康菲 (COP) 2008 Q1 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the ConocoPhillips' first-quarter 2008 earnings conference call. My name is Jen and I will be your coordinator for today. At this time all participants are in a listen-only mode. We will be facilitating a question-and-answer session towards the end of today's conference. (OPERATOR INSTRUCTIONS). I will now turn the presentation over to Mr. Gary Russell, General Manager of Investor Relations. Please proceed, sir.

Thanks, Jen, and good morning to everyone who's participating on the conference call; we welcome you, we're glad that you're here. With me today Jim Mulva, our Chairman and Chief Executive Officer, and John Carrig, Executive Vice President of Finance and our CFO, are here with me today.

Jim is going to be taking you through a presentation that we believe will help you understand more fully the financial and operating performance of the Company during the first quarter of this year. The presentation, as always, you can find on our website, www.ConocoPhillips.com.

If you please turn to page 2, our normal cautionary statement, basically says that during the presentation this morning and in answering your questions, we will be making forward-looking statements that are based on our current expectations and those expectations could be materially different than actual results. You can find the items or the issues that might cause those differences in our SEC filings. So I'll now turn the call over to Jim Mulva.

Okay, Gary, thank you and I appreciate all of those who are participating in our conference call. My comments are going to start on slide number 3. In the first quarter net income was $4.1 billion. We generated $6.6 billion of cash from operations; debt-to-equity ratio was 19%. During the quarter, as we outlined previously, we purchased $2.5 billion of our stock. So if you go back and look back to the first quarter of '07 we've reduced our average shares outstanding by 5.2%. I have a slide here a little bit later to talk about that.

Upstream business we've produced 2.25 million BOE a day, that includes 459,000 BOE a day which is our estimate of production coming from the LUKOIL investment segment. On the downstream our crude processing capacity utilization was 89%, that's down from 95% in the fourth quarter last year. And during the quarter we announced a 15% increase in our dividend, so go back to 2002 we've been increasing our dividend at in average annual rate of 15%.

So I'm going on to slide number 4. You see our first-quarter net income $4.14 billion or $2.62 a share, that was $230 million less than the fourth quarter of last year which was $4.37 billion shown on the left hand side of the chart. As we move along toward the right from the left hand side of the slide, you can see we had an $88 million improvement from the results of our asset rationalization program when you go from one quarter to the next.

And we had prices, margins and other market impacts help us this quarter to $269 million. This benefit was more than offset by the impact of lower volumes in both upstream and downstream that reduced our first-quarter net income by $283 million.

The tax impacts which are mainly the absence of the fourth-quarter benefits including a onetime E&P item related to the Canadian tax rate change and then there was another in Chemicals which was related to a capital loss -- these two things reduced net income $436 million when you compare this quarter to the fourth quarter of last year. Then there were other items that in the aggregate improved first-quarter income $130 million. These included lower controllable costs or impairments or net interest expense, but this was partially offset by the absence of a fourth-quarter benefit related to the extinguishment of the Hamaca -- that's the Venezuelan Hamaca project financing.

So we'll discuss these variances in more detail in our subsequent slides, so I'm going over to page 5 or slide 5 and we'll be including this in our future conference calls because we've been buying quite a bit of shares each quarter now. And if you look at the chart on the left you can see that we've reduced our average shares outstanding 87 million shares, about 5% compared to the first quarter of last year. Looking at the chart on the right, that reduction in average shares outstanding improved our first-quarter earnings by about $0.14 compared to last year.

I'm moving on to slide number 6, total company cash flow. If you start on the left hand side you can see that we generated $6.6 billion of cash from operations this quarter. So with this cash we funded the capital program of $3.5 billion, paid $730 million in dividends and reduced debt $195 million. You can see we purchased 2.5 billion of our shares. We also had $335 million from asset sales and other sources, left us a cash balance end of the first quarter of $1.4 billion, pretty similar to what we started the quarter with.

So now I'm going on to slide number 7, the capital structure of the Company. You can see on the left our equity grew to $91 billion. Our debt balance shown in the middle part, slight reduction. We ended the quarter at $21.5 billion of balance sheet debt. You can see our debt ratio on the right at 19%.

So now moving on to slide number 8, we start talking about E&P. Our worldwide realized crude oil - natural gas prices were higher this quarter than last. In the first quarter our realized crude oil price was $92.88 a barrel, that's $8.35 a barrel higher, and our realized natural gas price was $8.03 an MCF, that's $1.37 per MCF higher. Our E&P production and sales volume were somewhat lower than previous quarter and we'll talk about that more in the next slide which is slide 9.

Production in the first quarter from E&P was -- from our E&P segment -- was 1.79 million BOE a day, consistent with what we gave in our guidance. This is 41,000 BOE a day lower than the fourth-quarter production of 1.84 million BOE a day and that's reflected in the gold bar on the left hand side of this chart.

