赫斯 (HES) 2002 Q1 法說會逐字稿

This is an unedited realtime transcript. An edited version with proper case and full speaker names will be available shortly.

Good day everyone. Welcome to the a.M. Hess quarterly conference call. Today's presentation will be available for rebroadcast at 4 p.M. Eastern time today rung through may 1st at midnight. 1-719-457-0820. Or 1-888-1112 and enter confirmation code 680897 on your telephone. All media will be in listen-only mode. Media qaes should be directed to carl tursi. At this time for opening remarks and introductions i would lick to turn the call over to the vice president and corporate secretary Mr. Carl karchlt please go ahead, sir.

Hello. This is carl tursi. With me is john O'Connor, president of worldwide exploration, john schreyer, executive vice president and chief financial officer and john riley, vice president and controller. John riley will discuss first quarter results. After which the meeting will be open for questions. Certain forward-looking statements may be discussed during this call. I will turn the call over to john riley.

Thanks, carl. Hello everyone. My remarks will consequence at any rate on our results of operation for the first quarter of 2002 compared with the results for the fourth quarter of last year. Pages 3 and 4 of the press release include an income statement and a summary of operating statistics that contains much of the information to which I will be referring. I will begin with several significant high lights.In march the corporation announced an a-line oil on block g. The discovery encountered 157 feet of net oil bay. In february, we reported the a come oil dpi discovery which was 162 feet of net oil pay. The developments are being evaluated as are development plans for the previously announced discoveries. The fpso was secured in place in the saba field and the corporation's share of production increased to 46 barrels of crude oil per day in march. The field is currently producing in excess of 50,000 barrels per day. That's net to us. In our refining and marketing activities the coker at the hovenza refinery in the virgin islands the 97 percent complete. Construction is expected to be completed in the second quarter. Detective was reducied by $110 million in the quarter. Dividend payments were 53 million.Moving on to exploration and production.Compared with 115 million in the fourth quarter of 2001. For a total net increase of $84 million. Now, I would like to give you information on our hedging activity. The impact of crude oil and u.S. Natural gas productions in 2002 was an after tax benefit of $76 million or $2.31 per boe. Compared with a benefit of 68 million or $1.98 per boe in the fourth quarter of 2001. The status of our hedges at march 31 was as follows. For the remaining 9 months of 2002, we have hedged 46 percent of our crude oil production and 75 percent of our u.S. Natural gas production. For 2003, we have hedged 10 percent of our crude oil production and 55 percent of our u.S. Natural gas production. At march 31, our after tax deferred hedge position was break-even. This is comprised of a $7 million deferred gain relating to the remaining 9 months of 2002 and a $7 million deferred loss for our 2003 hedges. At march 31, we have realized, after tax deferred hedge gains of $54 million. And that's offset by unrealized losses of $54 million. The average price at which wti related crude oil is hedged in the remaining 9 months of 2002 is $24.05. The average price at which u.S. Natural gas is hedged is $3.45. The average price of wti related crude oil hedges in 2003 is $22.75. The average price of the u.S. Natural gas hedges in 2003 is $3.65. Before I continue with the enp discussion, I would like to address the reduction in stockholders' equity from year-end. Since we were profitable in the first quarter, it is reasonable to expect stockholders' equity to increase. However, we had a significant deferred hedge gain at year-end. As always, this gain is included in other comprehensive income which is a part of stockholders' equity on our balance sheet. The change in the deferred gain on the enp hedges from a gain of 2 49d million at year-end to a break-even position at the end of the quarter resulted in a reduction of stockholders' equity during the first quarter. Turning to oil and gas production which is shown on page 4 of the press release. In the first quarter of 2002, crude oil and natural gas liquids production was 324,000 barrels per day compared with 331,000 barrels per day in the fourth quarter of 2001. The decrease in u.K. Production reflected temporary operational issues in the angus, arbroth, and about the itern fields tow at that time yalg 10,000 barrels per day. Natural gas production was 8,013 a decrease of 4 percent from the fourth quarter. Production of oil and gas on a barrel of oil equivalent basis was 460,000 barrels per day, up by 14 percent from last year's first quarter. The same as in the full year 2001. Last week, however, changes were proposed to the u.K. Tax regime on exploration and production operations. Under the proposed changes companies will pay a supplement recharge of 10 percent on profits from their u.K. Oil and gas production in addition to the current 30 percent corporation tax. If the current proposal is enacted, we anticipate recording an one-time noncash charge of approximately $45 million relating to the u.K. Deferred tax rye built on our balance sheet. In addition, if royalties are abolished the annual benefit would be approximately $7 million. Now, moving to downstream results. Refining and marketing results amounted to a net loss of $22 million in the first quarter of 2002 compared with income of $25 million in the fourth quarter last year. The corporation's share of avenza's results amounted to a loss of 26 million in the first quarter compared with a loss of 19 million in the fourth quarter of 2001. The fcc unit at hovenza was shut down in mid march for scheduled maintenance. During startup, problems were encountered and certain equipment was damaged. At present the equipment is being repaired and the fcc unit is expected to be back in operation by the second half of may. We estimate our share of lost margin was approximately $5 million in the first quarter from this shutdown. We anticipate approximately $5 million of repair costs will be expensed. Retail operation had a loss in the first quarter of 2002 compared with income in the fourth quarter. After tax trading results in the first quarter of 2002 were break-even compared with a gain of 19 million in the fourth quarter. As we have discussed previously, cost reduction efforts are under way within refining and marketing, including in energy marketing unit. We anticipate an accrual in refining and marketing for severance in the second quarter and a write-off of certain energy marketing assets. I would like to comment on the variances in several income statement line items in the first quarter compared with the fourth quarter of last year. The pre tax gain of approximately $40 million is included in nonoperating income in the income statement. Marketing expenses decreased in the first quarter compared with the fourth quarter. In addition first quarter costs were lower because of the sale of the u.K. Energy marketing business. The sale of this unit, which was a break-even business will reduce total marketing expenses by approximately $10 million per quarter in the future. This concludes my remarks. I will turn the meeting over to john schreyer for the question period.

