赫斯 (HES) 2004 Q1 法說會逐字稿

Good morning ladies and gentlemen and welcome to the Amerada Hess conference call. My name is Jill and I will be your coordinator for today. [Operator Instructions] I would like to remind all participants that this call is being recorded for replay purposes only.

I would now like to hand the call over the Mr. J. Wilson, Vice President, Investor Relations. Please proceed sir.

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

Certain forward looking information and other previously undisclosed items may be discussed during this call.

I will turn the call over to John Hess.

Thank you, Jay and welcome to our first quarter conference call.

I would like to make a few brief comments on our strong first quarter financial results and the progress we are making in our exploration and production business.

In terms of our first quarter financial results, exploration production earned $207 million versus $120 million for the same period last year. The results reflected strong oil and natural gas prices and reduced costs together with strong production performance.

Our refining and marketing business earned $112 million for the quarter versus $136 million for the same period a year ago. Refining earnings benefited from strong margins and high utilization rates. Energy marketing earnings were strong but were lower than last year due to it being a warmer winter. Retail marketing earnings were down versus a year ago as a result of higher wholesale fuel prices.

In terms of our exploration production business, all our development projects are on schedule.

In the deep water Gulf of Mexico the Llano [ph] Field, in which we have a 50% interest, will commence production in the next few days. On block A-18 in the Malaysia/Thailand joint development area, the offshore pipe lay is continuing and facilities construction is proceeding to plan. In Equatorial Guinea, the plan of development for the northern block G fields will be submitted to the government in June.

With regard to exploration at Shenzi in the deep water Gulf of Mexico, we have completed drilling a second side track on the number 2 well with encouraging results. After operations on the number 2 well are completed, the rig will move to drill the Shenzi number 3 well.

In Indonesia a two well appraisal program is under way in [inaudible] Pangkah. This program will determine the extent of the field and may add additional reserves.

With regard to Libya, the United States government's easing of sanctions will allow Amerada Hess and our our oasis partners to further advance plans to return to our operations there. Negotiations regarding the terms of our re-entry are under way and the oasis partners and the Libyan national oil company continue to make progress in those discussions.

In conclusion, we are pleased with our first quarter operating and financial performance. We were on track in executing our development projects and appraising our recent discoveries. We have improved our financial position and are building a strong platform for the future.

I will now turn the call over to John Rielly, who will provide more details on our financial results, after which we will be happy to take your questions.

Thank you, John. Hello, everyone.

Earnings release was issued this morning and it appears on our website. I will discuss our usual comparison of first quarter results to the fourth quarter of last year.

Net income was $281 million in the first quarter of 2004 compared with $68 million in the fourth quarter of 2003. Net income from exploration and production activities was $207 million in the first quarter of 2004 compared with income of $83 million in the fourth quarter of 2003.

First quarter E&P earnings included gain of $19 million from the sale of an office building in Aberdeen, Scotland. Fourth quarter 2003 E&P results include a charge of $9 million for accrued severance and office lease costs in the United Kingdom. Excluding these items, E&P earnings were $188 million in the first quarter and $92 million in the fourth quarter of 2003.

The components of this change on an after tax basis are as follows, our average crude oil selling price increased by approximately $1.50 per barrel including hedging which increased our earnings by $11 million. Average natural gas prices were also higher which increased earnings by $22 million. Sales volumes were higher which increased earnings by $4 million. Operating costs and exploration expenses were lower which increased earnings by $46 million. All other items increased earnings by $13 million which led to a total increase in first quarter adjusted E&P income of $96 million.

The after tax impact of crude oil and U.S. natural gas production hedges in the first quarter of 2004 was an opportunity cost of $73 million or $2.99 per barrel of oil equivalent. Compared with a cost of $59 million in the fourth quarter of 2003.

The status of our hedges at March 31 was as follows. For 2004 we have hedged 70% of our crude oil production and 35% of our U.S. natural gas production. In 2005, we have hedged 55% of our crude oil production and we do not have any hedges for U.S. natural gas 2005. The average price for WTI related open hedge position is $27.02 in 2004 and $26.25 in 2005. The average price per brent related open hedge position is $25 in 2004 and $24.87 in 2005. Approximately 18% of the corporations crude oil hedges are WTI related and the remainder are Brent. The average price for U.S. natural gas open hedge positions is $5.04.