So if we move along toward the right, production in the lower 48 was down 61,000 BOE a day and that's largely due to the unplanned shutdown of a nonoperated natural gas processing facility in the San Juan basin. And then also the absence of a onetime NGL volume adjustment that we had in the fourth quarter last year.

Production in the Timor Sea was up 14,000 BOE a day, that includes improvement of 19,000 BOE a day due to the completion of fourth-quarter planned maintenance and 5,000 BOE a day reduction due to the impact of production sharing contracts. Then there were other items that increased first-quarter production 6,000 BOE a day as compared to the prior quarter. Then you add our equity share of LUKOIL production and so that totals 2.25 million BOE a day in the first quarter.

Now I'm moving on to slide number 10 about the income of E&P. Net income in the first quarter was $2.9 billion, compares to $2.6 billion in the fourth quarter last year. So start on the left you can see we had lower gains from our asset sales program that reduced our first-quarter income $17 million, and we have prices and other market impacts improved income $743 million, had lower production sales volume reduced income $168 million and we had tax impacts which were discussed earlier reducing first-quarter income $283 million.

So there are a number of other items in the aggregate that helped us by $4 million this quarter and they included benefits of lower impairments, lower controlable costs, lower DD&A which was mostly offset by the absence of that fourth-quarter benefit from Hamaca project financing.

I'm moving on now to the downstream, slide number 11. Our global capacity was 89%, now that's down 6% from last quarter. On our domestic capacity our utilization was 90% and that's 6% lower than the previous quarter and that's due to higher planned maintenance in our refineries on the East Coast and then we had the unplanned downtime at some of our refineries on the Gulf Coast.

Now our international utilization was 86%, that's also 6% lower than last quarter and it's due to weak hydro-skimming margins that led to run reductions at our Wilhelmshaven refinery in Germany. Now with respect to Wilhelmshaven, for a good share of the first quarter the hydro-skimming margins were below $2.00 a barrel, which is lower than our cost to operate and therefore we made run reductions.

And we saw similar market conditions in several regions in the U.S., in particular on the Chicago and San Francisco as well as certain parts of the East Coast where refining indicators were below operating cost for some of the time periods during the first quarter. In spite of these conditions we chose to optimize our refinery -- refining operations than to make significant run reductions.

Our realized worldwide refining margins were lower this quarter than last. U.S. margin was $8.00 a barrel, now that's $3.56 a barrel lower than the fourth quarter and the international margin was $6.42 a barrel and that's $0.30 a barrel lower than the fourth quarter. And then our U.S. realized marketing margins were down $0.25 a barrel.

Now going to the next slide, the refining and marketing net income slide, you can see that in the first quarter our income was $500 million, that's about $600 million lower than the fourth quarter from $1.12 billion and that's shown on the left hand side of the chart. Then as you move from the left to the right you can see we had the benefit of asset rationalizations in the first quarter, it helped us $105 million. And however prices, margins and other market impacts reduced first quarter a little over $600 million compared quarter to quarter.

Now the largest portion of this variance relates to the absence of fourth-quarter benefits from our planned crude and refined product inventory reductions. So during the first quarter this year we were building inventories in anticipation of the switchover to summer grade gasoline, we just routinely do that. In addition, we had operating problems through most of the first quarter with respect to our FCC at the Humber UK refinery and that reduced clean product yield and certainly impacted negatively margins and income.

So overall our volumes in R&M were lower than the fourth quarter, that reduced net income $127 million. It's mainly due to lower utilization, as I talked earlier; reduction in our ownership of the Borger, Texas refinery from 85% to 65%, that's consistent with our joint venture agreement with EnCana. And then there are other items that in the aggregate improved income by $21 million and that included lower operating costs and somewhat offset by higher taxes.

I'm now going to go on to slide number 13, the other segments. Our estimate of first-quarter equity earnings from LUKOIL is $710 million, slightly higher than last quarter which we estimated at $649 million. It's primarily due to higher estimated realized prices for crude and refined products and to some extent offset by higher export tariffs and extraction taxes.

Our earnings reflect that we own 20.6% of LUKOIL. In the second quarter we expect our ownership to go back down to 20% and this is a result of LUKOIL's issuance of treasury shares with an acquisition they made, the purchase of a power company in Russia. Income from our Midstream business was $137 million, that compares to $162 million in the fourth quarter and it's down primarily due to lower realized NGL prices. And our Chemicals joint venture contributed $52 million, a little bit higher than previous quarter after you adjust for this onetime capital loss tax benefit of $65 million in the fourth quarter.

