赫斯 (HES) 2006 Q3 法說會逐字稿

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

Thank you, Kelly and good morning, everyone and thank you for participating in our third-quarter earnings conference call. Our earnings release was issued this morning and it appears on our website. Certain statements made in the conference call today may constitute forward-looking statements. These statements are subject to known and unknown risks and uncertainties that may cause actual results to differ materially from those expressed or implied in such statements.

As usual, with me today are John Hess, Chairman of the Board and Chief Executive Officer; John O'Connor, President Worldwide Exploration and Production and John Rielly, Senior Vice President and Chief Financial Officer. I will now turn the call over to John Hess.

Thank you, Jay and welcome to our third-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 first to exploration and production. Our third-quarter results as compared to the year-ago period benefited from higher oil price realizations and production volumes, which more than offset increased exploration expenses and higher foreign income taxes. Our production averaged 352,000 barrels of oil equivalent per day, up 13% from the hurricane-impacted third quarter of 2005. For the full year 2006, we expect production to average approximately 360,000 barrels of oil equivalent per day, which is about 7% above last year.

Our new field developments continue to make excellent progress. Okume Complex in Equatorial Guinea and Phu Horm in Thailand are on schedule to commence production in the first quarter of 2007. Facilities are now largely in place and development drilling is ongoing at both locations. Also the Pangkah gas development is Indonesia is on track to start production in the second quarter of next year.

With regard to exploration, the Tubular Bells appraisal well on Mississippi Canyon Block 682 was successful. The operator recently commenced drilling the first of two planned sidetracks, which will further delineate the field. Hess has a 20% working interest.

Our Ouachita and Alsace exploration wells on Green Canyon 376 and Garden Banks at 243 respectively did not encounter commercial quantities of hydrocarbons and have been plugged and abandoned.

Meanwhile, at our Pony discovery on Green Canyon 468, the sidetrack well commenced drilling at the end of September with a target 4000 feet northeast of the discovery well. We have set casing just above the objective section. Our plan is to drill ahead and then to cut cores.

In September, we reached an agreement with Maersk by which they will pay a promote on three exploration wells to earn a one third interest in 104 deepwater blocks in the western Gulf of Mexico lower Tertiary play. The Jack Hays prospect located at Port Isabel 526 spud in October and is the first well in this program.

In addition, we are currently participating in two exploration wells in the Garden Banks area. We have a 50% interest in Andros Deep in Garden Banks 342 and a 16.25% interest in Norman in Garden Banks 434. Both of these wells spud in September and are operated by Anadarko.

With regard to Marketing and Refining, the combination of stronger retail and energy marketing margins, as well as higher utilization rates at HOVENSA offset a decline in refining margins compared to the year-ago period. 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 third-quarter 2006 results to the second quarter. Net income for the third quarter of 2006 was $297 million compared with $565 million in the second quarter.

As indicated in the press release, third-quarter 2006 results include a charge of $105 million for the additional 10% supplementary tax in the United Kingdom that was enacted in July, but had an effective date of January 1. 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.

Turning to exploration and production. Income from exploration and production operations was $206 million in the third quarter of 2006, including the United Kingdom tax charge. Income from exploration and production operations was $501 million in the second quarter of 2006, including the Gulf Coast asset sale and office accrual. Excluding these items, E&P earnings were $311 million in the third quarter of 2006 compared with $469 million in the second quarter.

The after-tax components of the decrease are as follows. Lower crude oil and natural gas selling prices reduced earnings by $8 million. Higher crude oil and natural gas sales volumes increased earnings by $7 million. Increased exploration expenses, principally dry hole costs, reduced income by $89 million. Higher operating expenses reduced earnings by $38 million. A higher effective income tax rate reduced earnings by $25 million. All other items net to a decrease in earnings of $5 million for an overall decrease in third-quarter adjusted income of $158 million.

The charge of $105 million for the additional 10% supplementary tax in the United Kingdom includes a provision of approximately $60 million representing the incremental tax on earnings for the first half of 2006 and a charge of $45 million to adjust the United Kingdom deferred tax liability on the balance sheet.

In addition to this charge, the effect of the 10% supplementary tax on third-quarter United Kingdom earnings was $21 million. For purposes of estimating our normalized annual effective tax rate for 2006, we have included the 10% supplementary tax for the full year, but we have excluded the one-time adjustment to the United Kingdom deferred tax liability. On this basis, we expect the E&P effective rate for the year to be in the range of 53% to 55%. For the first nine months of 2006, the E&P effective income tax rate was 53%.