Thanks, john. John O'Connor, john riley, carl tursi and I are ready for your questions. Let me ask the operator to give instructions.

If you would like to ask a question press the star key followed by the one on your touch tone phone. To ask a question please press the star key followed by one. We will pause a moment to assemble our question rosters. Our first question from steve five with merrill lynch.

Hi, guys.

Hi, steve.

John O'Connor is there, so I wanted to see if he could update us on the drilling program in eg. Secondly, if you could comment on the gas volumes in the urksz what's going on with the log volumes that like like the volumes in u.S. Gas did decline pretty much from q4. Thanks.

John O'Connor.

Okay. John, thank you. Hi, steve. Happy to answer those questions. We have had the three separate prospect discoveries in eg, as you know. Abano, I think reported in february, acom, and alom. We are currently drilling the next prospect which is titled g9. We would think we will see the objective section in 10 days to two weeks. We have three rigs operating in eg right now. We have just completed gst, went back into ovang 1 the discovery well which had not been tested. We completed a successful test on that well. The third rig has just completed drilling the saban 9 it's dedicated to the saban field. That's the story there. On u.S. Gas, you may or may not recall when we did the conference call at year-end in january that we talked about dropping the rig count in the gulf coast area from six to one because of the unfavorable commodity prices we had at the time. To an extent that's a temporary contribution to the drop in productivity. I would also say that in the first quarter, we have added additional capacity. Last weak for example we put a new facility into britain which is part of the properties acquired. That facility has got 40 million a day capacity and -- we are wrapping up production -- ram pittsburg up production on that now. I think you will see a different set of numbers on that in the fourth quarter.

On the marketing is there may be a number? Looked like backing out trading and backing out hovenza it looked like market was in the red, but very modestly on the red?

You're on r & m now?

Yes on the marketing side. The rest of the r & m business loft more or less $6 million. It's fair to say that the retail business was not profitable in the quarter, as we already mentioned. On the other hand the energy marketing business had a little profitability as did some of the other business units like the refinery at port redding end ships.

Great. Thank you. Operate operate we go next to paul ting with salomon, smith, barney.

Good afternoon.

Hi, paul.

Hi. Question on your production profile. First quarter about 460,000 barrels per day boe. If you're going to reach about 480 for the year, it would imply some fairly significant increase in the rest of the year. Are you still comfortable with that level of production for this year?

