赫斯 (HES) 2005 Q2 法說會逐字稿

Good day, Ladies and Gentlemen, welcome to the second quarter 2005 Amerada Hess earnings conference call. [ Operator Instructions ] I would now like to turn the presentation over to your host for today's call, Mr. Jay Wilson Vice President Investor Relations. Please proceed, sir.

Thank you, Kelly. Good morning to everyone and welcome to our second quarter conference call.

With me today are John Hess, our Chairman and Chief Executive Officer, John O'Connor, President of Worldwide Exploration and Production, and John Rielly, our Chief Financial Officer. I would now like to turn the call over to John Hess.

Thank you, Jay, and welcome to our second quarter conference call. I would like to make a few comments, after which John O'Connor will discuss our exploration program for the balance of the year. John Rielly will then review the financial results for the quarter.

Turning first to exploration production. Our second quarter production averaged 355,000 barrels of oil equivalent per day up about 1% over the year ago quarter. Strong operating performance from our existing assets new production from the JDA, Clairfield and Russia all contributed to these results. At the end of March, we announced the acquisition of a controlling interest in Samara-Nafta, a company operating in the Volga-Urals region of Russia. Since then our Russian venture has acquired three additional licenses in the Volga-Urals region increasing our investment to approximately $200 million. Production from Russia averaged 7,000 barrels per day in the second quarter.

July 19 we announced an agreement signed for the sale of gas from the Phu Horm field located on shore in northeast Thailand. Amerada Hess is the operator with a 35% interest. First gas is expected to be delivered by early 2007, at an initial gross rate of approximately 80 million cubic feet per day increasing gradually to a rate of approximately 100 million cubic feet per day. We are steadily building a significant position in the southeast Asia gas market and this development is a positive addition to our portfolio. For 2005, our current production forecast is 350,000 to 360,000 barrels of oil equivalent per day, excluding any contribution from Libya.

We continue to believe that reentry into our Oasis Concession will happen, however, the timing of our return is difficult to predict. With regard to refining and marketing, our operations performed well during the quarter. The Hovensa joint venture refinery operated at full capacity and benefited from a strong margin environment. While our retail marketing business posted same store gasoline volumes which were 8% higher than last year, and convenience store sales which were 3% higher, income was negatively impacted by lower retail gasoline margins, resulting from the run-up in wholesale prices during the quarter.

Effective June 1, our Wilco-Hess joint venture acquired 102 retail outlets in eastern North Carolina. The acquisition which was financed solely by the joint venture has solidified our competitive position in North Carolina, where we have 233 sites and has increased the total number of Hess branded retail outlets to about 1,355. Earlier this month, Hess LNG, a 50/50 joint venture between Amerada Hess and partners received approval from the Federal Energy Regulatory Commission to proceed with a Weaver's code L and G regasification terminal in Fall River, Massachusetts. While additional federal, state and local permits are required the receipt of the FERC certificate is an important milestone. The facility is designed for base load send out capacity of 400 million cubic feet per day.

Our current estimate of 2005 capital and exploratory expenditures is $2.4 billion to $2.6 billion. This level of spending is up from our previous forecast of $2.1 billion and is opportunity-driven. Our investment in Russia accounts for, approximately, 200 million of the increase with a balance coming from additional opportunities in our portfolio. I will now turn the call over to John O'Connor.

Thanks very much, John and good morning. We have an active exploration and appraisal drilling program planned for the second half of 2005. We're currently drilling a wild cat well offshore Gabon and we're participating in a well on Block 64 in Peru. Results of both of these wells are expected before the end of the third quarter. In addition, we plan to drill approximately eight appraisal wells at the Malaysia-Thailand Joint Development Area over the remainder of 2005, which are designed to prove up reserves in support of both Phase II and Phase III developments. In the Gulf of Mexico we'll participate in four exploration wells in the second half of 2005, including a well as at our Pony Prospect on Green Canyon 468. This block is to the north of the and is contiguous with the Nexen operated Green Canyon Block 512, on which they and the partners are currently drilling the Knotty Head prospect.

Reported results from that well appear encouraging and we believe that the same structure extends on to our blocks, pending the drilling outcome of Pony. We intend to drill our prospect with 100% working interest. In addition to Pony we plan to participate in the drilling of two lower miocene prospects in the Green Canyon area, Ouachita (PH) where AHC will have 66% interest and Turtle Lake where we will have 25% interest or so. As well as a prospect named Barossa, where we will have 100% interest, and Garden Banks 158, which will target natural gas reserves in the pliocene. Rigs have been contracted for all of our drilling needs for the balance of 2005, as well as the majority of the 2006 program. With regard to our Shenzi and Tubular Bells discoveries, in the deep water Gulf of Mexico, Shenzi is now appraised and we're working with our partners to sanction the development before the end of 2005. As for Tubular Bells, the operator advises that we will have an appraisal well on that prospect in the first quarter 2006.