Turning to marketing and refining, marketing and refining earnings were $153 million in the third quarter of 2006 compared with $121 million in the second quarter. Refining earnings were $64 million in the third quarter of 2006 compared with $107 million in the second quarter. The Corporation's share of HOVENSA's results after income taxes was income of $43 million in the third quarter of 2006 compared with $63 million in the second quarter.

Port Reading earnings amounts to $18 million in the third quarter of 2006 compared with $40 million in the second quarter. The decrease in refining earnings in the third quarter was due to lower refining margins. The balance of the PDVSA note at September 30 was $152 million and principal and interest payments are current.

Marketing operations had income of $63 million in the third quarter of 2006 compared with income of $15 million in the second quarter principally reflecting higher margins. After-tax trading income amounted to income of $26 million in the third quarter of 2006 compared with a loss of $1 million in the second quarter.

Turning to corporate. Net corporate expenses amounted to $31 million in the third quarter of 2006 compared with $29 million in the second quarter. Full-year corporate expenses are expected to be within the range of our earlier guidance of $105 million to $115 million.

Turning to cash flow. Net cash provided by operating activities in the third quarter, including a decrease of $95 million from changes in working capital, was $828 million. The principal use of cash was capital expenditures of $788 million. All other items amounted to an increase in cash flow of $20 million resulting in a net increase in cash and cash equivalents in the third quarter of $60 million.

At September 30, 2006 we had $546 million cash and cash equivalents. Our available revolving credit capacity was $2.074 billion at quarter end. The Corporation's debt to capitalization ratio at September 30, 2006 was 32.8% compared with 37.6% at the end of 2005. Total debt was $3.775 billion at September 30, 2006 and $3.785 billion at December 31, 2005.

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). Steve Enger, Petrie Parkman.

First, on Tubular Bells, that appraisal well was drilled quite a distance from the first well and I think you guys had a pretty wide range of potential resource as a result. Can you tell us how consistent the most recent well might have been and do you have a better definition now on kind of what that resource range may look like?

You are right, Steve. It is about five miles between the current drilling well, the well number two and the original Wildcat discovery well. And certainly I think that it has increased our confidence in the size of the prospect and reduced the uncertainty. But in terms of giving you numbers, I would rather leave that to the operator, BP.

Sure. John, would you say it was pretty consistent in terms of net pay count and other important parameters?

Yes, I think it was a very encouraging and a very positive result.

You have obviously got a lot of activity going in the Gulf now. Can you give us a bit of a preview as you look ahead to next year as to kind of what your objectives are in terms of types of Gulf of Mexico exploratory wells you may drill, any sense for numbers at this point?

We are at the very early stages of putting together the program for 2007. That is not really going to come together much before the December board meeting and I think after we're through and have reviewed this with the Board, we will talk about the program on the January call.

Is it fair to say that Miocene and lower Tertiary opportunities both look interesting to you?

Absolutely, yes. And also importantly I think continued evaluation of both Tubular Bells and Pony.

Arjun Murti, Goldman Sachs.

Thank you. I know you are going to provide more detailed capital spending and production growth commentary on the January call, but maybe just conceptually if you look at the -- sort of ex the acquisitions this year, the three odd billion of capital spending, it sounds like a number of the major projects like Okume and so forth are coming on early next year. Ex inflation, should we be looking for a major ramp in '07 or just maybe some inflationary gains in capital spending and that is the extent of it?

Obviously we understand the direction of your question and it is fair, but again we would rather hold it to the January call to give you specifics on that. There are moving pieces, yes. You have cash flow ramping up from God willing the startup of the developments that we have, but we also have an ongoing investment program and developments going forward fortunately. So there are a lot of moving pieces there and we would like to give more clarity to that on the January call.

Okay. Just to follow up in Tubular Bells, do you think the two sidetracks get you the confidence in where in that -- I believe it was the 75 to 350 million barrel range you are or a little more appraisal likely be drilling if you need it?

Our understanding at this stage from partners is that the information from the sidetracks is likely to suffice and that we would not need a further third location, but I think it is also fair to say that that outcome will be influenced to some extent by the results that we find from the sidetracks.

And then just finally is there any update on the Shenzi development at this time or any other metrics beyond what you have said in the past?

No. We have a rig drilling in the field, the first of the development wells. We also are cutting steel both for the [TLC] and for the [Jack] and so I think things are pretty much on track.

That's really helpful. Thank you very much.