In addition to the hedges I just mentioned, we currently have 24,000 barrels per day of Brent related production hedges from 2006 through 2012. The majority of these hedges cover a portion of our plant production from Equatorial Guinea during those years. The average price of these hedge positions is $26.20 per barrel.

The after tax deferred hedge loss at March 31, 2004, amounted to $329 million. Of this amount, $44 million was realized and $285 million was unrealized.

Moving to our downstream operations, refining and marketing earnings were $112 million in the first quarter of 2004 compared with $55 million in the fourth quarter of 2003. The corporation's share of [inaudible] income was $51 million in the first quarter compared with $10 million in the fourth quarter.

R&M earnings include $7 million of interest on the [inaudible] note in both the first and fourth quarters. The balance of the [inaudible] note at March 31 was $303 million and principle and interest payments are current.

The results of retail operations decreased in the first quarter of 2004 compared with the fourth quarter of 2003 reflecting lower margins on gasoline. Earnings from energy market activity in the first quarter were seasonably higher than the fourth quarter last year. After tax trading results amounted to income of $15 million in the first quarter of 2004 compared with $2 million in the fourth quarter of 2003.

Moving to corporate costs. Net corporate expenses were $2 million in the first quarter of 2004 and $29 million in the fourth quarter of 2003. The first quarter results include an income tax benefit of $13 million resulting from the completion of a prior year United States income tax audit. The fourth quarter amount included premium expense of $19 million or $31 million before income tax from the repurchase of bonds.

Turning to cash flow, net cash provided by operating activities in the first quarter net of a decrease of $49 million from changes in working capital was $394 million. Other net cash receipts, including proceeds from asset sales and a payment on the [inaudible] note, amounted to $89 million.

The principle uses of cash were as follows. Capital expenditures amounted to $364 million. Cash dividends paid were $67 million. We reduced debt by $13 million in the quarter. We had a net increase in cash and short term investments in the first quarter of $39 million. At March 31, we had $557 million of cash and short term investments on hand. The corporation debt to equity ratio at March 31 was 41.7%.

This concludes my remarks. We will be happy to answer any questions. Jill, please prepare us for the question.

Your first question comes from Mr. Fred Leuffer from Bear, Stearns.

Good morning, gentlemen.

Good morning.

Just a couple of questions. John Rielly, do you have the allocation for G&A in exploration and production? Trying to come up with a unit cost per barrel.

Let me go over the overall unit costs. Our unit costs were $16.16 in the first quarter. And the reduction in unit costs were due to accommodation of higher production volumes as well as lower costs resulting from favorable operating performance. I think, as we have stated, our plan is to lower our unit costs by $2 to $3 in the next three years as compared to our 2003 results. We plan on accomplishing that by reducing our fixed base of costs and by adding new lower cost production. Just wanted to add that as for 2004, we were continuing to forecast our unit cost to be comparable to the 2003 level since our per barrel cost will likely increase as production declines from our high first quarter performance.

John, what were the components because I'm coming away with higher -- again, I don't have the allocation for G&A, but I had you at about $18.13 in the fourth quarter. What are the components that get you to that lower 16.16 per barrel?

Sure, our exploration was approximately $2.50 per barrel. Our listing costs were $5.95 per barrel. Our G&A costs were just under $1 per barrel. And our DD&A was $6.75 per barrel.

Looks like the DD&A drops quite a bit. What's behind that?

During 2003, again, it becomes a mix of fields in what the DD&A per barrel becomes. You have to mix of fields either coming off production at a higher rate, which I think just drops us down, as you know our production forecast for this year is at 3.5. We do have some lower production this year. What's happening in some of our higher cost fields are coming off and it reduced in the first quarter our DD&A rate.

Okay. Secondly, can you give us a reserve estimate for the north block in the northern block EG?

I can't give you a reserve estimate .

You broke up.

Can you hear me now?

Yes.

Okay, sorry, I was saying that what I would say to you is that northern block G was roughly comparable in size to Saver, I mentioned in our last conference call it was roughly the same order of magnitude of 77 to 800 million barrels of oil in place and the [inaudible] recovery factor you can get from the oil in place to roughly the size of the field is [inaudible].

So that's like 500 million barrels total, right?

No. Between the two fields, between Saver and northern block g.

Right.

That might be about the right order.

About 500?

Two fields combined. Saver plus the northern block G.

Right, exactly, okay. Which is kind of what you had indicated earlier.

On a gross basis, obviously.