Exploration expense for 2005 is forecast to range between $425 million and $475 million, compared to $287 million in 2004. The increase reflects the carryover effect of expenses the Wembley and Diamondback wells in 2005 together with an expanded drilling program at the JDA. Now, over to John Rielly.

Thanks, John. Hello, everyone. Our earnings release was issued this morning and it appears on our website. In my remarks today, I will compare second quarter 2005 results to the first quarter. Net income for the second quarter of 2005 was $299 million, compared with $219 million in the first quarter. Exploration and production income from exploration and production operations was $263 million in the second quarter of 2005, the same as in the first quarter. Second quarter earnings include income tax benefits of $11 million, reflecting the effect on deferred income taxes of a tax rate reduction in Denmark and tax settlement in the United Kingdom.

First quarter earnings include nonrecurring income of $22 million, from an asset exchange and a legal settlement. Excluding these items, E&P earnings were $252 million in the second quarter compared with $241 million in the first quarter. The after tax components of the increase are as follows: exploration expenses were lower which increased earnings by $27 million. Increases in other E&P costs decreased earnings by $17 million. All other items net to an increase of $1 million for an overall increase in second quarter adjusted income of $11 million. The affective income tax rate on exploration and production earnings for the first half 2005 was 41%.

The full year 2005 effective income tax rate will be, approximately 43 to 45%. The after tax impact of crude oil hedges reduced second quarter 2005 earnings by $231 million, compared with a cost of $195 million in the first quarter. The press release provides details on the portion of our future production that is hedged and the related contract prices. The after-tax deferred hedge loss included in accumulated other comprehensive income at June 30, 2005 amounted to $1.7 billion. Of this amount $93 million was realized. As John has stated earlier, our current production forecast for 2005 is 350,000 to 360,000 barrels per day. Due to seasonal maintenance we anticipate that third quarter production will be approximately 330,000 to 340,000 barrels per day, while fourth quarter production will be approximately 365,000 to 375,000 barrels per day.

Turning to refining and marketing. Refining and marketing earnings were $98 million in the second quarter of 2005, compared with $63 million in the first quarter. Refining earnings consisting of Hovensa and Port Reading operations, interest income on the PDVSA note and other miscellaneous items were $77 million in the second quarter of 2005 compared with $42 million in the first quarter. The Corporation's share of Hovensa's income after income taxes of $42 million was $66 million in the second quarter compared with $31 million in the first quarter. Port Reading earnings were $7 million in both the second and first quarters of 2005. After tax interest income on the PDVSA note amounted to $3 million in the second quarter and $4 million in the first quarter. The balance of the PDVSA note at June 30, was $243 million and principle and interest payments are current.

Marketing earnings were $14 million in the second quarter of 2005, compared with $13 million in the first quarter. Retail operations were slightly profitable in the second quarter of 2005, compared with a loss in the first quarter. Earnings from energy marketing activities were lower in the second quarter, reflecting seasonal factors. After tax trading results amounted to income of $7 million in the second quarter of 2005, compared with income of $8 million in the first quarter.

Turning to corporate. Net corporate expenses amounted to $28 million in the second quarter of 2005, the second quarter results include $7 million, after tax, for premiums on bond repurchases. First quarter net corporation expenses were $69 million including an income tax provision of $41 million relating to the repatriation of the foreign earnings to the United States, under the America Jobs Creation Act of 2004. Turning to cash flow. Net cash provided by operating activities in the second quarter, including an increase of $170 million from changes in working capital, was $606 million. The principle uses of cash were as follows: Capital expenditures amounted to $493 million. All other uses of cash amounted to $41 million.

We had a net increase in cash and short-term investments in the second quarter of $72 million. At June 30, 2005, we had $916 million of cash and short-term investments. Our available revolving credit capacity was approximately $2.1 billion at quarter end. The Corporation had debt maturities of only $1 million during the remainder of 2005, and $78 million in 2006. This concludes my remarks. We will be happy to answer any questions. l'll now turn the call over to the operator.

[Operator instructions ] Your first question comes from the line of Steven Enger of Petrie Parkman. Please proceed.