So after the adjustment the higher income is mainly due to better olefin and polyolefin margins. And then the Emerging Businesses contributed $12 million in the first quarter compared to $2 million in the last -- reflects primarily improvements in income from our Immingham plant in the United Kingdom. This improvement is mainly the result of higher spark spreads somewhat offset by unplanned downtime. And our corporate costs, $170 million, that's $92 million less than the fourth quarter, it primarily lower interest expense and reduced losses from foreign exchange.

Then we go on to slide 14, we look at our E&P metrics on a BOE equivalent and we compare that to prior periods of time. And then when we use the peer group in all of our slides like in the past, our peer group is made up of the large international oil companies -- that is ExxonMobil, BP, Shell, Chevron and Total. Obviously we don't have the information yet because they haven't reported in the first quarter of '08.

So the top of the chart shows income and cash per BOE, it goes from 2003 all the way through the first quarter of '08. The effective purchase accounting certainly negatively impacts our earnings per BOE because about everything that we've done in the past in terms of acquisition mergers with purchase accounting. But you can see that our cash contribution continues to be very competitive, as does the income contribution.

So we go from E&P then to the next slide which is refining and marketing and it's for the same peer group and the same time periods of comparison. Obviously the downstream has been under pressure because of the market conditions, but we think we will see that our income and our cash per barrel will continue to be competitive with the peer group.

So now I'm going to us move on to slide 16, return on capital employed, again, the shaded area in the back on this slide represents the high, the low of the peer group that I previously mentioned and the bar chart reflects our return on capital employed. There are no adjustments for purchase accounting, adjustments [married] to the peer group reflect purchase accounting for them, we always include as an attachment in Table 3 to the presentation and then you can see for the first quarter of '08 our return on capital employed is 15%, it's 1% higher than for the annual number last year of 2007.

Now I'm going to the last slide that I have under outlook and we made a number of announcements and developments in our company that, first, we're quite pleased to be working with BP on the development construction of the gas pipeline that moves natural gas from Alaska's North Slope through Canada to the lower 48. Ultimately the pipeline will move 4 billion cubic feet of natural gas to the markets in North America, the lower 48. We're pleased to be underway with developing this project.

Then in addition, we were a successful bidder on several prospective leases in Alaska's Chukchi and the Gulf of Mexico recent lease sales. And this is an important step in the development of our exploration portfolio. And then we look to the second quarter, we expect the Company's E&P segment production will be lower than the first quarter and this is a result of seasonal planned maintenance. But for the full year 2008 production we expect to be consistent with our operating plan as we outlined at the March New York analyst meeting.

Our second-quarter exploration expense is to be about $250 million. In the downstream we expect crude capacity utilization to be in the lower 90% range in the second quarter; this reflects primarily some planned maintenance at several of our facilities. And also taking into consideration the potential of ongoing weak hydro-skimming margins at our Wilhelmshaven refinery.

Our second-quarter pretax turnaround costs will be about $175 million and we expect our share repurchases in the second quarter will be like the last several quarters, between $2 billion and $3 billion which is in line with our plans to complete $10 billion in share repurchases for calendar year 2008. So that completes our prepared remarks and so now, John, Gary and myself will respond to questions and observations that you may have of our performance.

Okay, Jen, I think we're ready for our questions.

(OPERATOR INSTRUCTIONS). Doug Terreson, Morgan Stanley.

Good morning, guys. Congratulations on your record results. In the Middle East, the Shah Gas Project would obviously represent an important and positive development. And while you guys have experience on projects of that nature I was wondering what two to three factors do you feel differentiate ConocoPhillips as it relates to the selection on that project then. And also, while I realize that it's very early, the path forward that's ahead of us on development of this project during the next 12 to 24 months?

Well, we do have experience in handling sour gas and, of course, this is a very attractive project, very large project technically and challenging for any company and also for ourselves. We've been very interested in pursuing this project. Nothing has been formally announced, but we continue to work very closely on all the aspects of this project with ADNOC.

So we would expect hopefully in the next month or so that we could be making a formal announcement going forward on this really important project for our company. We think our approach towards this project is pretty innovative, both on the technical aspect as well as the commercial aspect. As I said, Doug, we've been working on this for actually several years and this is really a good important one and, hopefully as I said, I'm optimistic that we'll make some formal announcement on this here in the next month or two.

Okay, I see. And then also, Jim, you guys were successful on almost 100 tracts in the Chukchi Sea. And while I realize that you wouldn't be involved if you were not optimistic, my question is how optimistic are you in that area and also the next steps as it relates to drilling and development in the Chukchi Sea?

Well, we have 10-year leases. We feel that we really know the area quite well. This goes all the way back to the historic presence of ourselves through ARCO Alaska and of course we have the benefit of that and the experience. We think that a lot of the things that we see in the Chukchi is similar to what we see in the North Slope of Alaska, even though the 10-year leases we have to get underway pretty quickly.