Our forecast for the full year was and continues to be 475,000 barrels a day.

Okay.

Yes, we are comfortable with that given the first quarter results.

Okay. And triton will be pretty much on target then?

Yes.

Okay. Is it going to be close to zero or close to four?

John riley has that.

Actually, mentioned in the discussion earlier that we'll actually be paying slightly lower tax this year as a result of the changes in the depreciation rules.

Only slightly, paul. That's fair to say it's in the $10 million range.

Does this change your long-term strategic outlook at all in north sea? It doesn't sound like it's a huge deal but I want to make sure I get that clarified.

As we said before, we are reviewing all our assets because of the great opportunities we have and we want to high grade the existing assets. Obviously we were looking at north sea assets. We already mentioned we sold in the first quarter two small fields there. And actually wrote down a third field that we have for sale there. I guess it's fair to say that it doesn't change anything, but it certainly doesn't improve the prospects of the emp assets as they -- in the u.K. As they rank against other enp assets.

Thanks a lot.

Next argin murtry goldman sachs.

Any change to your cap-x cap-x budget for the rest of the year or any change --

No. Our cap-x budget, as we mentioned is 1,450 billion a tow -- a billion 330 is enp. There is a larger component of cap-x in the first half of the year than the second half of the year. But at the moment that's the way the program lays out and we are sticking with it.

Okay. You mention you are adding some capacity in u.S. Gas will you ramp that rig back up from one rig to something higher or not?

We'll let john O'Connor talk to that.

I don't think that you would expect to see an overall ramp up in u.S. Cost production. I think what you would see is a modest inning crease and holding stable through the year offsetting the underlying field declines. We are ex setting rig contracts that we otherwise might have dropped. And that's really the extent of the impact of the price on our program.

That's great. I apologize. One more question. The disclosure on the u.K. Tax is very helpful.

That's correct.

Well, no.

Great. Thank you very much.

Next matthew war burton ubs.

Good morning everybody. Just a couple of quick questions. On pdvsa that pgs ex is spec taigs of a distribution from hovenza later this year.Noted on the balance sheet some fairly substantial moves on the assets and liabilities. I was wondering if you could give us some details on those moves.

As to hovenza we anticipated for the year some distributions. Those distributions were contingent on bond financing to take out some of the bank financing we now have in place. We have been working on that bond financing.So we haven't got the bond financing in place. We are are still working on it. Absent that bond financing, distributions this year are likely to be minimal because we will be using the money to finish the coker.

So safe to assume probably for the time cannot to put a distribution until you get clarification on the bond?

That's what we are doing on the hess side.

All right. On the movements on the balance sheet?

Well, first thing that happens on the balance sheet is at year-end we are at a high point because of the winter in terms of receivables and payables. They come down over the first quarter. Now, that has a lot to do with our r & m business. Another thing that's changed the balance sheet is the sale of the energy marketing business in the u.K.. They had substantial assets and liabilities, I believe in the $300 million range. And those are now gone with the sale.

Right. Okay. Thank you very much.

We go next to michael young with jerard klauer.

Hi, mike.

Couple questions. Starting with the u.K. Tax situation. What is your understanding as to when that actually may be implemented, number one? Two would it be remember tro active to the beginning of the year? Three, what is the likelihood that it is actually implemented? Is there a chance that this is just a proposal that actually is changed down the road?

John heilly.

The first question is when do we believe it would be enacted? That the process that we think they need to go through, i don't think that the formal enactment would happen until july. So we are thinking it would be a third quarter item. But obviously that may change. It's not -- if it becomes an active, it does not go back to the beginning of the year. It goes back to the date of the budget presentation which was april 17th. So it's effective as of april 17th and a go forward from there. Effectively, it would impact companies for the 9 months of 2002. And then, as to your last question as far as likelihood, I think we believe that there's a good likelihood that this will be enacted. Obviously there's some discussions from other oil companies that they want to have with the government. From an early look at it, we do believe there's a high chance this will be enacted.

Excellent. I appreciate that.

That's right. If it is in july, we'll take the write down in the third quarter. If it happens to be moved to june it would be a second quarter item. That's when we would recognize the impact.