Good morning.

Good morning, Steve.

Couple of things, on production, on the third quarter expectation, do you have or can you quantify how much hurricane or other storm impacts you may be incorporating in that third quarter estimate?

Steve we really don't have any real major impact from storms in the third quarter. It is really just a matter of seasonal maintenance in the U.K. North Sea that drives the third quarter production down.

Okay. So it's really just planned down time?

Correct.

And in 4Q can you make comments on the large increment in production going from Q3 to Q4? I've got some increase, but not to the level that you guys are expecting.

The primary increase, obviously, will pick back up from the seasonal maintenance, but it's also the JDA coming on full production after the gas plant is completed in Southern Thailand so we're getting up to our 390 million cubic feet per day in the fourth quarter for JDA.

And you're assuming you'll have that essentially all of the fourth quarter, then?

Correct.

Okay. and, then, for John O'Connor, on the Pony Well, what's been reported is positive results in a secondary objective. Do you basically see the secondary objectives and the primary objectives extending on to your block; thus, do you basically see this as, as one large structure? Set of structures?

I think there's probably two questions there, Steve, for one, but, it is difficult for me to say what might be in the adjacent blocks. What we do know is what we see on the block we call the Pony Prospect and reported results so far, on what we a also could consider to be a secondary objective.

Okay. I get the essence of it. John, do you see that target extending onto your block as well? Sounds like the answer is yes?

I'm not sure if I'm addressing your question but I would say again -- our primary targets have not been tested yet in the Knotty Head well.

Okay, and then can you give us any additional commentary on Libya, in terms of what the issues may be and any sense of when that may be concluded for reentry?

Yeah. The ball is in the Libyan’s court. Between May of last year and December, we negotiated with the National Oil Company, now it's at the government approval level and the government is mulling over the different positions and will be reverting back to us. Dialogue is ongoing.

Okay. So you're basically done with the negotiations with the NOC and government?

With the NOC yes. We're awaiting direction from the government.

Great. Thank you.

Your next question is from the line of Mark Flannery of Credit Suisse First Boston.

Hi, there. I've got a follow-up on Pony there for John O'Connor. When are you going to start drilling there? And do you have a rig in place to do that yet? Or are you still looking for one?

Hi, Mark. Yes, we actually have a rig contracted, it's the Ocean Baroness It's to be mobilized in the Gulf for us. The first well it will drill for us will be Pony and we expect a spot at the beginning of November. The well should take about 100 days. The location is in 3,200 feet of water and the prognosis, currently, is for a TD of 31,000 feet.

Great. Okay. I have a site follow-up question on CapEx. Which is, CapEx is going up between $3 million and $500 million, something like that. You said $200 million of that is from Russia, the rest in the portfolio. Can you characterize what type of things you're spending that extra money on? And should we think of this as new opportunities or cost inflation? How does this split go between those two things?

Mark, it really is scope changes due to opportunities that we see in the portfolio. And I think you remember John O'Connor mentioned that we will be doing additional appraisal drilling at JDA for our Phase II and Phase III developments. So really with Russia and this increased drilling at JDA that is the bulk of the increase and then there are a few other exportation opportunities that we saw in the portfolio that were value-creating and we put it in our CapEx program for this year.

Okay. But they are, that last thing, the exploitation opportunities is small, against Russia and JDA, is that correct?

Correct.

Great, thank you very much.

You're welcome.

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

Thank you, I think, too, maybe, John O'Connor, you alluded to the Shenzi development likely getting sanctioned. Any rough update in terms of timing and what volumes may look like from the development and maybe the same thing for Tubular Bells?

The second first. For Tubular Bells we're clearly going to have to await the results of the appraisal well which, BP the operator, currently plan to build in the first quarter of next year and I think that's proceeding at a stately pace, you might say. As to Shenzi, we are just about to receive from the operator the proposed plan of development which we will then scrutinize, and go over and work through our own approval processes and expect the final investment decision to be made the fourth quarter. Until we've had an opportunity to do that due diligence, Arjun, it's premature to talk about timing or volumes, and so forth.

I guess I'd imagined oh, some typical two or three year development time frame?

That's my assumption, yes I think that's the right range to look at.

Any update on Bellud? I know you were drilling wells there.

We had a discovery last year in Malaysia?

We have a follow-up well planned for the back end of this year, probably sputter around December I believe.

Terrific. In response to the CapEx question, most companies are experiencing oil service and steel cost inflation as the reason why they've changed their budgets. Did you just plan for that better at the beginning of the year do you think? Or is there some reason you're not feeling the inflation effects that others may?