John Herrlin, Merrill Lynch.

A couple of quick ones for John. With the two dry holes, could you give us some sort of a postmortem on Ouachita and Alsace?

I mean I think it is fair to say, John, that we have learned quite a bit. Every time we drill a Wildcat well, we learn something with respect to trap, more importantly petroleum systems and it gives us more data for sand mapping frankly. So in both cases, I think it's added to our knowledge. Obviously the results are disappointing, but as you know, that is to be expected in a comprehensive exploration program.

So was sand the issue?

I think it is complicated frankly. We're still working up the postmortem from the two wells. Perhaps we will have some more information later on.

That's fine. With Pony, when are you going to TD? You said you set casing. When are you going to TD?

The sidetrack has casing set just above the objective section and the intention now would be to drill to the first objective and then take whole cores. So there will be a comprehensive core cutting and data gathering program on this well. Right now, I would say we are on the drilling curve, if not ahead of it. But there is probably 30 to 60 days worth left on the well.

Okay. Switching to the M&R side of things, with gasoline prices coming down, are you seeing more demand at the pump?

Well, it is a good question and the direct answer is not more because we are coming out of the summer driving season. On a same location basis, our demand is pretty consistently up same-store sales kind of 2% year on year whether it is outside in gasoline sales or inside in convenience store sales.

Paul Sankey, Deutsche Bank.

Got (indiscernible) couple of the questions you've had earlier. Firstly, could you talk a little bit more about your near-term exploration and how much risk that we have from -- if you like a repeat of the write-offs that we've just had? I am thinking of the Q4 and the Q1 programs and how much value at risk you have got there. That would be question one.

First of all, as John said, we have two wells drilling in the central Gulf, basically the Garden Banks area, Andros Deep and Norman. We have 50% of one of them and 16.5% of the other. They should TD in the quarter. The third well that may or may not TD in the quarter is the Jack Hays well, which is drilling in the western Gulf.

The exposure there, John, I think is relatively less than what we have seen this 3Q. Is that the right way to look at it?

Yes, it is.

In worst-case scenario, presumably we are not going to see another write-down of the kind that we have had really for the foreseeable future.

I think that's right. It's hard to forecast. So much of this is timing dependent. We could've had one of those wells had it drilled quicker, TD and the expense. The second quarter is just sort of serendipity or happenstance that both wells came together in the third quarter. So it is difficult to say it is not going to happen, but I think it is less likely.

Right. And if we just look towards the end of the year and beyond in fact, you have guided I believe that you expect at least 100% reserves for placement over the next five years and I would think that '06 is likely to be a banner year within that.

We have not guided; I would say we have set an aspiration to do that. Certainly while we won't give results in terms of reserve replacement for '06 until the January call, we're certainly encouraged by what we see in the states.

Great. And if I could have a final high-level one for John Hess. John, we think that your NAV is close to $60 than the $40 that you are currently trading at. Is that something that might cause you to change your strategy somewhat in terms of for example disposals or realizing some of the locked up value that is here that isn't being reflected by the equity market?

As you well can appreciate, our focus is to invest, to grow our reserves and production reserves at the 5% to 8% year on year and the production 3% to 5%. That is the major driver of where we are spending our money and as we execute our developments, as we bring some of these appraisals and exploration activities to the development pipeline, we are pretty confident that the value that we are building will be shown and we are going to stick to our knitting in that regard.

Paul Cheng, Lehman Brothers.

John, I know that you are still going through your capital spending program, but if we are looking not just for next year, but for the next five years, can you give us some ballpark numbers saying that if we just want to spend the money to maintain a flat production and what is that number? Also what will be the amount of capital on average that you need between '07 through '10 in order to achieve say a target 3% to 5% production growth rate?

Paul, as you know, the guidance we give will be on the January call and it will be for the year 2007.

Just trying to understand -- how much money that we need for the program in order for you to say achieve that over, not next year, but over say a four-year timeframe?

I understand your question, Paul and we only give guidance for the current year and we will give that on the January call for 2007.

And maybe let me try another way. For the new production that is starting up in Equatorial Guinea in the nation (indiscernible), is that going to have any meaningful impact on your unit DD&A and also the capitalized interest for 2007?

Yes, Paul. Anytime we have new fields that come on just due to the way the reserves are recognized, you can't book all the reserves upfront. So you typically have lower reserves that come on at the initial production and then you wait for performance in the field in additional wells. So from a DD&A standpoint, you would say that the rates from these fields are going to increase our unit DD&A in our portfolio.