That's right. And John Hess or John O'Connor, can you give us more color on Libya. What do you think it could add to the company's production profits? Cap Ex? What kind of time frame do you see developing here?

Fred, you know, the U.S. government now has lifted the sanctions so we are in negotiations with a Libyan national oil company to reenter the country. Major focus of the negotiations are the economic terms for re-entry. And it would premature and inappropriate for me to comment now on what that would mean in terms of reserves, in terms of cash flow, in terms of production. I will say this. The Libyan assets will fit very nicely back in our portfolio and have the right metrics both in unit cost and reserve life and actually upside in terms of exploitation and exploration for our portfolio going forward. So we would be very happy to have it back in our portfolio, but we are also going to be very disciplined about the economic terms to make sure it's competitive with other investment opportunities that we have. So, negotiations are ongoing. The Libyan's want us back and we want to be back. But we will be disciplined about what terms we accept on a going-forward basis.

Thank you.

[Operator Instructions] Questions will be taken in order as received.

Our next question comes from the line of Bruce Lanni from A.G. Edwards. Please proceed sir.

Good morning everyone. Just a real quick question following up on what Fred said regarding Libya. Two things, first of all, are you negotiating additional concessions above and beyond when you exited Libya, that would be one question. And then in addition, are there any thoughts -- are you going to continue as the Oasis Group or is there any thoughts of operating independently over there?

The whole focus right now is on WahHa [ph], which is Arabic means oasis, that's the name of the concession, its about 13 million acres. The focus of the Oasis Partners is on Oasis itself. And it would be premature to discuss anything outside of that at this moment. Then, John, one other question as long as I have you on. Any thoughts of resisting your hedging policy. If I understood correctly, the losses that have been incurred to date have been pretty substantial. Are you going to stick with that -- looking at possibly unwinding some hedges. I know you went over the new hedges were, but could you comment on that? It's wonderful to have 50/50, 20/20 hind sight and -- I think the point here is as follows.

We took steps last year to put a major repositioning program for EMP in place. We lowered our production significantly in the short term, and we were in the investment mode last year, this year, and next year. It certainly the right long-term decision. So during this time period of significant repositioning, we thought it prudent to actually reduce the risk in our cash flows and that's why we took the hedges and that's why we took the mandatory convertible preferred in December. These moves allowed us to have the financial strength, the financial flexibility and resiliency to ensure that we could spend the billion five/billion six hundred million of Cap Ex this year, of which about 900 is development similar numbers for next year, and make sure that we could see our developments through on a timely basis. So we are in this repositioning mode and during that time we wanted to reduce our risk. Yes, there is an opportunity cost and then in hindsight would indicate -- wish we had maybe started the hedging today as opposed to a year ago, but we are where we are. Once the developments are on stream and generating the significant increase in cash flow in '06, we will be able to withstand more commodity risk and we will actually be looking to do that. So our hedging percent '06 and beyond will be a significantly reduced number from the one that we have for our '04 and '05. But, in this transition period we wanted to reduce risk, we have done that. There is an opportunity cost, but we wanted to make sure that we could protect the investments we have for the developments we have.

Okay, I fully understand that. Then as far as the new projects that you talked about, the everything pretty much is on schedule as far as EG and other --

Yes, we are very pleased. All of our organization is focused and executing the developments that is the major priority for the year, to bring them in on time, on budget and we were on track.

Great. I appreciate it. Thank you.

Your next question comes from Mr. Steve Enger from Petrie Parkman. Please proceed, sir.

Good morning.

Morning.

Couple of things. One on 2004 production, your 325 looks increasingly at risk in a positive sort of way. Obviously nice performance in the first quarter. Can you give us a little more color on that full year projection? Is there a lot of cushion in there so to speak for downtime and such?

Hi, Steve. We are right now still sticking with our 325 production. We are happy with our first quarter performance. But as you know, it is only one quarter. And there are, as you know, especially in the U.K. in the summer season in the third quarter, there is a lot of maintenance that does go on. So we do expect our production to decline at that point. We had a little better experience as far as work-overs and maintenance and therefore had higher production in the first quarter. We don't know if -- based on history that could turn around a bit. So I think at this point we just -- we are staying with the 325. Yes, the first quarter gives us more confidence obviously that we'll get that number. But as the year progresses, we will update that guidance. We do see that we have a positive surprise.

Okay. And then on exploration, what are the goals of the next well at Shenzi, and specifically do you plan to go deeper to test the Eocene.