It really is Arjun, that it is scope changes from the CapEx budget from the beginning of the year. Our budget, you could say, if we did a nice job of it, I mean, right now, all of our big development projects say, Okume Complex, is right on budget. We are clearly experiencing the cost pressures that others in the industry are experiencing, but we did have that in our budget so, right now all the additional opportunities are really just changes in scope from our program.

That's great. Thank you very much.

Just supplement to that, Arjun, I think that that's certainly the case with respect to the capital program. In many cases we had the rigs secured. We've done a good job in value engineering for the major projects and as John said, all the major projects are basically spot on with some pluses and minuses. We're seeing some plus on the drilling services side and maybe minuses in some other areas. I think where we do see oil field cost pressures coming through is in run-up costs and these contribute somewhat to the pressures we see of lifting costs around the world.

Got you. Thank you.

Your next question comes from Doug Leggate of Smith Barney.

Good morning.

Good morning.

We're about half way through the year now. I just wonder if you could give us some thoughts on how you see potential reserve replacement for this year? Really what I'm looking for is a little color on the projects you've already sanctioned, how much of the reserves yet have you already booked? and I guess Shenzi, is there any potential that we might see you book -- at least partially some of that field this year?

Doug it is premature to try to quantify the full year reserves. As you know, most of the detail, as it were, in engineering work occurs in the second half of the year; and in point in fact, in most cases in the fourth quarter. We surely expect that assuming that the boards of the partner companies, for Shenzi approve the investment that we will book proved reserves associated with that sanction. We will certainly book reserves associated with the Phu Horm development being sanctioned, and at a number of other areas where we can see reserves coming through, but it would be misleading to try to quantify the total reserve placement. But I would say that our expectation would be that somewhere in the $10 to $12 dollar a barrel F&D cost would guide us towards the type of reserve replacement we ought to see and then it's dependent on where the E&P capital program comes out of that $2.1, $2.2, $2.3 something like that. Well, rough guides but way too early to forecast specific reserve outs.

Is it safe to say that the current exploration program has no real bearing on the exploration of the reserve replacement over the next two or three years?

It depends on where you’re talking about the exploration program. If it's the Gulf of Mexico that might be appropriate; if it's other places it may be possible to develop projects to sanction quicker and at sanction we would book the reserves. So, I think it's a smorgasbord. You have to be careful about where you're talking about with respect to the exploration, but as a generalization, that's accurate, however.

One final, follow-up on Pony I'm afraid. I'm not sure if it was you, John, or if I heard it elsewhere, but I think you had -- there's been some discussion that the Knotty Head prospect or the prospect that's shared between the two blocks, around 50% - 60% is believed to be in your block, would you agree with that?

I have no idea. I don't know where -- it didn't come from me, I can say that. I really think we've got to wait until we see the drilling results from Knotty Head and of course we're enthused at the success that the Group on Knotty Head are having. Next step obviously is to wait until the well gets to TD and see what the partners there say, but really what we have to do is wait until we get our prospect to TD and that's going to be early in 2006. So, we're looking forward to that result.

Great. Thanks very much.

Next question from the line of Paul Sankey of Deutsche Bank.

Hi, good morning gentlemen.

Good morning.

Good morning, Paul.

Gentlemen, if I could ask you a very high level question, given the number of questions about the Gulf of Mexico, there's been quite a lot of water under the bridge, I guess, since we last spoke, in terms of what you've learned about the Gulf of Mexico. Has your -- I mean you've had two significant dry holes, I guess, and others major discoveries. Has your view changed or has it been changing over the past six months to a year in terms of what you learned? And if you could put it in a global context as well I'd be interested.

In a global context I would say most explorationists would argue that the deep Gulf of Mexico continues to be the most attractive exploration play in the world. I'm not quite sure what might compete with it at this time. So, in terms of global opportunities, that -- we certainly believe the place to be and we think other professional explorers would say the same thing. As to our prospective on the Gulf of Mexico, for our company, we continue to learn every time we drilled a well, whether successful or not, you add to your store of knowledge and this is high technology and it's about extensive seismic processing and it's about creativity and imagination. We continue to improve across the board on these aspects and we continue to be very enthusiastic, and you can see that we're basically putting our money where our mouth is, with the program we have for the rest of the year and into 2006.

Great. And you had quite a lot of management turnovers, have you stabilized that and got the team that you want?