Understood. Two technical questions. One is the ddna number in the first quarter a clean number? Or john schreyer, I believe mentioned there might have been an u.K. Asset writedown. I'm assuming that might be flowing through the number.

No. It is a clean number. As a matter of fact, if you extend it, you'll see you get about the billion 250 of ddna that we are forecasting for the full year.So we sold energy marketing, we sold two u.K. Fields. They all had gains. We wrote down a third u.K. Field which had a loss.

I see. Perfect. Perfect.

In a second I will give you.

Thank you.

We go next to paul chang with lehman brothers.

Hey, guys.

Hi, paul.

Several quick questions. First on the hovanza, the contract on the joint venture with pedovesa on the crude spray is that in any way impacted by the crude oil quarter?

It has not been.

Or would that be subject to in the future? Or that have the grandfather?

We have no reason to believe that the mesa supply contract would be affected by the opec quota. There is a notice, as you know to all companies that heavy crude contracts may be impacted. At the moment we have no reason to believe that they won't deliver what was anticipated to deliver under the heavy crude contract.

When the coker actually, it should computed in the second quarter or when the first crude delivery is going to start?

Our best guess is there will be mechanical completion in the second quarter and crude might be going through it very early in the third quarter.

Early third quarter. Okay. And also, I think this is for O'Connor. John, wondering if you can give us a number, break down by quarter what is the eg and the u.S. Natural gas production may look like for the remainder of this year?

Yeah, sure, paul. If we look at the u.S. Gas, it probably on average quarter by quarter would run close to or a shade under 4 --

We actually expect the production will be slightly higher from the first quarter level?

Yes. Exactly.

And that's assuming how many rigs that you are running? Basically working on the analog properties, we have one to two rigs in the main pass briton sound area.

How about in eg?

In eg, as john said earlier, we are running right now at a gross production level of 74,000 barrels a day of oil. It's stable, flat, predictable, so around 50,000 barrels a day, perhaps a shade over. We expect to see that average for the second quarter and on into the third quarter. Then a kick-up in the fourth quarter as we tie in the three production wells I alluded to earlier. At that stage we will probably be running at the top end of a 5, 56,000 barrels a day in the fourth quarter.

Okay. Perfect. And also, I think this one is for the accounting. Because in the past, the first exploration well whether it is a success or not you tend to write it off. Have we changed that ultra conservative policy into a more common one like the rest of the industry?

Good question. Let me explain it this way.Seismic was $10 million. The other, which is the processing and the g&a were $16 million. Each of those three numbers, if extended by a multiple of four, for four quarters is about where we estimate we will be for the full year. On the other hand $17 million in the first quarter for dry hole. At the moment in our overall exploration budget for the year of just under 300 million, we would anticipate that number to be 128 million for the year.Let me explain the components of that as follows. We had a number of dry holes, six of them. The tier well, high island, an indo nearby yan well, beech-nut in the u.K.. The total of those dry holes was $17 million. We recap tale liszed them. We had one other successful well in indo nearby yeah for half a million dollars. The total of those wells that we recap tale lized was $28 million.Then there was one additional well drilled in the first quarter. That was $16 million. If that well is successful, under our policy, we would have recap taleized it in the second quarter. That has given us great pause. We were concerned about a first quarter where we were ahead of first call, expensing a $16 million well and if successful kree captalizing it in the first quarter. We will suspend them. We will make, at the conclusion of the well, the same decision we were making before. The same hard decision, what is the chance of an economic development here? And we'll look very carefully at that. If we feel the chance is high, we will leave the well capitalized. So the $16 million of the devil island well, because it is not clear yet that that won't be a successful well, is, indeed suspended and therefore not expensed. So if you add those numbers up, you get to the 60 million. I mean there were 17 million of true dry holes. There were 28 million of drew successes and the devil's island well remains to be seen.

John, is it fair to say that that is a slightly different policy than it was in the past? Because in the past even if the well is successful, if it is on a new area, different zone it would be written off. Now that you will make a decision based on the liability of that well if you believe that if the well is going to be economic, even though it may be in a new region, you will still capitalize it, right?