The next well will be a fairly extended step-out from the number two location. The ideal expectation would be to demonstrate reservoir continuity and sand continuity from the first to the second well. If that were to be the case, it is probable that that would give us a high degree of confidence that we were close to a sanctionable project. So really, that's the primary objective. As to drilling deeper, I have not seen a proposal to do that at this location. I don't think it's in the ideal. You may recall that we have planned to do that in the number two well, which was better located with respect to [inaudible]. We had operational problems so as a result we have temporarily P&A'd the number 2 well. But, at some point in time, when appropriate, we will come back on this structure and do the drill deeper.

Okay, thanks John. And then finally, can you talk about the '04 exploration program as you see it now in terms of impact wells whether they in the gulf or internationally?

Sure. In the Gulf, the key well is the wemably [ph] well, which we would expect to probably spot late second quarter, early third quarter. That is a miocene prospect that has a lot of characteristics that make it look similar to the Tubular Bells prospect that we were involved in last year. That's the key ranked wildcat, I think, to look out for in the Gulf of Mexico.

Elsewhere we have a total of 18 wild cat and appraisal wells left to be drilled. The concentration of ore in southeast Asia, which is one of our core areas, they would be [inaudible] interesting wells to look out for. We have a couple of wells in the North Sea with a well in west Africa and couple of in onshore Algeria. That gives you a sense of the spread of the opportunities that we are looking at this year.

And if Phu Horm [ph] included in that list?

Yes it is, Phu Horm we are mobilizing a rig. We have a two well program planned which are really appraisal in nature. And we expect the rig to be on location in May [inaudible] we will probably be drilling and testing those wells through the second half of the year.

Thanks a lot.

You're welcome.

Your next question comes from Steven Pfiefer from Merrill Lynch. Please proceed sir.

Hi guys, had couple of questions on the international gas realization. Year over year, it went up from, I guess, $3 to little over 4 and the liquids realization went from 25 to 27. I know that internationally the pricing is somewhat tied to oil. But, I just was wondering if there was a mix effects or any other factors that would kind of explain why the gas is up so much more than the oil. Or is it just simply, you know, the relationship between liquids and gas.

John Rielly will try to answer that question.

Steve, you basically had the answer. It was more the relationship -- it was on the international gas side, the relationship to the oil which allowed that to increase. There is a bit of a mix, but for the most part or a good part of our gas really is set at some type of fixed price [inaudible] that is tied to oil when you go over seas. As far as the international crude, again, we just had a little better -- we had a little better realization in the fourth quarter, or we should say a little less of a differential loss of the benchmark and just with our production being a little bit higher than forecasted, we said we had 70% hedged. We are getting the benefit of production coming in at the higher on hedge price.

Perfect. And then just on Equatorial Guinea, John, you said -- plan to submit the development plan in June, could you just update us on your best expectation for timing of how that gets turned around and, I guess, is there any change to the onstream estimate?

Pretty much we are pleased obviously that the planning schedule that we laid out for the optimization of the development in northern block g is on track. We have basically finished the optimization work, we will now move over to documentation phase. So, through the month of May, that we will documenting our proposals, discussing and clarifying them with partners, the national oil company, the government authorities and we are still on track for our plan submission to the government of the first week of June. Obviously it's not possible to speculate how long it will take, Steve, to have that turned around. But, as I said on previous occasions, we work very closely with both our partners, the national oil company and the government authorities. So, we would not expect undue amount of time before receiving approval to proceed to the development. As to the time it will take, I would have thought it's probably going to be some 27 to 30 months subsequent to receiving approval to proceed before we see first oil. So the timing of first oil we still expect to see the latter half of '06 on the presumption that we get a quick turnaround of the approval [inaudible].

Great, and then just now that you have completed the seismic and the study work up there, could you just maybe discuss what was learned from that and what is it that may -- as you optimize block g relative to [inaudible] -- the northern block g relative to [inaudible], what is it that you may think about doing different on that development, if anything?

We have obviously a number of encouraging progress milestones as we have delved deeper, in more detail, both into the sub-surface in terms of understanding what is a complex series of reservoirs, but we feel confidant that we have an extremely good view model and reservoir model and, obviously, the drilling results that we embarked on in the third and fourth quarter of last year have also added to the resource base in northern block G. As to the facilities, we have come up with a compelling series of facilities to have a low cost development there which will be quite robust. So overall, I think this is going to be attractive and appealing project.

Okay, thank you.

Very welcome.