I think the management turnover is probably a thing of the past, frankly. We have been aggressively adding to a stable group of experts and management over the past 18 months. I think we've added something in excess of 100 new employees to E&P over the past 12-15 months and we continue to actively recruit the best and the brightest.

Okay. In terms of Libya, the specifics, I think that you included guidance that Libya would in some way be in your numbers for this year, is that the case? Have you taken those numbers out?

In terms of production forecast, nothing in Libya is included.

Okay, and there is obviously nothing on the CapEx side as well, I guess?

Correct.

Okay, and if I can ask you a specific one about the down stream as well, could you just make some comments about any change in risk in Venezuela regarding your exposure there?

Well, we don't have any exposure in Venezuela, as you know. Our investment with Venezuela is offshore, in the Virgin Islands and they own 50% of the Hovensa Refinery and they're meeting all their supply and financial commitments and they're a good partner.

Okay, so there's no change basically?

No. It's a good relationship.

Great. I'll leave it there, thank you.

Next question from the line of Paul Cheng of Lehman Brothers.

Good morning, guys.

Good morning, Paul.

John, John, and John. John -- well--

Got yourself tripped there, Paul!

Yes, I know. Sorry to ask about Pony again. I think, John, did you say 100% interest on that?

Yes, I did.

What is the pre-drill reserve target and what is the exposure in the total expense?

Sorry, Paul, would you say that again?

What is the reserve, pre-drill target if there's one? And what is the exposure -- the total exposure of the expense on that well?

I think the prospect is a typical middle to lower miocene prospect. It would fall into a broad range of 100 to 600 million barrels. The pre-drill cost for the well would be roughly $60 million. Pre-tax.

And, John, this is just a, maybe, a conceptual question; from a portfolio management standpoint, is it worth taking a 100% interest for a well like that? Is there any particular aspect of the well to make you feel optimistic or attractive? Do you think that you really want 100%? I mean $60 million in one well is still a pretty large exposure.

You know, each wild cat well you drill has got its character of risk, Paul. Some less so than others, but all carry risks. We try to assemble a portfolio of exploration opportunities. Where the risked reward for the aggregate portfolio delivers value for us. We can demonstrate, starting 2002,through the present time, that approach indeed created value and as we look at the current portfolio of wild cat opportunities, we believe it's going to continue to deliver value.

So, it's difficult, just as with a stock portfolio to pull out a single stock and say my goodness why did that perform or not perform and or how much should you have in your portfolio? Same thing is true with respect to a wild cat. Having looked at this carefully and judged it in the context of the portfolio we believe it's appropriate to maintain that exposure. In other prospects obviously we take less for a variety of reasons.

John in the past I think you have indicated on a sustainable basis expecting to spend roughly about $2.00 per barrel of production on exploration in a year? And is that still, in the ballpark; a good number or that given the outlook of the Company and your stronger financial position, and, perhaps, looking at the cost inflation in the industry now, that you think you have to spend more?

I don't think we'd look at spending more because of cost inflation, Paul. As John Rielly said, we remain disciplined around our capital spending. It's really important to us that we do that and that we continue quarter after quarter to demonstrate that that's the case. What we are seeing, however, as we ramp up the experience with respect to exploration, as we look in the best basins around the world -- we are finding that we can identify quality opportunities which can command capital. So, in response to that, the numbers may move a little bit, but it will be because the opportunities we are seeing and securing can command the capital versus other opportunities.

So you could potentially be moving it higher from the $2.00 maybe to $2.50 or $3.00 count range?

If we can see the opportunities and we're generating the free cash flow which would allow us to reinvest in an exploration profitably, then we certainly would consider that.

And in the Shenzi, I think the last time you talked it there somewhere in the 250 to 300 million barrels of recoverable reserves. Is that still, in the ballpark a correct range given you're already done with the appraisal now?

Again, Paul, I would really need to see the operator's plans for that and the assumptions of partners, which I have not seen. But certainly, again, I would say that prospect is in the 300 to 500 million barrel range, depending on the recovery factor you apply. There is a very sizeable volume of oil in place and the real issue at the end of the day will be what recovery does the operator and the partnership expect to get from Shenzi? But it's a sizeable development.

and I know that there's early, John, since that you guys give an update number for 2005, is there any capital expending number you can share with us for 2006?

No. We'll have that for you, Paul, in our January call when we do the targets for '06.

And, also, I think this is for John Rielly. When we are looking at debt, and have enough cash, is there any that you would be able to call yet early? For the near term?