However from a cash cost standpoint, these fields are actually lower on the cash cost standpoint and so will help us on our cash operating costs. And then come the January call, we will give you further guidance on where we see our DD&A rate and our cash cost rate for 2007.

How about the capitalized interest? I mean how much of the debt has been capitalized on those projects?

A significant part. You can see it on the press release that we give the capitalized interest numbers and those numbers are significantly related to Pangkah, Phu Horm and Okume. Now the fortunate part of our portfolio right now is as these production starts up and we start ramping it up and therefore taking capitalized interest off that, as John O'Connor mentioned, we have Shenzi going on. We have Pony going on. We now have another successful well on Tubular Bells. So we have another development. So we have three significant developments coming on here in the Gulf of Mexico and there will be capitalized interest associated with that. And then once again on our January conference call, we will give you guidance on where we see capitalized interest for next year.

Just one last question. John, with the retail margin that has been fluctuating quite a lot, I think it is still pretty strong, but can you give us some idea what is the current retail margin you guys realized compared to the third-quarter level?

The retail margin versus -- which quarter versus the third quarter?

Current -- (multiple speakers).

Well, on a relative basis, the retail margin that was realized in the current period versus the third quarter is down. Retail prices, pump prices have come down to match the drop in wholesale prices.

Any kind of magnitude that you can say give us some guidance. Is it down say $0.05, $0.10?

Well, you know, Paul, that changes every day and rather than give a specific number that may be misconstrued or misunderstood, I would just like to say retail margins have compressed over the last let's say 15 to 30 days versus the third quarter.

Very good. Thank you.

Doug Leggate, Citigroup.

Just a couple of things from me. I know you can't talk about the reserve replacement outlook for next year, but just conceptually, the three major fields that are coming on next year, can you give us some idea as to what proportion of the reserves you have already taken from Okume, Phu Horm and Pangkah?

I mean, as sort of rule of thumb would be that on initial sanction on initial startup of production, perhaps about 30% of ultimate recoverable reserves would be booked and as John Rielly said earlier, over time, you book the remainder.

Is it likely we'd expect some incremental bookings from those fields this year?

In 2006, Doug?

Yes.

No, I don't think so. I mean, the initial booking of the roughly 30% occurs at the point in time when you sanction the project. And then they lie fallow until you have additional information either from production performance or from additional drilling, which leads you to have confidence to book increased reserves. So typically, if it's two years from sanction to first production, you're going to have two years where the reserves associated with new developments don't move. And then they should move thereafter depending on what drilling finds.

I guess kind of a follow-up on the same issue. BP has been talking I guess very positively about further developments at Clair. I wonder if you could give us your take on what happens next at Clair because obviously there is a great deal of potential there in terms of the reserves outlook.

Yes. It's true. There's a significant volume of oil in place there. The issue with Clair was always the economics of producibility. We are certainly very pleased with the appraisal drilling that has been going on this year. So while I have not heard BP's commentary and I would rather leave any interpretation of Clair to BP who is the operator, we have been pleased with drilling results.

I guess the last one from me is the production guidance for the fourth quarter, obviously it is towards the lower end of what you originally told us about. Some of that is JDA-related. So I guess could you give us an update as to what is happening with Phase II? There has been some issues in the press about potential pipeline problems or issues on the government side, but maybe just a quick summary if you don't mind.

Let me first of all make sure that we are clear on what we are talking about. We did not give guidance for the fourth quarter. When John has talked about a number, he was talking about average full-year number.

Oh, sorry. My apologies.

No problem. Just so -- I would expect, without giving guidance, that the number would be higher than 360.

Of course.

As to the JDA -- the JDA actually is running extraordinarily well and we are very pleased with the reliability of the production and of the takes from the buyers. What you may be alluding to is we have a planned maintenance shutdown of production starting this week for I think it is 14 days, 14 to 20 days. This is required to install some pieces of equipment associated with what we call the Brownfield additional development.

Further on than that and we will talk about it some more in January, there will be a shutdown in January timeframe of the field again and this is what is going to be related to the tie-in of the main transportation system through the Gulf of Thailand through the market in Thailand.

Great stuff. John, thanks very much.

Bruce Lanni, AG Edwards.

Just a couple of quick questions. I think it is more or less a follow-up to what John Herrlin was asking. But first of all, is there a breakout that you can provide us on dry hole costs between the two wells, Ouachita and Alsace? And then I guess the next follow-up I would like is the Andros Deep and Norman, if you could refresh my memory, are they similar play types along the trend in Miocene that you were drilling for those two wells? Any color you can provide on that?