That's fair to say, paul with the following two caveats. We would have, if we thought a well that had been expensed was likely to be an economic development, recaptalized, it. We would have been switching from quarter to quarter. Secondly, just to be sure this wasn't a big deal, we went back and looked at wells for the last year. There are probably, at most, three wells that we might have capitalized and the total of that is under $10 million. So yes, there is a slight switch in the timing of the decision here. We still think it is the same conservative approach that we had before.

Okay. Very good. Thank you.

We go next on mark gillman with first albany.

Gentlemen, good afternoon.

Hi, mark.

Question on the saibl water flood to john O'Connor. John, when might it being reasonable for you to be able to evaluate the performance of the reservoir under water flood?

Good question, mark. Let me just say with respect to the water flood that so far mek cli it's performing very well. We are getting the volumes a way into the reservoir. I mentioned earlier we just completed a third injek tore. Next week the next seven to 10 days we expect to see the volumes ramp up to 50,000 barrels a day water injection. I also mentioned the field has been producing in a very stable condition at 74,000 barrels a day for the past three or four weeks. All indications are very encouraging, frankly. But with respect to seeing real reaction in the reservoir, I would be inclined to look towards the fourth quarter. We have got a comprehensive sim lateor of the sabre field of the final stages of tweaking, and we are getting some very good matches on performance. I think real lift cli in a reservoir of this size, i would want to see some more production, some more injection history before i would say that, you know, we had a true predictable model situation. So I would say fourth quarter.

Okay. So in essence, then, john the uptick in volumes that you are talking about is just the impact of the additional development wells coming on?

That's exactly right, mark.

Um' -- I'll get you that. There's hardly any production at the moment. A thousand barrels a -- a thousand barrels a day.

That's good enough. John, any reason there?

Okay. I guess I have a little bit difficulty getting to the 44 percent number with the enp number.

That is what it is. When the downstream loses money because it's -- we get no tax benefit for that loss. And so you need to take that out of the calculation. If you do, you get exactly to the 44 percent. So it's a net change of four.

Okay, john, thanks very much.

You bet.

We go next to fidel gate with fawn stalk and company.

Good afternoon, gentlemen. I have a few questions.

Actually, fidel, it's not our policy to go into those details field by field. We were promised it it was going to be separated so we know how good this acquisition went.

And we will tell you the following. We have said before that in connection with triton the ddna rate as a whole was about $7.20. Plus $1.50 of tax gross. That is about what the rate is in eg, and in columbia when you take account of the acquisition costs. There hasn't -- that's what we thought it would be. That's what it has been. The only change in that rate would come from something like the capitalization of the top sides of the ship, which we bought, would increase that rate a little bit.

Because we were under the impression the dna was much lower. That's all right. My second question again on eg, have you detected any pro noinsed trend in terms of drilling cost, what do you see higher costs for well? Lower cost? You gain more experience, obviously, you know the world better now.

I'll let john O'Connor talk to that.

Hi, how are you?

Good.

Good. I would say that there are no particularly pronounced trends. We have found in the past that we have excellent drilling experience in eg, and it's relatively benign environment. Water depths are not great. The targets are relatively shallow. We have had excellent performance from the units we have working there. Structurally in hess enp we have a single global drilling organization. We will be bringing additional knowledge to bear to the extent that that will work towards reducing costs. For example we are looking into batch drilling in eg as we go through the rest of the year. We have four wells to drill. We may drill them all in a row and complete them all in a row. We are looking at trying to drive down the cost. It is not that readly achieveable because of the drilling efficiency has been high in eg all along.

Okay. Then switching gear into the balance sheet.

Okay.

We are at the budget level, a billion 450 for the corporation as a whole, 1,330 for enp.

Thank you.

Fidel, there may be some question about the numbers i gave you for triton, ddna. If there is, I'll repeat it. The ddna cost, that is the number going through ddna is roughly what we said it would be from the get go, $8.70. And so 1.50 -- I'm sorry it's $1.50. That gets you back to aeffective ddna rate of 7.20. Which is where we have been all along and that's how it's working out.

But this ddna shouldn't it come down as your success to expand the --

That is an excellent point. In our models, we spread the acquisition cost over 455 million barrels. At the time, as you know there are about 290 million barrels of reserves. Obviously we are adding reserves and we will soon be at a point where we have covered all the acquisition costs and barrels after that will bear no acquisition cost.