Paul, what I would tell you is, it's not our intention to reduce our overall debt level in 2005, and then as we move forward, again, the first call on cash will be the development projects and then excess cash flow beyond that we would look to reduce debt at that time.

Is there any reason why you don't want -- why you want to hold to $1 billion cash and, with just tough earnings and [inaudible] increase your net cash position?

Again, we're -- you know there's, you have to look at where commodity prices end up, where our cap from our capital program ends up, so as we go through the year and we look at where the development projects have gotten to and then we look at new, you know -- a Shenzi development and things like that, that will all be factored in and we really as we said, we're disciplined on making sure we use our cash for our development projects first and we execute there. And, then, excess cash flow, beyond that, again, at these type of commodity prices, probably then in '06, if we have the cash flow would start looking at debt reduction.

One final question, then, final comment. Comment is that, thanks for getting that increasing, that information in the press release, especially on the downstream, really appreciate that. This last question is on the downstream, maybe just for John Hess. John on the refining, if I'm looking at the refining profit, your report year-over-year [Indiscernible], but given the heavy and [Indiscernible] has been widened, quite substantially year-over-year is there anything have changed that's why we see such a big drop in earnings?

I know it's a little confusing, Paul, there are a couple of moving pieces. You're absolutely right in you look at Hovensa margins actually are longer year-to-date this year versus a year ago so, overall growth profitability is actually up some, because of the widening two oil and some of the differentials you talked about. However, you also know at Hovensa for our share , we're providing taxes now. So, on a net bases it's actually down year-versus-year, that's number one and two in the -- trying to understand refining profitability. Number three is Port Reading year-versus-year is down in part because of margins because it's not a crude refinery, it's a cat cracker refinery. And also with the turn around that they had in the first quarter, they were hurt as well. So those are the three major pieces that are the reasons why net income from refining is down year-versus-year, even though it's stronger contributor in the refining and marketing universe for profitability.

Very good. Thank you.

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

Guys, good morning.

Good morning, Mark.

A tough couple of things. John Rielly, I wonder if you could clarify some of the dislocations that seem to be occurring with the respect to E&P tax rate? And in particular the foreign rate, which is very, very low in the second quarter, and which, apparently, you expect, given the comment, to go back up in the second half?

Yes, Mark. And if you just look at the numbers in the press release you can see the foreign rate is down substantially. But if you exclude the special income tax adjustments that we mention in the press release, basically the effective tax rate for E&P is 41%. And, that tax rate is below earlier forecast due to fits from foreign exchange, which I think you can see, in the press release, those benefits actually flow through on the tax line; and then the mix of crude liftings for the -- for the first half of the year. So we do estimate that our effective tax rate will increase a bit in the second half of the year and we're estimating a full year rate at the 43 to 45%.

Okay. But there's nothing else going on, John, in terms of changes in statutory rates or anything like that?

No, only the Denmark statutory rate change, which we mentioned, and put that as a special item. Reduced from 30% to 28%.

Okay. Could I just follow up on the Port Reading comment for a sec? I assume the reason for the lack of improvement is that you're buying cat feed there, which is pretty much tracked to the VGO markets?

Directionally that's correct, Mark.

Okay. Can we have an update on Llano and how that's performing and expectations on it, John?

Yeah, sure, Mark. It actually was one of the impacts in the second quarter production in that the host platform order was taken down for much of June for turn around or half of June. Which cost us 20,000 barrels a day during the time it was down.

How much, John?

20,000 a day during the time it was down. So it continues to perform to expectations if not above expectations, with modest volumes above 20,000 barrels per day net costs.

And you expect to sustain that rate?

Sure do.

Okay, the Russian number, I think that John Hess mentioned in his opening remarks, 7,000 a day, that's a bit above what I remember being associated initially with the leases. Is it just my memory that's failing or is something else going on there?

Wouldn't like to say that, Mark, I would say it's been like that since we acquired the equity in this [laughter]. In other words, it was running about seven when we acquired it. We were down for a little bit, by about 500 barrels a day, it went down to 6.5, it's now about 7.5 so it averages out around seven and we expect it to stay there for the rest of the year.

One final, for John Rielly, could just clarify whether working capital in the second quarter, John, was a source or a use of funds? I didn't quite catch it.

It was a source of funds, $170 million increase.

Okay. Guys thanks an awful lot.

Thank you.

You're welcome.

Your next question from Jeff Dietert of Simmons Company.

Good morning.

Good morning.

Remaining question is on operating cost. John O'Connor you started to talk a little bit about operating cost inflation and I was going to see if you could give us more color there and expectations for the back half of the year?

