赫斯 (HES) 2006 Q2 法說會逐字稿

Good day ladies and gentlemen and welcome to the second-quarter 2006 Hess Corporation earnings conference call. My name is Kelly and I will be your coordinator for today. At this time all participants are in a listen-only mode. We will conduct a question-and-answer session towards the end of this conference. (OPERATOR INSTRUCTIONS) I would now like to turn the call over to Mr. Jay Wilson, Vice President Investor Relations. Please proceed, sir.

Thank you. Good morning everyone and thank you for participating in our second-quarter earnings conference call. As usual with me today are John Hess, Chairman and Chief Executive Officer; John O'Connor, President of Worldwide Exportation and Production; and John Rielly, Senior Vice President and Chief Financial Officer.

I will now turn the call over to John Hess.

Thank you Jay and welcome to our second-quarter conference call. As usual I will make a few brief comments after which John Rielly will review the financial results for the quarter.

Turning to Expiration and Production, our second-quarter results compared to a year ago benefited from strong oil prices offset partially by higher income taxes internationally. Production averaged 354,000 barrels of oil equivalent per day, which was essentially flat with the second quarter of 2005. For 2006, our current production forecast is 360,000 to 370,000 barrels of oil equivalent per day which is at the lower end of the range of our original guidance. Price effects from our production sharing contracts and asset sales account for the bulk of this revision.

We continue to make excellent progress in advancing our field developments. The Okume Complex, Pangkah and Phu Horm developments are all on schedule to commence production in early 2007. Also in the second quarter, the Shenzi development in the Deepwater Gulf of Mexico, where we have a 28% interest, was sanctioned by the operator BHP Billiton. Major contracts have been committed and the project is scheduled to commence production in 2009.

In the United Kingdom, production from the Atlantic and Cromarty Fields commence in June and average 13 million cubic feet per day for the second quarter. Net production from the fields is currently averaging about 80 million cubic feet per day.

Regarding our exploration activities, during the second quarter we announced a discovery at our 100% owned Pony prospect on Green Canyon Block 468, in the Deepwater Gulf of Mexico. The well was drilled to a total depth of 32,448 feet, and encountered 475 feet of oil saturated sandstones in Miocene age reservoirs. After we complete data gathering, we will drill a sidetrack which is intended to evaluate the perspective section 4000 feet to the northeast of the discovery well.

Also in the Deepwater Gulf of Mexico, we are drilling our Ouachita and Alsace prospects on Green Canyon 376 and Garden Banks 243 respectively as well as the Tubular Bells appraisal well on Mississippi Canyon 682. These wells have not yet reached their targeted objectives.

With regard to Marketing and Refining, refining was the major contributor to improved earnings in the second quarter versus the prior year period. The HOVENSA and Port Reading refineries both benefited from the strong margin environment. Similar to last year, retail marketing margins were squeezed during the second quarter as wholesale prices rose more quickly than pump prices.

Our current estimate of 2006 capital and exploratory expenditures is 4.1 to $4.3 billion. This level of spending is up from our previous forecast of $4 billion. The increase largely reflects our success at Pony which has resulted in the addition of a sidetrack well and an appraisal well into our 2006 program; the acquisition of new leases in the Deepwater Gulf of Mexico; and accelerated development drilling at the Okume Complex.

I will now turn the call over to John Rielly.

Thank you, 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 2006 results to the first quarter.

Net income for the second quarter of 2006 was $565 million compared with $695 million in the first quarter. As indicated in the press release, second-quarter earnings included a gain of $50 million from the sale of Gulf Coast assets and a charge of $18 million as a result of vacating leased office space. The pre-tax amount of the office charge is included in general and administrative expenses. First-quarter earnings included a net gain of $186 million from the sale of certain producing properties in the Permian Basin.

Turning to Exploration and Production, income from Exploration and Production operations was $501 million in the second quarter of 2006, including the Gulf Coast asset sale and office accrual. Income from Exploration and Production operations was $706 million in the first quarter of 2006, including the gain from the sale of the Permian assets. Excluding these items, E&P earnings were $469 million and the second quarter of 2006 compared with $520 million and the first quarter.

The after-tax components of the decrease are as follows, higher average crude oil selling prices increased earnings by $70 million; lower average natural gas selling prices decreased earnings by $51 million; a higher effective income tax rate, primarily due to Libyan operations, reduced earnings by $85 million; all other items net to an increase in earnings of $15 million for an overall decrease in second-quarter adjusted income of $51 million.