So it will bring down your ddna very sharply?

It will bring down our ddna. This obviously means we have to produce thousand 455 million barrels.We will get a reasonable return then. But once we are passed those 455, we will get a seriously better return.

Just means the john O'Connor has to work harder.

He's done a great job so far.

Okay. Good luck.

Thank you.

Is there a next question?

We go next to mark flanery with credit suisse first boston.

Hi. Good afternoon.

Hi.

My question is really a bit more on the philosophical side. Both on the downstream and on the upstream. In terms of asset rejigging, that kind of thing. Are you done now, completely on the downstream following the sale of the u.K. Energy business, or have you got more to go? Would you like to continue reshaping that business? And on the upstream, I would say we are talking about a high grading process which seems to have started now at least in the u.K. North sea. Can you give us, you or john O'Connor, even, give us a broad outline of how much of the current portfolio you would say is suitable upstream for high grading type dispose yals?

Let me start, mark, by saying that the u.K. Energy marketing business is always seen as part of the upstream business. The downstream business we have said that we will continually look at the asset base there. And if we can find assets that are more valuable in somebody else's hands than they are in ours, we well may sell them. We are continuing to look in that direction. So there could be some additional asset rationalization in the downstream. As to the upstream, it is a broad fill coughic question. We have had we are going to continually high grade the portfolio. You have seen the start of it. There's no reason to believe we won't do more. But there's not much more we can say about it. Although I will allow john O'Connor, if he wishes, to elaborate.

Hi, mark.

Hi, john.

Certainly fill sof cli, i think there is a good deal of opportunity to high grade the portfolio. And the consequence is evident because that's a low cost, highly effective grouping of producing assets. There's opportunity to do so. We are in the final stage jess of evaluating and putting together a program. This will not be a crash program, there's no need for that. We will have a gradual program of continual high grading of the producing assets.

Great. Okay. Thanks.

You're welcome.

We go next to fred leufer with bear stearns.

Good afternoon. John, most of my questions were answered. But let me just ask, do you think you'll get to the 455 million barrel threshold by the end of this year?

I don't know. I mean, john O'Connor, do you want to say? We are obviously making very, very good progress. How many of those barrels will be in the proved column by the end of the year remains to be seen, I would say.

You think you have a shot at it?

I think we are doing very well.

It's really not so much a resource establishment question as it is a technical question of how much we develop and how much the reserve auditors allow us to book. The question of booked reserves. In terms of resources, we are there and beyond.

Okay. John riley mentioned something about severance charges in refining and marketing i didn't get. Can you repeat that, please?

Yes. What john riley said was that we are going through a cost reduction effort in refining and marketing. And in the second quarter we will have an accrual for severance charges and, in connection with that, we will deal with some intangible assets that are a part of our downstream energy marketing business and write them off, too.

And can you quantify that?

The total of that should be in the $25 million range.

Okay. Thank you, john.

Mmmm-hmmm.

After tax by the way. $25 million after tax.

Thank you.

I think that may be the last question, is it not? Another question?

Final question from steve inger with petrie park man.

We can do two more.

Hi, guys.

Hi, steve.

Couple of things probably for john O'Connor. Where is the g9 well in eg from some of the other discoveries? And secondly, can you highlight for us some of the important frontier exploration that you have planned for the balance of this year?

Yes, sure, steve. The g9 well is about 1 1/2 miles south -- I would say south, southeast of the g8 discovery. And interesting because of that. So it's nearby. It's in the same play fairway that contained the other g block. What we call the northern g block discoveries. With respect to the program for the rest of the year, i would say that we have another g block welcoming up in eg after this one. The g10. Then after that we shift out of this current play fairway into the southern play fwair fairway initially and into another play fairway into block f. We are going to go back to blank wild catting in blocks f and g in the second half of this year. That's something exciting to look forward to. We also spun a wild cat in north central north sea called barbara. Those two are interesting. At this stage, I cannot think of -- there will also be while not a wild cat, but a follow-up appraisal well to the marjoon wild cat last year in the pharoah's area. We have at well called cambo which is in the same area but on a separate prospect. We are concentrating on impact wild cats, and that's the flavor of what we can look forward to for the rest of the year.

Okay. That marjoon follow-up is that bedlington on the north side?