And your next question comes from Mr. Mark Flannery for Credit Suisse First Boston. Please proceed sir.

Thanks. Yeah, my question is on U.S. natural gas realization, which this quarter was much closer to the bench mark than we have seen for quite sometime. Is that simply the effect of the hedging program? Or is there something else going on in the U.S. natural gas realization that we can't see in the press release?

It is really -- it's comparative of where we were in our hedge program. The actual differentials off the benchmark are quite similar basically in 2003 and 2004 Going into 2003 we had hedged approximately 45% of our U.S. natural gas, at a price around us at the beginning of the year numbers, I think, around $4.15. So we had some losses on our U.S. natural gas. We have less hedges in place right now in '04 and at a higher price that essentially are hedge program for U.S. natural gas was break even in the first quarter. So you are seeing the differential off the benchmark.

Right and -- just a question on, as you change the proportion of gas hedged and the pricing, if that changes throughout the year, would we see an effect of that in the P&L if suddenly, if you suddenly decided to take some of these off or put some more on? Would we see that as a line item in the P&L, or did this just get bundled into E&P.

What typically happens is if you have hedges in place, if we do liquidate hedges before the actual production that we have hedged, it typically will remain on our balance sheet as deferred realized loss initially and then at the time the related production comes about you release that into our income statement. You do not see a separate line item for that because what we are doing is hedging the sales price so it comes through in our revenue so what you will come up seeing that in the realized price at that time.

Right, okay, thank you very much.

Your next question comes from Mr. Jay Saunders from Deutsche Bank. Please proceed, sir.

Thanks, just a couple quick ones. Was wondering on the downstream number, what portion of that is coming from the fixed percentage interest in -- in HedCo [ph] and second question, the -- of the '05 hedges, what proportion -- I think I just missed this of -- what proportion of the 55% of the crude is WTI? And finally just one more. The exploration expense for the year. Wondering if you have changed the outlook for that? Or is what the outlook, basically?

Okay, I think I have all your questions. As far as our trading income, we -- it is $15 million in the first quarter of 2004. That's our trading operation. It does encompass HedCo [ph] and some corporation proprietary trading. But that's the number we give from a trading standpoint, it's $15 million in the first quarter. As far as our exploration expense for the year we are n changing our guidance that we provided in the first quarter conference call or in our 10K, so we are still saying in the 315 to 325 area for exploration expense. And as for 2005, the percentage that is WTI versus -- Brent, it's 18% is WTI related hedges and the remainder of Brent.

Okay, so just on a first note, energy marketing is separate from the $15 million.

Correct.

Okay, right, thanks.

You are welcome.

Your next question comes from Ms. Jennifer Rowland from J.P. Morgan. Please proceed Ma'am.

Good morning. Question on the cost savings that you were targeting on the restructuring program. I think you were targeting $15 million pre-tax and achieving 60% of that in '04.. I'm just wondering where things stand on that, how much you realized this quarter and if the outlook for the year has changed?

The outlook for the year has not changed and we are still looking for the $50 million and 60% this year. Again, it's a combination of savings on our lease cost that we have in the U.K. as well as our personnel costs. And so we have started the realization through the first quarter and I would say it is a little bit back-ended in the year because we still have people that are on staff at this point so, we will be picking up a little bit more of the benefit the second and fourth quarters.

Okay, and then just one more quick one. On Hovensa [ph], you have any planned maintenance scheduled for this year.

There is no major programs outside of the normal course -- smaller units. Some of those major programs start next year and the year after as we do low sulfur -- these [inaudible] low sulfur gasoline change over and have some turnarounds then, so nothing major for this year. And Hovensa [ph] ran, I believe, 499,000 barrels a day on average for the first quarter and it continues to run at the high rates and we get the benefit of the strong commodity market that we were in right now.

Okay, thank you.

Your next question comes from Mr. Paul Cheng from Lehman Brothers. Please proceed sir.

Hi, good morning guys.

Morning.

Congratulations. Very good quarter.

Thanks Paul.

John, couple quick questions. If there are -- maybe I missed it from the early remark that you made. Why that the U.K. gas [inaudible] will be down sequentially from the fourth quarter? Seasonally that should -- the [inaudible] should be up. I didn't realize that you have other sales in the fourth quarter. Are there any particular reason we should take that into consideration?