I'll take that one, Jeff. What we see now for unit costs, if we exclude exploration costs, for which John O'Connor previously provided guidance in his discussion earlier, we estimate that our unit costs will increase by approximately 5%. All right, John had mentioned some cost pressures but there's also an increased level of work overs and also higher production taxes, which directly relate to higher commodity prices but the work overs and the higher production taxes represent about one half of that increase.

So, that's a 5% increase relative to which period?

To, to -- I'm sorry, to full-year, last year. So when we get to the end of the year of 2005 versus 2004, we're looking at 5% increase in our unit costs excluding the exploration costs.

Okay. Very good. What about maintenance activity in the North Sea for the third quarter? Could you give us a little more color on how significant that might be?

We have a raft of projects to be completed in July, August, September. Scott has been down for part of July. Lomond is down, Everest, Beryl, Valhall, Bittern. We have a significant turn around period in the third quarter. And John Rielly gave you essentially, the impact that would contribute in the third quarter by pulling the volumes down and provided you with a range. So the issue is, are the turn-a-rounds completed on time? Do the fields come back up as expected? But there's no doubt that it is impactful, as it always is in the third quarter.

Thank you for the comments.

Your next question from Jennifer Rowland of JP Morgan.

Thanks. Most of my questions are answered. Just one quick one regarding hedges. Has there been any change to your '06 hedging program? Or any plans to change the '06 program?

No. As you can see in the press release we laid out the details of hedging on go-forward basis, and you see there's no change from second quarter and, and we have not, -- and we have no intention of changing our hedge position or to add to it. And, you know when we put it in place the oil hedges were there to provide down side protection during the transitional period and so looking forward our financial and operating positions are significantly improved and we feel we can take on more commodity price risk.

Okay. Great, thanks.

Your next question from Paul Tice of Lehman Brothers.

Good morning.

Good morning.

Just a few questions, first one on Okume. John Rielly made a comment that you're on budget. Can you just tell us exactly how much has been spent and remaining to be spent on the development there?

We had talked about that that development will be about $1 billion, gross, for the life of the development. In 2005, our CapEx is budgeted at right around $350 million for the year and we're right on that forecast right now.

Okay, and in terms of the piece of the development, can you give us an update in terms of the construction and where that stands?

Yeah. All of the construction is ahead of the S-curve. You know that some of the facilities are being fabricated in the Gulf of Mexico, Gulf Coast. Others have been fabricated in South Korea. We have visited these facilities and they are all on track, in fact, they're slightly ahead of schedule. I guess the significant milestone to look forward to probably will be the shipping out of the TLPs from Korea in the first half of February next year.

Okay, and on Hovensa, any color in terms of whether you might be getting cash distribution from that? I believe August is next--

August our Board is going to meet and after that meeting hopefully you'll be able to hear something.

Okay. And then lastly, I know it's not in your production forecast for this year, around Libya, but are you still hopeful that you can get resolution before the end of the year?

As I said before, dialogue is ongoing and we await direction from the government of Libya.

Okay. Great. Thanks.

Your next question from Steven Enger of Petrie Parkman.

Hi. John, I'm wondering if you can add some color or kind of how you're looking at some of the high potential exploration prospects, particularly Gabon, Peru, and a couple of lower miocene, Gulf of Mexico opportunities?

I'm looking at them optimistically, Steve. In this business you have to. [laughter]

Any expansion on that? [laughter]

The other thing we like to do is wait until we have facts in hand before we comment on exploration wells. As I said, both the Gabon and Peruvian wells will have tested the objectives, assuming nothing dramatic prevents that, in this quarter and as we have the results we'll report them. Where we're operator we'll certainly do that; and where we're non-operator, we'll expect the operator to do that.

So that's the two that are currently drilling. Bit of a hiatus until we get to the others but, we really think it's a very solid program, We like it. We like the equities we have. We think Barossa is a great prospect, we think Ouachita is a great prospect. We think Turtle Lake is a great prospect and if I've left it out, shame on me. But, we'll have exciting times as we go through the next six months.

Okay. I think that covers them. And then, the last thing from me, Asian gas, if you would give us, kind of a broad question, you know, what's your vision there? You alluded to making progress on Phu Horm, you've got Pangkah out there. Do you see that as continued focus region for you and if so can you put any additional details to that?