So we are working really hard both on the technical side, but also ultimately the lining up that we will be doing our drilling as soon as we can. But we have the infrastructure in Alaska and we're really pretty pleased about this promising area. And as you know, several wells have already been drilled out there. So we know that we're in hydrocarbon province.

So it really fits in really well for us to develop our exploration portfolio, but it also helps as we continue to look at exploitation of the oil resources we have, then the gas pipeline from Alaska, and then Chukchi really hopefully being successful sets us up for many decades to come in Alaska.

Sure. Congratulations again.

Arjun Murti, Goldman Sachs.

Thank you. Jim, I realize the analyst meeting was only about six weeks ago, but even since that time oil prices have continued to move higher and I think general confidence in the bullish natural gas outlook in the U.S. has improved. Can you comment on how you're thinking about capital spending over the next year or so? I think relative to your $15 billion budget you've talked about potentially plus or minus $1 billion around that. How do you guys think about capital spending now in light of commodity prices?

Thank you. Yes, I mean we see an environment that's pretty surprising to ourselves in terms of very robust oil and gas prices. But our capital spend as we look at 2008, 2009 is still going to be around $15 billion. It may be because of cost pressure or some other unique opportunities might be up $1 billion or $2 billion -- maybe $1 billion this year, maybe $1 billion or $2 billion next year. But we're really thinking about $15 billion or $16 billion.

As we said, the priority is not debt reduction. We're very satisfied and think we've got the right capital structure. So if we find that we have more cash flow it's not really going to be going towards capital spending, it's going to be going towards more distributions to the shareholder in the form of share repurchase.

That's really helpful. One follow-up. On your lower 48 gas production, it had been pretty steady between 2.1 and 2.2 BCF a day. It looks like it fell a little bit in the first quarter. Is that natural declines or is it some one-off affects and would come back to a higher level going forward?

I think it primarily goes back to the San Juan gas processing plant that was down. That is a real significant impact to our natural gas production in the lower 48 and it's really the primary reason why we are somewhat less on the total company's BOE production.

That's right, thanks for reminding me about that. The last question was just on the Alaska gas pipeline. Can that substantively move forward without Exxon's participation?

Obviously it makes a lot of sense for all of us to be a participant, so we continue to work very closely obviously with BP, but we also work closely in everything that we do with ExxonMobil. So hopefully in time I would like to see and would expect and hopefully that all three producers are part of the project.

That's great. Thank you very much.

Michael LaMotte, JPMorgan.

Good morning. A quick follow-up on the San Juan. Is it back up now? Is there going to be any impact in the second quarter?

That's back up and running and I don't think there's any impact in the second quarter.

Okay. And then to return to this question of CapEx briefly. Help me perhaps understand a little bit better the returns trade-off, if you will, between increasing CapEx on the upstream side and increasing the buyback. I would imagine with the higher commodity prices that the returns have to be pretty good in the upstream. Certainly the returns that we're seeing from the independent producers in the lower 48 would suggest that. How do you all view it? Clearly excess cash goes to the buyback, but if I look at returns of the buyback program versus CapEx, what's the thought process there?

First of all, we don't give up the optionality of doing any of the drilling in the future. The question is when do we want to capture those opportunities. Do we want to do them today or do we want to do them a year or two from now? We like the discipline of the share repurchase. We think the purchase of shares is a very attractive investment opportunity for the Company. And then we also want to make sure that we're concerned that the service industry and our own people, that we have the oversight of doing this really well.

So where you never give up the opportunity -- the option of drilling the wells and adding to the production, it's really a timing question. Take all of those things into consideration and that's why we'll drill these wells, but it may not be this month or this year, it may be next year.

That's helpful color, thank you. And then on the service side in particular, a couple of your peers in the lower 48 have talked about -- after several quarters of falling services costs -- have talked about stabilization. I'm wondering if you're seeing the same thing and if there's an opportunity to perhaps go long in terms of contract duration to try to stave off any potential reinflation in service costs over the next few quarters?

That's difficult for me because I'm not as close to it as our operating people on what we're seeing on the cost side. I think there might be in some unique areas a little bit of moderation in escalation or cost. That's good, we'd like to see it go quite a bit further. But I don't know. John, do you have anything more to say on that?

No, we tend to look at it where we have long-term utilization needs we'll go a little bit longer. But we do see some moderation, whether it has an uptick as a result of the recent surge in gas prices remains to be seen. So we try to manage the cost structure across the board, some long, some short, but by and large we're current with prices.

And historically we don't go out and line up long-term rate contracts.

Okay. The last one for me on the downstream -- Jim, perhaps you could provide some color on what the biggest differences are in ethanol's impact in the gasoline market this year versus last year?