As indicated in the press release, production volumes amounted to 354,000 barrels of oil equivalent per day in the second quarter of 2006, compared with 361,000 barrels per day in the first quarter. This decrease primarily reflects seasonally lower natural gas production and maintenance activities in the North Sea. Our E&P operations were under lifted compared with production in the second quarter, resulting in decreased income in the quarter of approximately $20 million.

The effective income tax rate for Exploration and Production earnings in the first half of 2006, excluding special items, was 46%. In July 2006, the United Kingdom enacted an additional 10% supplementary tax on petroleum operations with an effective date of January 1, 2006. As a result, we will record a charge in the third quarter of approximately $105 million. This charge includes a provision of approximately $60 million representing the incremental tax on earnings for the first half of the year and a charge of approximately $45 million to adjust the deferred tax liability in the UK. Excluding this special charge for the change in UK supplementary decks, we expect the E&P effective rate for the year to be in the range of 50% to 53%.

The after-tax impact of crude oil hedges reduced second-quarter 2006 earnings by $83 million compared with a cost of $65 million in the first quarter. Outstanding hedges on the remainder of 2006 production amounts to 30,000 barrels per day. The press release provides details on future production that is hedged and the related contract raises. The after-tax deferred hedge loss included in accumulated other comprehensive income at June 30, 2006 amounted to $1.7 billion.

Turning to Marketing & Refining. Marketing and Refining earnings were $121 million in the second quarter of 2006 compared with $49 million in the first quarter. Refining earnings were $107 million in the second quarter of 2006 compared with $21 million in the first quarter. The Corporation's share of HOVENSA's results, after income taxes, was income of $63 million in the second quarter of 2006 compared with a loss of $1 million in the first quarter. The improvement in the second quarter was due to higher refining margins and increased utilization of the fluid catalytic cracking unit.

Port Reading earnings amounted to $40 million in the second quarter of 2006 compared with $19 million in the first quarter, reflecting higher margins. The balance of the PDVSA notes at June 30 was to $182 million and principal and interest payments are current.

Marketing operations had income of $15 million in the second quarter of 2006 compared with income of $12 million in the first quarter. After-tax trading amounted to a loss of $1 million in the second quarter of 2006 compared with income of $16 million in the first quarter.

Turning to corporate. Net corporate expenses amounted to $29 million in the second quarter of 2006 compared with $23 million in the first quarter. Full-year corporate expenses are expected to be within the range of our earlier guidance of 105 to $115 million.

Turning to cash flow, net cash provided by operating activities in the second quarter including a decrease of $79 million from changes in working capital, was $686 million. The principal use of cash was capital expenditures of $759 million. Proceeds from asset sales and other items amounted to an increase in cash of $55 million resulting in a net decrease in cash and cash equivalents in the second quarter of $18 million.

At June 30, 2006, we had $486 million of cash and cash equivalents. Our available revolving credit capacity was $2,138 million at quarter end. The Corporation's debt capitalization ratio at June 30, 2006 was 34.5% compared with 37.6% at the end of 2005. Total debt was $3,774 million at June 30, 2006 and $3,785 million at December 31, 2005.

In May 2006, the Corporation amended its revolving credit facility to increase available capacity to $3 billion and extend the term to May 2011. The Corporation has long-term debt maturities of $1 million over the remainder of 2006 and $29 million in 2007.

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

(OPERATOR INSTRUCTIONS) Doug Terreson of Morgan Stanley.

Congratulations on your record results. My question is not Exploration and Production but instead refining and marketing. And specifically in refining, while the results were obviously strong, the capture rate for margin seemed to be a little bit lower than we were expecting. And so I wanted to see if you could provide some color as it relates to a few of the factors that might help to explain that issue meaning, were crude oil or refined product differentials or operating costs different than were the case in prior periods? And if so, any quantification that you could provide would be helpful.

Doug, fair question. And you are absolutely right. Second quarter was hurt by some unexpected downtime in our HOVENSA joint venture refinery. We had at the beginning of the quarter some down time because of a problem we had with cab cracker which was since corrected. And then in June, I believe, we did some extra work on one of our crude units to basically defer a coker and blocked turnaround at the refinery that was planned for this year to divert in probably the second quarter of next year.

So we took some more down time in June which meant lower crude rates and therefore lower capture rates of those margins you talked about, in essence to run the coker a longer time period before the turnaround next year instead of this year.