I would not want to take it and expand it out for you, quite right, it is a bit of an anomaly. Couple of combination factors. There were some operational glitches in a couple of fields and we also experienced lower nominations from the buyer during the quarter which is [inaudible] -- which is a [inaudible]-off effect. [inaudible]

So that means that even though sequentially that in the second quarter we will expend [inaudible] should be down, but we should -- base on a base [inaudible] to be higher than what we are showing in the first quarter.

Spot on Paul.

Okay.

Quite right.

Secondly. John, can you let us know what is the [inaudible] gross production, I mean, net to you and when are you at 23,000, what is the gross number?

Right now, we are running a gross number of 40,000 barrels a day, Paul, I'm very pleased with that. That's the target plattue level we have set for optimum recovery from the field. And our net from that currently would be about 28,000 barrels a day.

So why now you are -- in the second quarter your net is 28?

This is early in the second quarter obviously.

Right. So far?

[inaudible] operation experience over the past week or so has been 40,000 in excess of 40,000 barrels a day gross, which would net us 28,000 barrels a day. Obviously we have been coming back from a low in the first quarter, which was operational in nature.

And I suppose it may be a bit premature. Any kind of production estimate for the northern block G.

Yeah, it is premature. What we would like to do there, Paul, obviously is get all of the approvals from our partners in the government and once we have the approval from DOD and have [inaudible] time to share more information about the development concept and about expected rates. I think that would be appropriate and; hopefully, we will have that on the second quarter conference call.

Finally, if I could, John, could you give us some update about JDA second guess [inaudible] and what is the progress over there?

Yeah, absolutely Paul. We are very pleased at the [inaudible] activity of the buyers to discussing the next [inaudible] gas sales. Very collaborative discussions are ongoing between the sellers and the buyers. And I'm optimistic that the fullness of time that will lead to conclusion of additional volumes to move into that market.

Job, are you targeting the Thailand or Malaysian markets for the second guess sales?

Actually it is going to be a combination of both, I think, Paul. As you know, the buyers are represented 50% by the gas purchasing authority in Thailand and 50% in Malaysia, the end disposition of the volumes is really dependent on the buyers and arrangements they might have for use of the gas. I might say while you give me the opportunity by the way that we are currently in the process of tying in the offshore pipeline system to the Chocowalla [ph] platform, that's ongoing, and I would also add additionally that some half of the total offshore pipe lay has now been completed.

Are we still are looking at say in the 3000 [inaudible] time frame that the second gas sales may be activated?

You know, it's difficult to project that far forward given the stage that we are asking the discussions, but I think that our estimate would certainly be at this stage '07, '08, something in that time frame at this time. I would guess that a lot of it too would be dependent on the continued progress on=f the economies in those two -- [inaudible]

Perfect, thank you.

You are welcome.

Your next question comes from Mr. Mark Gillman from the Benchmark Company. Please proceed sir.

Hi Johns, good morning. Just a couple of things if I could. John, could you locate the Shenzi 3 relative to the one and the two and put some numbers on what an extended step that is?

Yeah, I can. It's about 3 kilometers basically west, northwest, over towards the block boundary that's due west.

Three kilometers west, northwest of the one or the two?

Of the two.

John Rielly, I did not hear you mention an ENT tax rate. Could you do so for the quarter and reaffirm any thoughts for the year? Also, did you have sufficient U.S. taxable income to offset the hedging losses in the first quarter.

The ENT tax rate for the quarter was 46% and we are still reaffirming our guidance for the year of a range between 47 and 51%. As far as our hedge losses that we have in the U.S., we do have net operating loss carry forwards available to use against taxable income in the United States and by our projections will use all available tax attributes that we have in the U.S.

So that some of the -- John, some of the losses are the hedge losses in the first quarter, if you will, viewed that way were non-sheltered?

We have -- we take a full benefit for those losses. We book that as a tax benefit and it will be utilized against a domestic income in the United States. So there are no, if you want to say unsheltered losses in the U.S. for us.

Okay. One more if I could please. Could you talk a little bit about what the lifting position was in the first quarter relative to production and where you stood at March 31 internationally.

Yes. For the timing of lifts in the first quarter, if you just looked at our production of 346,000 barrels a day, due to just timing of lifts, our sales volume were a little bit higher than our production. Just over a million barrels were sold higher than our produced volumes. So we really don't have a -- do you want to say a true underlift or overlift position. We do have inventory -- a standard inventory position in various countries. But, we are pretty much breakeven if you want to say in an overlift, underlift situation. But we did have higher sales volume versus production which increased earnings in the $10 million range this quarter.