No. It's not. I'm not sure if it has a name apart from farrow's follow-up or --

Something clever like that?

Yes.

What's the timing on spud of that?

We are currently looking at mid-june. That's a critical question. A good question. Because we did not get a test off on marjoon because the weather situation deteriorated because of the winter in the north sea. We hoped to spud this well earer, but the contract is secured from another operator who is running behind in their program. So it's something we are watching very carefully. I don't think we can allow this to go passed the middle of june. Equipment availability is the key issue there.

One quick follow-up on eg. John, what can you tell us about the difference in plate types and gee logic risk as you move away from the area where you have had so much success to different areas? What are your thoughts on that?

Obviously the probabilities of success from the plate that we were playing or have been playing and are playing, the problths increased with each succeeding discovery. As we step away from that fairway, I think we are going to go back to I won't say significantly higher risk. It will be partially the same play, but partially a deeper play. A combination of risks. I have always said I think if we are going to explore these blocks properly, we will have to expect to find dry holes. I'm not saying that the program for the rest of this year will be like that. But certainly we'll carry significantly greater risk in drilling where we are currently drilling.

If I understand you right, not maybe true frontier wild catting in terms of chance factors, some carry-over elements from some of the successes you have had in eg, but different enough to be in a different regime in terms of chance factor?

Very well described. Very well characterized.

Thanks.

Sure.

Next sammy horbison. Harbison advisors.

Hello.

Hi, stand.

I guess I got the last one.

No we'll take one more after yours.

I know you put the bite aside at the end. That's all right. Better questions come at the end, you know as the mature people... I had a question, actually about the l log situation the drilling the variability of the drilling program coupled with the fact that you have had a fairly aggressive and pretty successful hedging program on gas. I would have thought you would have wanted to ex sploit the difference between falling rig rates and fairly decent gas price sort of hedged for a good part of that production. Is that the way you are trying to look at it? If so, how come it sounds as if you haven't done it?

Actually, stand, I think it's fair to say that we can realize the hedge benefit on other gas when the prices are down which is harder to shut in, which we are doing. Then when the prices come back, go back to the gas that is easy to get at and low cost. And I think increase our returns over all.

Okay. And that would suggest that, you know, the margin there is -- gets tough at 2.50, or 2.75. If you are hedged at a higher rate, you would be able to widen the margin by virtue of the rigs being unemployed. Doesn't sound like that's the --

I think it depends on the position you are in, in terms of how many hedges you have on and what you can use the hedges to do. Our position makes us think the best answer for us overall is take the hedge money now, shut in this gas which has good margin on it and get to that gas when prices go back up.

John O'Connor.

I think that's right, stand.

Any activity yet planned in any of the jda situations?

Right.

The good news there is that we are seeing reservoir performance from our activities there which is better than we expected. So that holds out some significance for the future. We can adjust the program to accommodate that. So I think that's an interesting story and one with some potential significance.

Right. That is block a-18 in that joint development area. Very significant gas resource. 3 p basis probably getting close to 10 tcf.

Right.

On the ground what's happening is that we are currently installing the production facilities in the field capable of producing for phase one. We have been advised that a decision will be made on proceeding with those facilities by the end of this month. So we are waiting. If that's the case we would look to first production in first quarter of 2004.

My recollection from the tryton history was that many of those wells were quite prolific producers.

That's correct.

But also in some cases needed a lot of sulfur.

Yes. Co2 that's why we need the treating facility.

Okay. Good. Thank you.

Next chris malone with dresdner.

Good afternoon.

Hi, chris.

Hi, how are you? One quick final question. Forgive me if it has been answered. I got dropped off the line for a few minutes. As you have in the past I was wondering if you could discuss this quarter's company-wide kind of all end enp cost per barrel and kind of your forward comments. Last quarters conference you were talking about 14.25 per barrel. I'm wondering if that -- and or your reduced drilling in the u.S. ?

John riley will deal with this.

Hi, chris. Our unit cost for the first quarter of 2002 were $13.53. Our target for the year is $14 right now. Basically in a $7 range for ddna $5 in the production area, 1.50 in the ex plo reigns area and 50 cents for gna.

Very good. Thanks.

Okay. I think that is our last question.