Great. Thanks a lot and congratulations on your record results.

Thank you.

Steve Enger of Petrie Parkman.

Good morning. Just a couple things on the Gulf please. On Pony, assuming your first well was more or less on top of that structure, what do you expect to find in the step out? Do you think you're going to see a similar amount of debt pay? Would you expect you are going to see some thinning? What can you tell us obviously based on only a gross interpretation at this point?

I wish I could tell you, Steve, but the purpose of drilling the sidetrack is to determine whether the section remains at the same thickness or whether it is thinning or indeed whether it is thickening as we come off of the crest. So I'm afraid we're going to have to wait until we get the CD with the sidetrack to answer that question.

Okay. So it looks like it will be structurally a bit lower, John, and you'll just have to see on net pay, is that's a fair assessment?

At this stage I would think that that is right. I mean we located the first well [successfully] pretty much but it depends on how much dip we're going to see on the structured.

Okay. And just to confirm in the net pay count on that first well that is essentially all oil and you did not see any free gas?

Yes, we did not see any free gas to my knowledge. The samples we've taken have been all oil with the [MTT]. But let me just clarify what you said. What we are reporting is total hydrocarbons encountered in all of the sands.

Okay. And then can you give us an update on kind of drilling schedule for additional Gulf exploration prospects, [Andross Deep], [Jack Hayes], I think are on your schedule?

Yes, they are and to be honest with you on the schedule they are showing as late July, early August. I think that things are moving backwards depending on the activities of the rigs that are scheduled to drill those locations. So at this stage I would push it back a month probably towards the back end of August for both of those spuds.

Still well within third quarter?

Yes.

Okay, thank you.

Doug Leggate with Citigroup.

Thank you, good morning, guys. A couple of things from me if I may. First of all, I think there has been a little bit of consternation about your gas utilizations in the North Sea this quarter. I've got you down in line with the IPE kind of quotes but can you just confirm what your spot contract prices or your spot contract volumes rather versus any long-term contracts you've got and your exposure to the spot price moves in other words?

Yes, sure. In Europe, so within the Europe gas production that you see there, approximately 56% of our production is on the spot market. And then the rest are on term contracts. And some of them will float relating to oil type indices but for the most part for the spot market for overall Europe it is just around 56%.

Okay. But nothing unusual in the realizations?

No, nothing unusual at all. It is just market based coming off from the strong first quarter pricing to the second quarter.

Great. I guess the second thing I have is actually for John O'Connor, and it is on Shenzi. When Repsol obviously acquired this date from BP, they gave some additional color on their view of ultimate recoverable reserves and what they thought was going on in the northern flank. Can you just maybe give us your opinion on the same kind of issues? And also can you confirm whether or not you were offered any preemption or not and if so why did you choose not to move ahead with a larger stake in Shenzi?

Let me answer the second question first. Both we and BHP Billiton had preferential rights with respect to BP's interest once they sold it. We evaluated it and we did not think that it necessarily was an outstanding fit for our portfolio and for our trajectory of growth plans.

As far as the northern flank is concerned the intention is to drill a couple of wells on those blocks and I think it would be smart to wait the outcome of the drilling without speculating what might be there. Obviously in committing to drilling the wells we're optimistic that they will be prospective.

Okay, John. I will leave it there, thanks.

Paul Sankey of Deutsche Bank.

Good morning everyone. Just firstly on let's say the tighter range of guidance for production. Can we assume that given that you've moved down about 10,000 barrels a day that that was the entirety of the asset sales and the [PSC] effects? And if you could split out that share of those two that would be helpful? Thanks.

Hi, Paul. It is not entirely due to that. We had some heavier than expected or programmed contributions from maintenance in the North Sea. And also in Southeast Asia, frankly. I think there were lingering effects from the hurricane impact on production on which we had assumed would be remedied sooner than was actually the case. And we had also anticipated that Atlantic Cromarty would likely come on production sooner than it actually did as a result of some bottlenecks that the outside operator experienced in bringing the production facilities up.

So I would say it is a raft of things. In terms of the production sharing agreement it about 3000 barrels a day on an annualized basis in terms of asset sales over and above the Permian it's between 2000 and 3000 barrels a day on a full-year basis. So the things we reported would get you back to about 370 and then you add on top of the delayed startup on Atlantic Cromarty, and heavier than expected maintenance brings you right bang in the middle of the number.