Okay, but as of March 31, the lifting position is pretty much in balance?

Yes. We do -- there is always inventories that you have in the various countries. But, we are in balance.

Okay, very good. Thanks very much.

Your next question comes from Arjun Murti from Goldman Sachs. Please proceed.

Thank you. Just a follow up on the DD&A comments I think, John Rielly made. You mentioned, I think, 675 a barrel in the favorable mix shift. It would certainly seem that with the Gulf of Mexico shelf properties having been sold that there is some permanence here to this improved 675 number, especially if we believe S&D costs will be better than -- than historic numbers, is that directionally correct?

That is directionally correct. And obviously and again as we continue to bring on lower costs to production, should benefit our unit cost over the next couple of years.

Right, so the 675 could even have upside to extent future developments are even lower cost?

Yes, correct. There are some -- you still have some of the assets that have acquisition costs on them, but for the most part our -- the new assets coming on will be at a lower cost so we will be able to bring down our D&A.

Yeah, and then a follow-up to maybe, John O'Connor, on some of this Seba [ph] NEG comments, you know, I remember when I used to cover United Meridian, which became Ocean, when they first discovered the [inaudible] there was a lot of optimism, then there was some disappointment. But after they figured it all out, you know, over the next five to ten years, that reservoir has over long periods of time continued to surprise the upside as people have figured out the channel sands and how to produce it and optimize the recovery rates. You know, it would seem like EG, which you have gone through the same sort of initially optimistic then disappointing -- you are starting to get your arms around that and while we all want to be conservative and not get ahead of ourselves in the long term upside here seems to be quite significant. Just wondering if you generally agree with those types of comments?

Yeah, I do generally agree with those comments, Arjun. I feel the same way. I'm not sure I would draw a straight analogy between sulfur [ph] and the potential upside here. Because I believe I'm right in recalling that they found additional pods of oil in place, peripheral to the initially developed area of that field. I think we have a pretty good scope on the location of the oil in place. But there is always opportunity for upside. There is no question, however, that with the detailed sub-surface modeling work and understanding that we have experienced over the past year say, that we have certainly enhanced our confidence. I think we have a better recovery model and I do think that there will be upside -- there is potential for upside in the event that the sub-surface plumbing is favorable to us and that we get, if you might say, top [inaudible] type recoveries under water flood. So, if there is that and, obviously, we aren't counting on that right now. We are approaching it conservatively, but if nothing else, just a straightforwardly, on recovery factor I believe is upside.

That's terrific. And then, just lastly, and I don't think there is any change to the -- I can't remember one-"sixish" type Cap Ex number. If you could just confirm that for this year that would be great.

We can confirm that. That with relooking at 1.5 and 1.6 number Cap Ex.

Thats great, thank you very much.

Your next question comes from Mr. Mark Tiddles [ph] of Barkly [ph]. Please proceed sir.

Yeah, good morning, just a couple questions, could you give us an idea what the current second quarter production is running at?

John O'Connor will do that.

Right now it's probably very running very close to the average of the first quarter, frankly.

Oka, and when is the Llano's full production coming online net to Hess?

First of all net to Hess we were looking at 50% Shell operated and Exxon the other partner as John Hess, I think, mentioned in his opening remarks, the initial production is imminent. I would expect that we would see first oil over the next four or five days. It's now imminent. You may recall that this is a two-well development production. We will start from the initial well and will be obviously ramped up carefully. We expect second well to be completed [inaudible] by the end of May and that will then draw on also. We will see careful ramp up of production from those two wells [inaudible].

So second late second half, kind of running full production?

Yeah, I think that's right.

And net to Hess, would that be 15,000 barrels a day?

I think we are presuming that on a run rate for this year we were looking at more on the order of 12,000 barrels a day.

Separately, I was surprised with the weakness of the retail marketing business in the first quarter. Is that just a lag affect given I'm paying $2 a gallon here in New York.

If you bought from Hess you could pay $1.89. I will let that stand where it stands. That's up to you. No, what happens is, as you are well aware, when the commodity markets go up in price, retail is the lagging indicator in terms of profitability and margins were squeezed for the industry. Not just our company. The good news is we have a pretty healthy revenue stream from our sea stores that mitigate most of that. Having said that the reason margins are squeezed simply wholesale goes up faster than retail. Then when prices go down you get the benefit the other way. We are happy to have that as part of our portfolio because of its characteristics in terms of stable cash flow and some resiliency in down markets.