I'll start with your first question regarding the breakout of the wells. We just don't provide individual well cost information. But as you saw in the press release, our dry hole cost for the quarter was $152 million and those costs were substantially related to those two wells. So on an overall basis, you can get the magnitude of the wells. There were subsalt deep wells, but just from a policy standpoint, we don't break out individual well costs. And then I will pass your next question over to John O'Connor.

Bruce, as you know, Anadarko operates both of these wells. We are not an operating partner of both. I think it is fair to say that they are targeting a Tertiary objective.

Can we go back to Alsace and Ouachita just a little bit? I mean I know you can't say too much about these wells, but (indiscernible) the evaluation phase and probably for confidentiality purposes, but was there a substantial difference for example between Ouachita and Pony? Was there something that shocked you between the two wells or is there some type of color you can provide on that more so than what you have already done?

I would like to think that that was highly confidential information that gives us a competitive advantage and I am not about to discuss it. Sorry.

I fully appreciate that. Thanks a lot.

And you know I think just to be helpful and obviously exploration is a major component of our strategy going forward. I think context is necessary here. Obviously dry holes do occur. It is part of the business; it is a cost. Obviously with the cost of services and drilling going up, the costs have increased. But I think the important thing is we are very pleased with the results of our exploration program. The value of our discoveries far exceeds the cost incurred and that we feel that tremendous value is being created for our shareholders. And I think that perspective is necessary when we go through these short-term hits to our P&L, which we all take seriously to have the bigger context that the exploration program is successful and is creating value.

I really appreciate it. Thank you very much.

Mark Gilman, The Benchmark Company.

I had a couple of things for John Rielly and then one for John O'Connor if I could please. John Rielly, it looks to me like the DD&A charge on the foreign side in the quarter was quite high relative to prior periods and the underlying level of produced by volume. I wonder if you could comment on that. Also, I didn't catch a hedge loss figure that you typically provide for the quarter and would appreciate that. Thirdly, could you comment whether there was any over or under lifting in the third quarter? And then I have got one for John O'Connor.

I am not taking them in order, but as far as your hedge loss, you are right. I didn't talk about it on my script because we put it on page 11 of the press release. So if you have that there, we give the hedge loss, which was $81 million in the third quarter and we give the last quarter and the previous year's third-quarter numbers there. So that information is now going to be in the press release so you will see it typically on that page.

Your other question was related to the DD&A in the third quarter and I guess from an overall standpoint, I'd just like to point out our year-to-date and full-year forecast for our DD&A unit costs continue to be in the range of our guidance, which was $8 to $9 per barrel. The increase in actual costs and rate in the third quarter and as you saw, you saw it on the foreign side, it is primarily attributable and it is something that I talked about a little bit earlier is the startup of the Atlanta Cromarty field where once again when you start up, you don't book the full amount of the reserves on the field. Yet you have essentially the full amount of capital cost going against the lower reserve number. So that is a reason.

We also have just production mix in the quarter and then there has been some increases in asset retirement obligations, which does increase some of the DD&A costs. And then you had a third question which was --.

Over or under lift.

Over or under lifting. In the quarter itself, our production of 352, our sales volume was also 352,000 barrels per day.

Okay. For John O'Connor, John, I wonder if you could perhaps just offer some qualitative thoughts on the statement that I believe you have made previously regarding the inability or unwillingness to narrow the resource range on Pony after the completion of the sidetrack and the whys and wherefores for taking that position?

I wish I had the source of that alleged content, Mark. Let's see. How do I address this? I think every time we drill a well, particularly a step-out well, nearly by definition compels us to narrow the range of potential outcomes. So I doubt if I said that sidetrack would not do that. Be that as it may, we expect that given success and I am always cautious (indiscernible) obviously penetrating objective sections not to count the chickens, but given success, then it will narrow the range, but there is more drilling to be done certainly.

Well, perhaps your comment, John, was with respect to what you will say publicly. Is that a more accurate interpretation?

Well, Mark, I think just another perspective. We have said the pre-drill on our share, our side of the structure. Pony prospect is 100 to 600 million barrels of oil equivalent. That is the pre-drill estimate. We would hope that maybe we can give further definition and narrow that range after this next well. Let's get the well done and core it first. But then it is more likely than not that further drilling is going to be necessary for the structure to delineate it further. It is just early days and obviously we would all like to delineate it further, but we have to wait until the information comes in to be more intelligent about that estimate.