Well, obviously there's more ethanol and that is a substitute for volumes and we see that. We also see that there's some indication of reduced demand because of the cost side of it. For these reasons obviously we do see some impact, particularly on the gasoline side of the business. As you know, the margins and the crack spreads are very strong on the distillate side of the business, not strong on the gasoline side of the business, so you can see that that does have impact with respect to ethanol as a substitute and as well as demand in terms of the cost structure of gasoline.

Is there a notable difference this year in terms of the distribution and logistics around ethanol versus last year, risk of dislocations to gasoline markets and potential spikes here in the second quarter, because --?

I don't think so, but maybe we could come back and talk with our people and respond back to you off-line.

Okay, great. Thanks so much. That's it for me.

Paul Sankey, Deutsche Bank.

Good morning, gentlemen. A follow-up on Alaska if I could. I think you talked about $30 billion for that pipeline. Could you, to the extent that you possibly can, talk a little bit more about how you get to that number and about the time frame there?

Well, really, this is on the basis of an old study several years ago and that's one of the things that we really are working on very hard over this next several years with BP and that is just what is the cost structure going to be as well as the engineering, the environmental, the permits. We're working towards open season, so there's no basis, it's really old numbers. We're going to have to do the work to come up with the new basis of what we think is the cost structure.

Jim, I was with John Carrig not long ago and I think he was saying that almost from the point of construction starts it's going to take 10 years to build. Are we literally that far away from this thing ever delivering?

I'm not going to dispute what John said in any way, he's sitting right next to me. But on the other hand, yes, from the time we are right here we're looking at 10 years, maybe a little bit longer than 10 years. By the time you go through all of the study work and engineering and permitting and then going through with the open season and then the construction of the pipeline, we're looking at 10 plus years. But we've got to start now which is what we've done with BP.

And I think, Jim, what you're saying is $600 million over what time frame with BP is that just on the initial work?

In the next year or two -- the next two years plus.

Thanks. In the past we talked about Mackenzie Delta coming first, could you update us on that pipeline?

Well, we continue to work that really closely with partners and with the regional authorities and all. I will just say I'm pretty optimistic, I think we're going to see something hopefully happen as we go through 2008 on the Mackenzie Delta pipeline. And I think Mackenzie Delta will come before Alaska. This makes a lot of sense. I know it's very important for the partners, it's important for Canada, but I think sequencing in terms of purchase of steel and use of services to do these pipelines it makes sense for Mackenzie Delta to come first (multiple speakers). And it's further along than the gas pipeline in Alaska.

Right. The tentative date there -- are we five years away?

I don't know. Maybe we could talk to our people and come back to you on that.

Thanks. A very brief one on the downstream. You've talked about a guidance for how much utilization you'll have in 2Q. How much of that is the required turnaround work and how much of that is the voluntary shutdowns that you've talked about? In other words, what would you be running at if we were in a strong crack environment?

I think everything -- we have quite a bit of planned maintenance as we do in the second quarter. In terms of what's impacting -- that impacts our utilization. Normally we run 95% or so, so when we say the low 90s we're taking into consideration planned turnaround. I think really the only facility -- we expect to run everything other than planned turnarounds other than Wilhelmshaven and what we're really saying is we're underway with making that a very sophisticated refinery, but until we do so that's the one that's going to impact utilization. It's really Wilhelmshaven.

And finally, Jim, is that then totally shut down, Wilhelmshaven not running?

No, no, no, we make run reductions.

It's a run reduction story, okay. So we can kind of strip out 50% of Wilhelmshaven's capacity perhaps in terms of (multiple speakers)

I don't know what percent it is, but there are times that we have accelerated turnarounds that have -- I think this past year we went almost to a full shutdown that we were doing maintenance. But normally we make run reductions, we don't shut the facility down completely.

Thanks very much, Jim.

Nikki Decker, Bear Stearns.

Good morning. So on the Denali project, I'm just curious, have you had discussions yet with the Alaska legislators and what is the status of the AGIA program? Is that ongoing?

Well, we talk with everyone, both the federal government, Canadian authorities and we certainly talk with Governor Palin, her administration, the legislators, everyone up in Alaska. And so the AGIA process continues to go. But as the Governor indicated, seeing ourselves going forward with BP and hopefully in time with Exxon Mobil. The AGIA process has been helpful to move everything along, so I give credit to the governor.

But what the governor has said and what we hear from everyone in Alaska, they're very pleased that BP and [ourselves] are moving out on this gas pipeline. So what it really is saying is there's certainly far more certainty that this project is going forward and it's going to be done.

Okay. But there are two proposals on the table right now, the AGIA proposal that I think TransCanada is heading up and your proposal?

Well, the Governor and the state legislature are going to have to sort through how they handle AGIA. But what we've announced is -- BP and ourselves, we're going forward with our project. It's not dependent upon funding from anyone, it's not dependent upon any approval by the state or the legislature. We're going forward with the project and we think, given our history and our knowledge and given that we are producers, we think we are really the right project to be going forward to see this pipeline come with certainty.