Sure. And the implied acceleration in the second half, what do we need to look for there, John, Atlantic Cromarty is an obvious one. Could you highlight some of the other startups or drivers?

Well with respect to Atlantic Cromarty, they are still bringing the facilities up. We have had three wells on stream, currently we are flowing two as again we debottleneck production facilities to handle greater volumes of liquids. I think by the middle of August we will be up to design capacity on Atlantic Cromarty. And hopefully we will run at that for the rest of the year.

There are no other new field startups planned for this year. There is a major downtime; however, if you take into account on the JDA facility there are forty days of down time planned for brownfield activities on the production platforms to get ready for Phase II volumes. And also to tie in the main pipeline in the Gulf of Thailand to Thailand.

Great. That is very helpful, thanks. And so how do I get my acceleration based on what you just said? The implied acceleration that you need in the second half to get up to the 360 to 370?

Pretty much what you are going to see in the second half is restoration of the volumes lost during the maintenance period particularly in the fourth quarter and full run rates of Atlantic Cromarty. So I'd say it's the absence of the down time due to maintenance which is really quite substantial. And also I'd say full run rates in Atlantic Cromarty.

That is very helpful. Thank you very much.

Arjun Murti of Goldman Sachs.

Thank you. One follow-up question on volumes. Any comments on how [SEBA] is doing? I don't think you quite put the volumes out like you used to and just curious on that one?

Pretty much right on stable plateau, Arjun. Nothing surprising. It's not down versus plan. It's right on, it might be 500 barrels a day plus or minus (multiple speakers) volumes.

Plus or minus 30,000 barrels a day net to you?

Exactly.

Great. And just to follow up on the Shenzi comment, it looks like you didn't see the need to counter that price. Any temptation to sell your interest at such an attractive (multiple speakers)?

We have camps on both sides of that issue, Arjun.

In all seriousness, do you see that as an alternative going down the road not necessarily Shenzi but as you made Pony and some other discoveries, monetizing this? Or is it really the plan -- is it going to be Legacy Fields, you know it's going to be core base production for many years into the future, or we're not really looking to sell these assets?

What I would say, Arjun, is that we keep the totality of the portfolio under review at all times. We're always trying to rebalance it and upgrade it which is why we had the Gulf Coast sales in the first half of the year and why we constantly look at other sales. Nothing is sacred. Nothing is off the agenda. But for the time being at least I think that the position in the Gulf of Mexico is one we like very much. We'd certainly like to add to it but as the portfolio evolves, there is potential for selling, trading or realigning the interest we have depending on how they turn out.

That is helpful, thank you so much.

Jennifer Rowland of JPMorgan.

Thanks. I was wondering if you could provide more detail on the drilling activities in the Gulf particularly where things stand on Ouachita versus your target depth? Same with Alsace. And if you could also comment on how the cost of those wells, particularly Ouachita, has risen over the past few months?

We don't comment on the cost, Jennifer, of drilling wells. We hope they will be successful and end up as part of the development. In terms of Ouachita, we are currently drilling in a sidetrack hole at about 23,000 feet. In terms of Alsace, we are preparing to sidetrack the well at about 7000 feet and that well is going to go to 24,500 feet.

Do you have any, can you provide us any targets for when you think those wells will be down?

Not really. I would guess somewhere in the vicinity of plus or minus 60 days, possibly for both wells. Both are complex wells, both are subsalt wells and I think we just have to see how they go.

Okay, great. And then just lastly, I noticed the foreign E&P, the G&A expense doubled versus last quarter. Is there something particular going on there or is that the run rate we should expect going forward?

Jennifer, in my remarks earlier I talked about the vacating the office and the charge associated with it. The pretax amount of that charge is $30 million and that is in that international G&A line.

Okay, great. Thank you.

John Herrlin of Merrill Lynch.

Yes, pretty much everything has been asked. A couple of quick ones. Services costs and terms of inflation, John, are you seeing moderation in the way it tracks, etc.? Or (multiple speakers) escalation?

John, I would more characterize it as stabilization at a very high level, quite frankly versus the rights that we have contract rigs at fortunately. But as we see rigs coming up for renewal, we don't see any moderating operation in price just yet. Say in oilfields, tubular goods, cement, drilling fluids, probably year-on-year about a 10% rise in costs there.

