roughly be balanced in 2004. Meaning we are not going to need any debt. I think that's the real take away.

Okay. In that assumption of balance, what are you assuming for refining and marketing? Are you assuming mid cycle or better than mid cycle this year?

I would assume closer to somewhere between mid cycle and this year.

Okay.

When I say this year, meaning what 2003 was.

Right. Right. Okay. Thanks, John.

Right.

Next we'll go to Fred Leuffer with Bear Stearns.

Hi, John?

Hey, Fred.

Just a couple of questions on reserve replacement and finding costs. First, excluding acquisitions, what was the reserve replacement ratio?

Excluding acquisitions and sales, about 50%. It varies depending on how you handle the treatment of the premiere interest.

Right. Which was -- and also the JDA, right? Which was a swap.

Yes, correct.

So the 50% takes the JDA out, John?

Yes.

Okay. Now, you also indicated that you had negative reserve revisions, can you quantify those for us?

In 2002. In 2002. My point was that we had gone over and imposed a standardized best practice reserve accounting process two years ago, and that part of the consequences of that was that 12 months ago, year-end '02 we had some negative revisions.

I know about those.

I'm not talking about 2003, Fred.

So there were no additional negative revisions in '03, right?

Correct. There were no surprises, absolutely.

All right. Good. The other thing is the higher exit rate which you explained --

Right.

-- [SABA] down time less than expected, why haven't you upped your forecast on production for '04?

I think it's fair to say that this was a one off event which impacted the exit rate. Whether that will carry through, through the four quarters of this year, I think -- I'm not confident enough to factor into a revision of the outlook.

Okay. All right. That's good. Thanks.

We'll go next to Fadel Gheit with Oppenheimer and Company.

Good afternoon. A couple of quick quick questions. Assuming the Libyan factions will be lifted soon, hopefully, what would the time line for you and what role will Libya play in your future?

Fadel, obviously this is a political issue going on between the U.S. government and the Libyan government. I don't want to speculate on what the timing would be. So, I don't think it would be appropriate to give much color commentary except that, you know, very constructive dialogue is under way. Obviously the next phase of the negotiations have to do with the inspectors and the weapons of mass destruction. We with Conoco and Marathon are having talks with our counter parts at the Libyan Oil Company on possible terms for re-entry, and it would be premature at this time to give more detail than that.

Okay. Strategically speaking is it an important area, not very important, or --

We will be very happy to have those reserves, that production, that gas glow and the opportunity upside both in exploration and redevelopment in our portfolio and it would fit very nicely as a compliment to our portfolio. And it fits our long-term strategy of long life, low cost reserves with up side.

Now some of the smaller question. I notice that most of cost expenses and expenses moved higher. One of them is [ INAUDIBLE ] which is higher despite lower debt level. Any explanation why?

I'm going to have John Rielly address that. It's a good question.

Hi, Fadel. It really has to do with the amount of capitalized interest that we have. So there is less capitalized interest that you saw in '03 than you saw in 2002.

Now, having said that as these developments begin to kick in and we spend more dollars on the development projects that the capitalized interest number will begin to increase again. So we're now anticipating, in 2004 that our capitalized interest on number will be a little bit higher than it was in 2003.

Okay. Also I notice that the G&A expense moved higher in the quarter and for the year. The reasons and what would -- should I assume for run rate for 2004?

For G&A, for the quarter in particular you heard John Schreyer mention that we had $9 million of severance and property related costs. We had that charge. That's an after tax number. The before tax amount is included in our G&A line in the quarter, and that's the reason why our quarter G&A is up.

When you're looking at it for the full year, you've got a difference of about $80 to $90 million on a G&A line. Over half of that, actually, because we talked about it we had a reorganization charge in the second quarter again related to E&P.

Right.

About half of that relates to those reorganization costs. Also our pension costs for the year are up like other companies. For us it was up $18 million in 2003 versus 2002. And then the remainder of that had to do with the hard market in the insurance area, and so our insurance costs were up, and that -- that is basically the reason for the increase in G&A in 2003.

So what you can expect then in 2004 is the one-time severance charges will be removed in 2004. Although we still do have ten to $15 million of costs still to come on our E&P reorganization that we're still undergoing, but outside of that there will be some fixed cost reductions in 2004. So you're looking at a range of G&A in the, I'd say $280 to $290 million for 2004.

Thank you.

You're welcome.

Our next question comes from Mark Tibalt with Barclays.

Yeah. Good morning. I'm calling to ask about if you could give a percentage of PUD ratio on the new reserves, as well as if you can give us a break out of the F&D costs for 2003?

Yeah, I can give you the F&D costs for 2003, certainly. That was $11.50. And this is somewhat important tour to calculate because of the issue of the swaps and how they are accounted for. However, I think we have seen prudent in making negative impacts of the consequence of the swaps by removing, from the calculation the Columbia reserves of about 55 million barrels of oil equivalent and the Scott Telford reserves of about 14,000 barrels of oil equivalent. Given the adds and taking those reserves out on that basis, the F&D costs for 2003 is $11.50.

As far as the proved undeveloped component of the reserves is concerned it's about 31%.

Thank you.

You're welcome, Mark.

Today's final question comes from Akeefa Cowen with Morgan Stanley.

I just wondered on the reserve replacement rate the 50% that you had referenced, does that include the positive impact? I think it was about 25 million BOE from the [INAUDIBLE] in terms of the swap?

It does not because it excludes acquisition sales.

Okay. So it's 50% excluding.

That's right.

Okay. Thank you.

That concludes our question and answer session. Mr. Hess, I would like to turn the call back over to you for concluding remarks.

We appreciate your interest in our company and look forward to updating you on our progress the next call.

Again, I'd like to remind everyone that you may listen to the rebroadcast of this conference beginning 3:00 p.m. Eastern today through February 4 at midnight by dialing 719-457-0820 or 1-888-203-1112 and enter confirmation code 598650 on your telephone. Thank you for your participation. That concludes the conference call today and you may now disconnect.