Okay, thanks. And secondly, operating costs seem to have stabilized this quarter, which is somewhat surprising given the higher commodity price environment. Can you comment on whether that is the case and maybe whether it's a product of the environment or more due to self-help? And particularly my observation is in the downstream where I think you made some comment, Jim, on lower operating costs quarter over quarter.

What we've been doing is everywhere we can, but let's talk about the downstream. We're trying to use productivity improvements, efficiency, whatever to hold our cost structure on an absolute basis constant. But if you're having some unplanned turnarounds that gets hard to do on a per unit cost. But what we're really try to do, as we outlined in the York analyst meeting, we're trying to hold our absolute cost structure flat as we go through the next several years.

On the upstream, if you look at our charts and all, it looks like -- certainly looks like the income and the cash flow came to the bottom line far better in terms of our upstream than in the fourth quarter. But in the fourth quarter we had a lot of unusual items. First quarter this year was really very, very clean, just a few discrete items that you can see.

But all of us in our industry but certainly in our company, a lot of emphasis on let's make sure we minimize our lost profit opportunities, let's be on top of our cost structure. But we continue to see push in terms of escalation, and foreign locations are not helped by the weakness of the dollar. But I think we are doing everything we can to constrain our cost, and maybe just starting to see that in the operating results in the first quarter.

So getting back to the downstream, could you provide some detail on the lower operating costs?

I will get back with you, Nikki. I can do that.

Okay, I appreciate it. Just one last one, where was the asset sale in the downstream? Was that domestic or international?

It was mainly retail locations domestically.

Okay, great. That is all for me. Thank you.

Paul Cheng, Lehman Brothers.

Thank you. Gentlemen, Jim, when we are talking about Chukchi in Alaska, can you tell us what kind of drilling program that you have in mind and in terms of the time frame and how many wells you're going to drill?

Also I know it is early days; any kind of rough idea of how big is the structure over there compared to, say, Prudhoe and any kind of estimate or insight you can provide?

First of all, what I referred to earlier in our call, I don't know exactly what the drilling program will be, but given 10 years and it takes a lot of time to do things, many years, we just know that we have to get underway pretty quickly on the drilling of the first well or two. And maybe our people will come out and we can get you some more information on that. I don't have it readily available to me.

Now given obviously we have to have some pretty large structures out there, because it's a challenging, tough environment. So they're quite expensive, so we expect to see some pretty large accumulations otherwise we wouldn't be bidding the way we did or in this 10-year time frame. So I really don't have more that I can pass along than that.

I see, okay. On the Saudi Aramco refinery project, any update there?

Well, we continue to work really closely with Saudi Aramco. I think we're starting to move up towards 20% of engineering completed. I think in the next few months -- in the next two or three months you'll hear exactly what we're going to do on Yanbu. But hopefully we can get to a position ourselves with Saudi Aramco to announce that we're going forward with it. But it's premature to do that, but we continue to work technically and commercially really well with them. I think you'll hear more on this as we go through this next quarter.

And Jim, any update on Sunrise?

Sunrise? No, I know that Woodside and Shell, we continue to be exploring all the different opportunities whether to do that offshore or to do that by way of coming to Darwin or going to East Timor, we continue to progress that work both technically and commercially. I'd like to think -- I don't have anything right in front of me, but I'd like to think as we go into the latter part of '08, early '09 that we get to a position where we make a decision on just what we want to do on Sunrise.

Okay. Two final short questions. I think this is probably for John. John, at the end of March, your production or inventory is under (inaudible) or over (inaudible) for the corporation?

Production for the first quarter was --.

By the end of the first quarter because, I mean, first quarter could be under (inaudible) or over (inaudible), maybe it's coming from residual on last year. So I just want to know that at the end of the quarter from an inventory standpoint are we over (inaudible) or under (inaudible) at that point?

I don't have a number of barrels on the water for you. We can try to get back to you on that, but overall sales were less than production for the quarter.

Yes.

We ended last year pretty close in balance, so if anything we're close to right in balance or a little bit less sales than production.

So we should expect, if everything else is equal, that the second quarter should be a little bit higher sales than the production going in?

Assuming that the end of the second quarter doesn't have barrels on the water that would tip that in the opposite direction.

Sure. And John, in your analyst meeting you were very kind to provide what is the full year Company expense, with the first quarter result out. Any update on that number?

No, we estimated that the corporate would be $1.2 billion for the year, so that's $100 million a month and we don't see that changing -- that monthly rate changing on average.

Okay. Very good. Thank you.

Mark Gilman, Benchmark.

Good morning. A couple things. Jim, can we assume that really, Alaska gas pipeline project, that you and BP have essentially relinquished the conditionality that was in place previously regarding tax and fiscal certainty?