One thing to bear in mind, so this is just a general observation of the industry, but one thing to bear in mind about projects, most of our costs have been contracted in and locked in so we are not experiencing that type of inflation just yet. Obviously for new projects going forward is where we are going have to bite that particular cost increase.

Great. An unrelated one which is on downstream. Refined product sales for resid was down a fair amount versus second quarter last year. Any reason other than price?

Well, the major reason there in quarter to quarter the Venezuelans may or may not sell to Hess their share of production at HOVENSA. And more recently they've been selling it on their own instead of selling it to Hess and that is just a market decision that they have made. So that's the major driver. And also with lower gas prices, there is incremental even though we are out of the season some substitution of natural gas sales which we have the benefit of in exchange for lower sales of residual fuel oil to our industrial commercial customers. But the major driver there is not having the resid available from PDVSA.

Okay. Thanks, John. Last one for me is on upstream volumes. So we should expect more of a back-ended fourth quarter surge in terms of the [games]? Is that fair?

Not sure I would want to characterize it as a surge, John.

Well higher.

I would expect to see higher volumes in fourth quarter for sure.

Okay, super. That's it for me.

Mark Gilman of the Benchmark Company.

Good morning I had a couple. I was wondering whether there has been any success today in terms of modifying the gas price, the gas contract on the West Med?

We haven't actually made any initiatives to modify the gas price, Mark.

I guess I was under the impression that the pricing arrangements were not satisfactory to you and that you might undertake such initiatives?

I don't know where that might have emanated from. Obviously gas pricing contract terms, any discussions with government or government entities would be confidential.

Okay, let me try another one if I could. On Pony, have you obtained the data from the [nix] on Chevron?

Not as of yet. I do know that we are in discussions with respect to confidentiality agreements to facilitate (inaudible).

So you hope to have it available?

Yes, I think that is the intent.

Okay. Are there in your mind, John, any reservoir energy issues with respect to Pony? And do you have in mind any particular in-place recovery rate on it?

The answer to both questions is no. I don't know of any concerns nor do I have any sense of recovery rate until we get hold course and do some more subsurface work, Mark, it's way premature to be contemplating what recovery rates might apply.

Okay. And just one final. Could you give us a little bit of an update on your LNG activities? And particularly apparently your intent to get involved in building a terminal in Ireland?

Yes, Hess LNG, as you know, Mark, was awarded by the Shannon Development Authority the rights to develop a site in Shannon for an LNG terminal. And it is early days there and we are starting to do some site work so it would be premature to put dates out there. But it is obviously an opportunity that we are enthusiastic about. At the same time, we continue to move on with the permitting process at our Fall River site where we have the FERC certificate to move forward in Massachusetts for another LNG terminal as Hess LNG.

Okay, guys. Thanks very much.

Paul Cheng of Lehman Brothers.

Thank you. I have several hopefully pretty short questions. I think two of them is for John Rielly. John, maybe slow here. Can you go back into your reconciliation on the E&P earnings from one quarter -- to the first quarter to the second quarter? In there you indicate that the higher average core price increased earnings by about $17 million but the higher effective tax rate primarily due to Libya, reduced earnings by 85. So if those math work, that suggests that Libya is actually a loss in the operation?

No.

Because all your other operation that are earning -- just trying to imagine that if oil price increased by $3 in your organization we have no Libya, your earning go up and now that you add Libya, and now that all of a sudden all the increase in earning is being absorbed or that actually more than offset so you have a net loss. So (multiple speakers).

We actually had a good bit of discussion, Paul, of how we were going to do this variance here for this quarter. First thing I have to say is the Libyan operations are profitable. We did lift our production -- basically in line with our production. We are still under lifted overall because in the first quarter we didn't lift any barrels at that time. So the Libyan production is profitable. What we have here is when you're doing a variance analysis like that and you apply your average effective rate over your overall portfolio, that is what happens with this volume variance and the way you are looking at it. So, again we could have done this variance excluding Libya and then add Libya on as being profitable from that standpoint.

In other words that in the sense that you understate the improvement in the average oil price increased to your earnings?

Yes, that is exactly right. And in some other ways -- in other parts even volume a little bit and in price that is what happens with that.

Okay. Second question on the -- you're talking about the special item in the third quarter. There are two components to the tax, one is the retroactive and the other one is the deferred. I understand that deferred is a onetime non-cash so we consider a special item. Why the retroactive for the first six months which is part of this year we saw would be considered as a special item?