We expect maybe a little bit better numbers here in the second quarter?

Yes. Right now margins are running better than they did at the beginning of the first quarter.

Finally, with the -- if there is excess free cash flow through the balance of the year, what would your priorities be with that excess free cash flow?

We were very happy with the financial cushion and strength that we have. Our whole focus is to use those funds for the developments this year and we have a pretty healthy investment program next year. So the priority is to focus on our developments and execute them. So we can strengthen our financial cash flows in '06. The priorities are the developments.

And just one more, the bank facility, the revolving facility, what's outstanding on that right now at the end of the quarter?

There is nothing outstanding on the revolver. We have $1.5 billion available to us.

And were any -- with the down grades that occurred by Moody's, did that impact any debt or receivables?

The Moody's downgrade, the effect of that we believe on our operations this year will be less than $10 million and that's on a pre-tax basis. And what that basically represents is an increase in our facilities fee, on the revolver that you just spoke about its now at .375% versus prior to that it was at .15%. So you pick up between 3 to $4 million of additional costs on the revolver. The other costs that you just estimate on was that you have to put up more margin on either energy marketing or hedging counter-parties where we have these hedge contracts. So we have to put up more letters of credit so we have increased fees associated with it. That's basically the effect.

Thank you very much.

Your next question comes from Al Anton [ph] from Carl H. [inaudible]. Please proceed sir.

[inaudible] Paul Cheng asked the question I was going to ask about the JDA and you mentioned that you're negotiating possibly further contract. But, you do have 3 or 4 TCF of unbooked available reserves which is quite large compared to what you have already. Are there any other possibility for disposing of those reserves beyond increments of the nature that you have already which is maybe 20 to 25% of your total potential?

We look at this basically and describe it as the base contractor or Phase 1, additional volumes which we are describing as Phase 2 and we recognize that we have additional uncontracted gas should the market opportunity arrive. I think that is the best way to describe it. We are happy to have it by the way.

So it is in pocket for the long-term.

May not necessarily be for the long term. But I am saying it would require a "guestamation" of how the market to demand for natural gas will occur. I would say in that context that with the completion of the major trunk system from the facilities onshore, that I think is going to be significant spur to see additional demand for that gas and that's the key.

Okay, thank you very much.

Your next question comes from Paul Ting from UBS. Please proceed sir.

Two questions please, first of all, your upstream Cap Ex at 352, that seemed to suggest the 1.4-ish kind of upstream Cap Ex could be -- could exceed that this year, especially giving a strong cash flow. Any comment on the potential of the upside of your upstream Cap Ex?

Again, at this point, we are forecasting that our overall Cap Ex is 1.52 to 1.6 with downstream of that a small portion of that. The only thing I really say from a potential upside to that is the potential successful negotiations in Libya and maybe there will be additional capital associated with that. But at this point we are saying 1.5 to 1.6 is in our plan.

So a 95% in upstream that is a good number isn't it?

That's correct. You know, about 50 or so, 50 million is in the downstream the balance is upstream.

Do you have anything with Libya right now within that 1.5, 1.6?

No.

Okay, on the downstream refinery runs at 247 for first quarter is very strong compares to not only last year's, which I guess could be due to Venezuela, but also compared to the historical run rate. Are you -- do you expect to maintain your 247 run rate?

Yes. Excuse me, Paul, but when I talk I'm talking the full interest of 100%, it's easy for me to think that way so if you don't mind, you can handle the 50% when I talk. You know, I said the Hovensa [ph] arena at 499,000 barrels a day. You are absolutely right because of the political problems in Venezuela last year first quarter, we were running at reduced rates as I recall. There were some periods we were running at 300,000 barrels a day. Obviously we are very pleased that the average for Hovensa [ph] in the first quarter was 499,000 barrels a day. It's currently running at similar rates now. In fact a little higher. All the downstream upgrading units are being fully utilized so we have great utilization, full upgrading and very healthy margin. So as a consequence we were benefitting economically and we are very glad to be in the position that we are in.

Great. Thanks a lot.

And your last question comes from Mr. Steven Pfiefer with Merrill Lynch. Please proceed sir.

Sorry about that, I've actually gotten taken care of, thanks.

Thank you. Thank you, everybody. For being on the call today and we look forward to giving you update in our next quarterly conference call.

Ladies and gentlemen, this concludes your presentation. You may now disconnect. Have a great day.