We're just going forward with -- we know that at some point in time we're going to have to talk about the fiscal situation that applies to the gas pipeline. But nothing is tied to anything in the past, we know at some point in time, though, once we go through engineering and permitting and all that we're going to have to sit down with the state and discuss that.

So that's still an open issue?

It's an open issue.

Okay. Secondly, a question for John Carrig. I noticed that we've seen a very steep downtrend in pretax interest expenses going all the way back toward the very early part of last year that's disproportionate with the decline in debt over the same period. Have you dramatically changed the financial structure, shortened up the maturity curve, if you will, to account for that or is something else responsible for it?

No, we might be a little bit more short-term oriented versus long-term, but our fixed to floating ratio is not that dramatically different. The floating rates have been positive and because of the cash performance of the Company we've had somewhat higher interest income during these periods.

I was focusing strictly on expense, John.

Well, I was focusing on net expense as well. But the gross expense, no, there are other factors that get into that number but, no, we haven't changed the financial profile of the Company dramatically.

John, in a way the off balance sheet financing and debt is about the same -- balance sheet is about the same, so --.

Yes, it would come into the fixed floating ratio, but there are tax accruals and other things that get into that interest expense number.

Okay. Just one other one for me. I can't help but noticing what's become the rather staggering difference between your equity and earnings of LUKOIL and the cash that would be allocable to your proportionate interest. I make this observation in the context of LUKOIL's apparent announcement this morning regarding a dividend increase. But it still seems as if their payout ratios are comparatively low. Are you lobbying at all, Jim, to try to get that payout ratio up so that you can monetize your interest to a somewhat greater extent from a cash standpoint?

Are we lobbying? Well, we continue to talk and discuss. You make a good observation. Our investment regained -- all the earnings aren't paid out -- it has a rather low payout. On the other hand, I do see Vagit Alekperov pretty routinely. We talk about the Company and of course what they have is a lot of opportunity for investment and they want to continue to fund their investments versus aggressive payout. But we talk about it. But I don't think you're going to see dramatic changes in what LUKOIL is doing.

Okay, thanks, guys.

Bernie Picchi, Wall Street Access.

Good morning. Jim, you've sort of alluded to this as the Achilles' heel of your worldwide refining system, at least in the current environment, has been Wilhelmshaven. Can you to discuss where you stand with regard to the equipment operating, if anything can be done to sort of accelerate the upgrading at Wilhelmshaven? And then also two or more years, I guess, into the acquisition could you critique that acquisition vis-a-vis your expectations for Wilhelmshaven at the time that you entered into the agreement?

Okay, we bought Wilhelmshaven and we purchased it with the idea that we were going to immediately start a deep conversion project in -- I'm going to say, I can't recall, about 2006 -- or it was 2006. So when we looked at the deep conversion project we felt it was overly complex and quite expensive. So we took the better part of a year, 15 months, to rethink it. So now we've embarked upon it and proved it and we're going forward.

I wish we could do it more quickly than we expect, I can't recall the exact number but it's the better part of maybe closer to five years than four years. But we want to make sure that when we do the project that we've got this figured out and we don't get too aggressive. We don't want to just throw money at it trying to make a schedule that ends up increased cost and we don't get the schedule we want. So we want to be realistic in that regard.

Now if you look at the acquisition cost and the cost of what it's going to take to do this, there's no doubt in our mind that even at today's crack spreads and margins this has been a good investment. Now we wish that we made a sophisticated refinery out of it within three years or two or three years, but we can't do it that quickly. And when we use modest normalized crack spreads, whatever you want to say those are, we're looking at a rate of return unlevered in the midteens. Therefore it makes a lot of sense for us to do this project.

Okay, very good. Just a follow-up question to the question that John was asked about the operating corporate costs. Basically I think, John, what you were saying was that the $170 million corporate item that you're showing for the first quarter is kind of an anonymously low number, that you would guide us to use something closer to $300 million a quarter?

Yes, we think that's probably better. You should use the $300 million a quarter. Hopefully we can do better than that, but that's what you should use.

Thank you.

Erik Mielke, Merrill Lynch.

Good morning. Thank you for taking my question. I have a couple of hopefully quick ones. Would you mind giving us a quick update on some of the key projects that you're developing in 2008, particularly Britannia satellite and the Timan-Pechora project with -- YK Project in Timan-Pechora with LUKOIL?

The YK Project, I think we're getting close to the first -- we have the first production or a small amount of production, so that's going right as we scheduled and outlined at the analyst meeting. What was the other part?

BritSat.

BritSat. Well, we've got quite a schedule in terms of how we're getting ready to bring that on stream and I think we're looking at no difference in what we said, production in the -- Gary, it's the third quarter isn't it? Third quarter of this year is production from BritSat?

That's the expectation.

So no change.

No change.