If I could just follow up with John Rielly on the DD&A question if I could. John, what portion of that third-quarter increase in the foreign side should we consider as (indiscernible) going forward given your comment?

Of how much is going to carry forward you are saying?

Right.

Again, Atlanta Cromarty did just start up. We are going to need performance at the field for that to change. Again I think come the January conference call, we will give you further guidance on the DD&A costs going forward. Again then you are going to be dealing with a different production mix as some of the new developments come on. So it is tough to give you that exact answer.

Jennifer Rowland, JPMC.

This is Kate Lucas for Jen Rowland. I have a question on your international tax rate. Looking at the quarter, even adding back the $105 million for the U.K. tax impact, it looks like your international tax rate has increased quite a bit. And I was wondering if there is another driver besides just the U.K. tax rate increase?

Yes, there is, and that has to do -- I answered a question earlier about were we under or overlifted, and from a portfolio standpoint, we were not. So our sales volume equaled our production volumes. However, in Libya our sales volumes exceeded our production volumes there to about one million barrels. Therefore, we had higher sales volumes within Libya, obviously, at that 90% plus tax rate, and that is causing the international tax rate to be increased in this quarter.

So, again, I gave guidance for the full year, 53% to 55%, which you can look at as more of what our run rate for 2006 is.

And then where is the offsetting underlift position that would've made up for Libya?

It is in various countries. So again -- it is going to happen. Our production mix is always going to change, and that is why we always try to give annual type effective tax rate information, because again over a full year, then it kind of evens out.

And then just another question; could we get an update on the West Med development and whether your plans for that are still to begin drilling next year, or whether you have been able to secure a rig?

We continue to work to optimize different development scenarios. We are probably looking at -- we have soft tenders for a rig for next year. We happen to be very pleased with the outcome. So I think we will continue to not be specific about when we would start drilling until we have tied down an optimum development plan.

(OPERATOR INSTRUCTIONS). Nikki Decker, Bear Stearns.

Just a few quick things. One, could you talk about what is behind the higher production costs this quarter and maybe some guidance for the fourth quarter?

Production costs primarily, obviously, you have the increasing service costs in the industry. We have higher production taxes because of the higher commodity prices than we expected at the beginning of the year, and then specifically as it relates to the third quarter, this is our North Sea maintenance period.

So typically, we are always going to have fields that go down for maintenance and workovers in the third quarter, and our production costs will always increase on a per barrel basis in the third quarter.

Guidance for the fourth quarter, John?

We have given general guidance of production type costs or cash costs in the $9 to $10 barrel range. Because of the items that I spoke about earlier, the increasing service costs and the higher production taxes, we would guide you probably a little higher than the $10 range at this point.

Did you book the entire expense on Ouachita and Alsace in the third quarter?

Oh, yes, that full amount. Now I mean there always can be some little pieces of work that get billed after, but really all the material costs are booked in this quarter.

And on Tubular Bells, what is the possibility that that gets sanctioned in 2007?

I wish I knew the answer, Nikki. Really, I would have to ask our partners in particular who work with the operator. There will be quite a bit of engineering work and subsurface work to be done before I could answer that question. But I would say it is -- at this stage, I don't have the information from the operator.

Okay. Just on an accounting thing on this tax adjustment, on page 2 in the release where you show the table that has the tax adjustment for the three-month period and then for the nine-month period, and it looks as though the nine-month period excludes the cash portion of the incremental income tax. You know, that sort of suggests to me that you have restated prior quarters, or how do we look at that?

What we try to give to you is -- so you can look at individual quarters and then the nine months on a recurring type basis. So what will be any type of item that affects comparability, how will our income look consistently going forward? So for the three-month period, you have the full amount of the charge because the whole out of period being the $60 million that relates to the first and second quarter and the one-time change to the deferred tax liability is really an out-of-period cost for the third quarter. That is the $105 million piece.

When you look for the nine-month period, though, now you should be including on a recurring basis the $60 million that relates to the first and second quarter. So, therefore, we have taken it out of that item from a special concept. And the only special item then you have from a nine-month standpoint is the one-time adjustments of the deferred tax liability.

So how would that $60 million break down by quarter?

You could say it is fairly ratable. And I gave the number for the third quarter. The actual third-quarter impact was $21 million.

Okay, thank you.

Ladies and gentlemen, this concludes the question-and-answer session for today's conference. We thank you very much for joining, and have a wonderful day.