It is all where you want to put it in your analysis, Paul. Why we're calling it a special is because we're going to pick up the whole first half's increase (multiple speakers).

I understand that, but for the full year that that's part of the operation.

Exactly. That additional $60 million really if you were starting from day one and you had the higher tax rate that would have been right in our effective rate. So it is just going to be special because we're taking all the first six months in the third quarter. But if you're looking at it for a year you are right on your analysis.

I can't imagine how you can treat that as a special item when you are looking at it from a full year standpoint.

Sure from a full year. But in the third quarter when we report it, it will show up in -- if you want to call it an out of period (multiple speakers).

Sure I understand. But I mean that you are going to carry it over into the rest of the year?

Exactly.

Okay the other question is for John O'Connor. John, with Nigeria talking about the windfall tax and also maybe changing the equity ownership in some of their partner or that their (indiscernible) in the country, what kind of impact do you guys have any kind of information you can share, what kind of impact on your operation may be?

This is with respect to the Algerian initiative, Paul, is that right?

That is correct, yes sir.

We obviously have not seen a law promulgated or regulations promulgated, so all we know is what we read in the media. The first of which basically is that Sun (indiscernible) should have a majority equity in these joint ventures. And in our case, in Gassi Agreb, our operation there at Sun (indiscernible) already has 51% working interest in the block. So at the stage, I don't see a major impact for us in what the minister has discussed to the media.

How about the windfall tax though? They have not contacted you guys and to disclose what is really what they mean?

It is difficult to know what they mean, Paul. Because we are just picking up media reports as I said. We've not seen anything formal just yet so at this stage, we are not asking to see anything. We are not particularly concerned. I think we are in good stead in the country and in the joint venture. The commercial terms I think are probably satisfactory both for the government of Algeria and for ourselves and of course, (indiscernible), our partner. So until we hear something different formally, that is how we view it.

I see. Okay. Last question is for John Hess. John, [HOVENSA] has been relooking at I think their international refining portfolio. And earlier was talking about wanting to sell their [SECO] refinery interest and now that seems like they may think about selling it to their partner. Have any kind of discussion in that similar nature have occurred between you and them on the (indiscernible)?

No.

So then it would be on continue on the status quo on that?

Yes, it is a good relationship. We are happy with the partnership and from what they tell us, my impression and our impression is that they are happy with the relationship as well.

Okay, very good. Thank you.

Nikki Decker of Bear Stearns.

Good morning. Just coming back to Pony, the estimated resource range is still very wide 100 to 600. Just wondering if you have encountered any data that would make you lean toward one range -- end of the range or the other?

No, Nikki, surprisingly as opposed to good news is that the initial well on the block is exactly as expected and therefore has not served to narrow the range. Nothing on forward has happened nor has it for example been doubled, the thickness we might have expected which might have increased the range. The real encouragement is that we found what we hope to find and we have additional drilling to do which will help to narrow the gap.

That resource range though, that would cover your acreage, is that right?

That is correct. That is on our acreage.

When do you think you will be able to narrow that range? Is there a milestone that we should look for?

I think that I would not expect to narrow the range with the sidetrack well. I think the planned appraisal well which will follow on from the sidetrack and which might spud middle of the fourth quarter but probably won't reach [GD] until sometime next year would contribute to narrowing the range. But at this stage, it is very difficult to say.

And I would refer you back to some of the questions earlier in the call who talked about Shenzi, for example. You see that Repsol in purchasing their equity in Shenzi described a significant range in the potential reserves at Shenzi and this is after significant drilling has occurred on the (inaudible).

On Ouachita and Alsace, what is your exposure on exploration expense there?

In Alsace, we are straight up 60% equity with (indiscernible) 40% equity. On Ouachita, it is more complicated because we farmed out to partners who took a disproportionate equity.

I'm looking for a dollar amount on exploration expense potentially.

Why don't I ask John Rielly to comment on exploration expense.

And unfortunately, Nikki, I can't give you a real grade -- I know you are looking for your model purposes but the point is it really does matter one on timing and on the success of the wells. So at this point I really can't give you too much guidance as it relates to exploration expense.

And just finally on operating costs. I know that you got hit on a unit basis by lower production. But can you just comment on the role that inflationary factors are going to play and how you think unit operating costs might look in the remainder of the year?