We see that market as strengthening significantly compared with the prospective that might have been the case two or three years ago. We are deliberately building a strong position there. And although we talk about our new projects, it's worth bearing in mind that we're are also an equity owner in Pilene, which is in the Gulf of Thailand -- partners with and Unical and PTT on that prospect, we are also an equity owner in the Natuna A block, which has remaining running room.

As these markets develop, so the resources that we have an equity interest in are coming to market, actually somewhat faster than we had previously expected. We see a strong and increasing demand for natural gas in the region, and we're well-positioned to be part of that growth.

and I guess the last part of that, you see potential for you to capture some incremental opportunities that matter going forward?

Yes, we do. Very much so.

Thank you.

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

John O'Connor any plans to further evaluate the Pangkah Oil accumulation over the balance of the year?

Oh, we are in the process, Mark, of putting together a plan of development for that and we and partners will be working with the authorities in Indonesia to seek approval for that development. So what I would say to you, Mark, is that depending on the authorities and the timeliness of which our applications are prepared, submitted and reviewed, in an optimistic scenario we would hope to see a plan of development approved this year.

So no further appraisal activity necessary?

None, necessary. Having said that, we are in the process of securing a rig for the block, Pangkah Block, and not the Pangkah Field, to test two additional prospects we see on the block, which could have some impact on the development that's currently foreseen, and in a positive way, obviously. That, that we expect to get that rig in to the field probably the fourth quarter.

Any preliminary comments on the scale of the Pangkah Oil Development?

Not really. We're not finished with the work yet Mark, hopefully we'll have that finished by the time of the next conference call and can give you an update then.

Great, thank you.

Sure.

Your next question from Bernard Picchi of Foresight Research.

Good morning, no one asked the question, I thought they would but, roughly half of the increase in the capital spending from the $2.1 billion to the now estimated $2.4 or $2.6 is Russian, and I wonder, I guess, John O'Connor it's probably your area, could you talk about, you know, what that's related to and what the expectations are in Russian?

Yes, I'd be happy to do that Bernie. You know, we view Russia as an interesting option for part of the total portfolio for the longer term. We are fortunate to have found a company and a management of a company that are very knowledgeable in the industry in Russia and with whom we're familiar and comfortable. We acquired our interest in that company in a modest way. Then, as part of the normal developments, the federal government in Russia puts out blocks of licenses for competitive auction. We look at those, evaluate together with our partner whether they would be appropriate or whether they can create value, and evaluate them in the normal economic terms and we bid on them.

We've bid on more than we have won, which speaks to the discipline with which we go to those auctions and to the competition, frankly. We're very happy with the blocks we've picked up. All of the blocks have already had wells drilled on them, so we have a good sense of the resource base, and that accounts for the 200 million, basically, the bulk of it was acquiring new license areas, three new licenses over and above what we participated in when we made the investment in Samara-Nafta.

Are these in that general region?

They're in the same province, the Volga-Urals region in the vicinity or within easy reach of the town of Samara, which is located on the banks of the Volga. As you know this is to the west of the Euro mountains, much closer to markets and easier to move the crude. Much more attractive, quite frankly, than other areas of Russian longer production histories and where the resources are much more depleted. The fields that we are investigating in have not been in production, so that we're enjoying plush production from the wells that we're participating in.

And John, would you describe your activity there as more developmental? Or would you call it exploration or -- how much of it would be rank explorative?

At this stage, none. I would say it's very much developmental. A lot of wells have been drilled, you know, to understand all this have to go back to the era of the Soviet times and the approach they took to establishing the resource base, but there are a lot of existing wells which gives us the comfort that the resources have been established so that exploration is not yet necessary. Having said that, in the longer term, I think there is exploration potential in licenses and in due course. As we have developed the production capacity we'll turn to exploration and see what we find.

Right. And a quick question for John Hess. I gather the FERC has approved your plan for the regasification terminal? Could you kind of describe where you stand right now in the whole regulatory review process, knowing that terminal is not exactly welcome,[laughter] I think, about the locals?

Well, where it stands is, the Federal Energy Regulatory Commission has given us the certificate and issued the order. There are still many other federal, state, and local permits required so it would be a little premature to put a time line on it, but the first milestone and the major one getting the FERC certificate in order, we've done that and now it's just a process of continuing the regulatory process to move it forward.

John, are you pursuing other regasification terminal concepts with Poten (ph)?

Yes, looking at one or two others.

Thank you.

Ladies and Gentlemen this concludes the question and answer and I'll turn it over to Mr. John Hess for closing comments.

Thank you everyone for your attention to our second quarter conference call, and we look forward to updating you on the Company's progress on our next call so have a good afternoon.

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