That's great, thank you. The LUKOIL number that you reported for 1Q, is that a clean number? Was there a fourth-quarter catch up involved as well?

There was a modest what we call true-up, but not overall significant.

Thank you. And on the Shah field that you're negotiating in Abu Dhabi, I know obviously you can't comment on the economics given that you haven't signed anything yet. Can you perhaps give us some guidance on where you see the economics in the project, gas versus liquids versus sulfur -- particularly in light of some of the stories that have been in the industry press?

As we've indicated, we felt that what would distinguish our company and how we competed hopefully for this opportunity was a rather unique bid, both in terms of technical bid as well as a commercial bid. And it's not appropriate, first, we have not been formally awarded this project and I think for other reasons it's not appropriate at this time for us to get into how that would be done.

But I think assuming that it goes forward, we're named with a formal announcement in the next month or two, you could expect here in the next quarter conference call, if we follow that schedule, we'll talk quite a bit more about the project and what are the drivers and what we see in it.

Very good. Final one for me is on share buybacks where you were pretty explicit about if you have additional free cash during the quarter 2008 you'll be more likely to be handing that back in the form of share buybacks. Would that be a fourth-quarter event? Would you wait until the end of the year before seeing where cash flows are? Could you conceivably accelerate buybacks during Q2 and Q3?

Well, I don't think you're going to see it in the second quarter, probably not even in the third quarter. But that's something that's very tactical we'll have to address and see. What we've really set up for the Company is we come out in the fourth quarter in December and we say, okay, we pretty well finished the year, here's what we expect, what we're going to approve and go to our Board for approval on the capital program for 2009. And with that we will be making announcements to what we see the share repurchase for 2009.

So we like the idea of doing this on an annual basis. We recognize that a question came from Arjun Murti, what would happen if you have a little bit more cash flow, what would you do? It's really the timing. We'll look at our capital program, but if we have more cash for share repurchases, a tactic question is when we would do it.

But we like the idea of making an annual announcement on share repurchase because that's pretty finite. Instead of saying something for three to five years, we say here's what we're going to do next year and then it's pretty clear with discipline that's what we are going to do and the marketplace and the shareholders look at it and say that's what we expect you to do. So that's really the plan of what we'll probably do.

I wouldn't disagree with that. Thanks very much.

As there are no more questions in queue I'll turn the call back to management for closing remarks.

Thanks, Jen. We do appreciate everybody's interest and participation on the call this morning. We remind you that, again, the presentation that we went through this morning is available on our website. And soon we will also include a transcript of the conference call there as well. Again, the website is ConocoPhillips.com and we appreciate your participation and wish you a good day.

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

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CAUTIONARY STATEMENT FOR THE PURPOSES OF THE "SAFE HARBOR" PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995

This transcript contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended, which are intended to be covered by the safe harbors created thereby. Forward-looking statements relate to future events and anticipated results of operations, business strategies, and other aspects of our operations or operating results. In many cases you can identify forward-looking statements by terminology such as "anticipate," "estimate," "believe," "continue," "could," "intend," "may," "plan," "potential," "predict," "should," "will," "expect," "objective," "projection," "forecast," "goal," "guidance," "outlook," "effort," "target" and other similar words. However, the absence of these words does not mean that the statements are not forward-looking. Where, in any forward-looking statement, the company expresses an expectation or belief as to future results, such expectation or belief is expressed in good faith and believed to have a reasonable basis. However, there can be no assurance that such expectation or belief will result or be achieved. The actual results of operations can and will be affected by a variety of risks and other matters including, but not limited to, crude oil and natural gas prices; refining and marketing margins; potential failure to achieve, and potential delays in achieving, expected reserves or production levels from existing and future oil and gas development projects due to operating hazards, drilling risks, and the inherent uncertainties in interpreting engineering data relating to underground accumulations of oil and gas; unsuccessful exploratory activities; potential disruption or unexpected technical difficulties in developing new products and manufacturing processes; potential failure of new products to achieve acceptance in the market; unexpected cost increases or technical difficulties in constructing or modifying company manufacturing or refining facilities; unexpected difficulties in manufacturing, transporting or refining synthetic crude oil; international monetary conditions and exchange controls; potential liability for remedial actions under existing or future environmental regulations; potential liability resulting from pending or future litigation; limited access to capital or significantly higher cost of capital related to illiquidity or uncertainty in the domestic or international financial markets; and general domestic and international economic and political conditions; as well as changes in tax, environmental and other laws applicable to our business. Other factors that could cause actual results to differ materially from those described in the forward-looking statements include other economic, business, competitive and/or regulatory factors affecting our business generally as set forth in our filings with the Securities and Exchange Commission (SEC). Unless legally required, ConocoPhillips undertakes no obligation to update publicly any forward-looking statements, whether as a result of new information, future events or otherwise..

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