Sure. At the beginning of the year we had talked about our unit cost being in the range of 17 to $19. And as you can see, in this quarter here we had an $18.94 unit cost and an $18.08 for the first six months. I'd guide you to the higher end of this range. We've got the higher prices that are out there. We have transportation contract linked to prices. We have production taxes that are much higher as a result of these prices. We have the maintenance activities that John O'Connor spoke about earlier and we're going into the maintenance fees.

And so for the year we will end up clearly at the high end of that range at the $19 and then obviously to get there in the third quarter specifically with the maintenance activities we will be above that $19. And with these high prices and the stabilization of the service costs at this high level that John O'Connor spoke about, that is where we see it ending up at.

Thanks, that is helpful.

Luis Olguin of ING.

Good morning, gentlemen. I'm trying to get a better feel for your production sharing contracts. Can you give us some color on what percentage of production you would say is under this type of contract and maybe some guidance on how sensitive production is too much higher prices?

As John O'Connor spoke about earlier, we are seeing about a 3000 barrel a day impact from the [PSCs]. I think what we generally have from a PSC standpoint is somewhere in the 25-ish -- I'm looking at the numbers quick here -- about a 25% range of production related to PSCs. And so again in this year with these higher prices, we are about 3000 barrel a day from the beginning of the year.

Okay. And nothing on maybe the tight prices go to $80 a barrel, how much would that change the production?

As you can see we've had a decent increase from the beginning of the year and we are not that sensitive. It's about 3000 barrels since the beginning of the year. So even if it goes up to 80, that is not going to be a big number.

Fair enough. Thank you.

Bruce Lanni of A.G. Edwards.

Yes, actually my question has been answered regarding the operating costs. But I do want to kind of focus back on the CapEx and see if you have any other indications that you are getting inflationary pressures similar to other companies that are going forward say into '07 and '08?

At John O'Connor mentioned, we clearly are seeing the stabilization at these higher level of the service costs and the ancillary services that go along with the rigs. Right now from our CapEx program like on our production and development purposes, we are pretty much coming in on our budget that we spoke about at the beginning of the year. Because we did have those contracts in place, we're able to forecast it and so we're able to get some of those contracts in before some of these increases. And again I mean you see on the rigs here, you are seeing almost close to 50% type increases. And so no question, that will impact us in the developments that we have going forward.

But since in the past we secured for the needs that we had especially in the Deepwater Gulf and also locked in our cost for the [Sabah] and Okume complex, we're somewhat insulated as John O'Connor pointed out earlier.

And just anecdotally, can you kind of provide some comments or some color on the downstream refining and marketing gasoline sales. They were flat year-over-year. Are you seeing any -- are you hearing anything or seeing anything from your retail outlets about what is going on with the gasoline sales?

No. Our sales, same-store sales on the outside are about up 2% year-on-year. And on the inside the C stores that we have, we own and operate 85% of our sites, again, it's up about 2%. So we are still getting our fair share of the market.

Okay. So you haven't seen anything indicating that there is a significant slowdown?

Not in our case.

Great. Thank you very much.

Robert Kessler of Simmons & Co.

Good morning. I wanted to see if I could follow up on Ouachita here again? Just to clarify, I thought you had said earlier on the call that you are now at around 23,000 feet. I also seem to recall that in May you were at roughly 20,000 feet with more or less 2000 feet to go before hitting pay. Are those numbers accurate and can you confirm where you are in the well now relative to target zones?

Yes, sure, Robert. We are currently at about 22,700 feet in the sidetrack hole. We have been deeper. We've experienced downhole pressure containment issues as a consequence of it, we've sidetracked and modified the design to go forward again. We have some drilling ahead of us before we get to the objective section.

Okay, so you've not tested any objectives zones?

Correct.

Okay.

Doug Leggate of Citigroup.

Sorry for the follow-up, fellows. Your refining and marketing again. John Hess, I wonder if you could give a little bit more color on the lost opportunity costs and perhaps the impact of maintenance on the refining earnings in this quarter?

As far as what happened is early on from the first quarter, our FCC was down again for unexpected maintenance. That probably was in the range of $5 million and that is gross so about 2.5 our share at HOVENSA. Then the coker and the repairs to the crude unit and the work we were doing on the coker itself to extend the turnaround I'm thinking again it is gross of about 20 so we are looking about 10 coming to us. So something in that range of 12-ish to $15 million in the quarter.

Okay, great. Thanks.

Thank you all for attending our call and we look forward to updating you on our progress in the next call. Thank you very much.

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