康菲 (COP) 2009 Q2 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the second-quarter 2009 ConocoPhillips earnings conference call. My name is Keisha and I will be your operator for today. At this time, all participants are in listen-only mode. We will conduct a question-and-answer session towards the end of this conference. (Operator Instructions). As a reminder, this conference is being recorded for replay purposes.

I would now like to turn the call over to Mr. Clayton Reasor, Vice President of Corporate Affairs. Please proceed, sir.

Thank you, Keisha. Good morning to everybody and welcome to ConocoPhillips' second-quarter conference call. Joining me this morning is our Senior Vice President of Finance and CFO, Sig Cornelius.

Earlier this morning, we issued our earnings press release, an updated supplemental information package and posted the slides we will be using on this teleconference. You can find this information on our Website. You may have noticed that we made some changes from what we've shared over the past several years regarding the content of our earnings release and the conference call slides. These changes were made with the intent to be more consistent with our SEC filings without reducing the information you've received in the past. The most significant change is the use of year-over-year rather than sequential variations as the basis for discussing our most recent quarterly results.

Before we get started, I need to direct you to our Safe Harbor statement on page 2. This is our standard reminder that we are going to use forward-looking statements that may be made during our presentation in response to questions you may have and our actual results may be materially different than the answers we provide today. The sources of those material differences can be found in our filings with the SEC.

So now I will turn the call over to our Senior VP of Finance and CFO, Sig Cornelius.

Thanks, Clayton. I will start my comments on page 3, which shows a summary of our key operating and financial performance for the quarter.

Earnings for the quarter were $1.3 billion or $0.87 per share with cash from operations of $2.6 billion. We ended the quarter with debt of $30.4 billion resulting in a debt to capital ratio of 34% which is flat versus last quarter. Operationally, we delivered strong results. Compared to last year, E&P production was up by 7%. In addition, operating costs across the Company were down by more than 15% due to market improvements and other cost reduction initiatives. Although these factors are positive, the combined impact of continued low North American natural gas prices and weak realized refining margins created significant headwind for us.

Turning now to page 4, total earnings were down by 76% compared to last year. The slide shows changes in the various reporting segments. The biggest decrease was in our E&P segment, driven by lower oil and gas prices. Prices and margins were also the largest driver in our downstream segment and resulted in a loss of $52 million compared to earnings of $664 million last year.

For all segments, prices, margins and other market impacts decrease our earnings by nearly $5.4 billion in aggregate. This was partially offset by higher volumes primarily in our E&P segment and after-tax cost reduction benefits of more than $450 million across the company.

Page 5 speaks to our cash flow performance. We generated $3 billion of cash from operations excluding working capital changes. Working capital increased by $400 million this quarter, primarily related to timing of tax payments. These items coupled with a capital spend of $2.9 billion and dividends of $700 million resulted in an overall debt increase of $1 billion this quarter.

I'm moving now to a review of our segment performance starting with total company production on page 6. Overall E&P production was up 7% or 122,000 BOE per day versus last year. Market factors accounted for approximately 25% of this increase. This included positive PSC adjustments and benefits from sliding scale royalty rates in Canada, which were partially offset by OPEC curtailments. Excluding these market impacts, production was up 92,000 BOE per day or a little over 5%.

In our operations category, production from new projects more than offset decline and other operational factors. We had a total increase of over 175,000 BOE per day from new developments and project startups. This includes YK in Russia; Brit Sats and other new wells in the UK;; Alvheim in Norway and Su Tu Vang in Vietnam. We are also seeing production increases from our heavy oil projects in Canada. Finally in the second quarter of this year, the new Bohai Bay FPSO came online.

When you add our share of LUKOIL production, which is an estimated 442,000 BOE per day, the total Company production was a little over 2.3 million BOE per day for the quarter.

Now turning to page 7, total E&P earnings for the second quarter were $725 million, down from $4 billion last year. The tables on the bottom of the page show the earnings variances by geographic area and changes in price realizations. On the left-hand side, you can see that the earnings variances are fairly evenly split between US and international. Moving to the right side of the table, you can see that the significant decline in realized prices year-over-year.

Compared to last year, natural gas and NGL prices were down around 60% and crude oil prices were approximately 50% lower. In total, lower prices negatively impacted earnings by around $4.5 billion. After including the price impacts on production taxes, the overall decrease was $3.9 billion, which is shown on the second bar from the left on the chart.

Although production volumes were up 7%, our overall sales volumes were up only 5%, reflecting an overlift position in the second quarter of last year. This higher sales volume resulted in an increase to earnings of approximately $650 million.

Overall operating costs are lower, consistent with our performance in the first quarter. On a pretax basis, costs were down around $275 million compared to last year. Market factors such as foreign currency and utility rates represented about 75% of this savings. The balance is due to savings and operations from lower activity levels, lower service costs, and portfolio changes, which is partially offset by higher costs for new production.

The other bar includes two special items. First, we had an impairment of $51 million for the expropriation of our Ecuador assets after we suspended operations there on July 16. In addition, we also booked a $37 million after-tax asset retirement charge related to an incident on June 8 at our Ekofisk 24W water injection platform. The other bar also reflects an after-tax increase of $75 million in DD&A predominately due to the increased production and major project startups that I referenced earlier.

The R&M earnings variance is shown on page 8. It was a tough quarter for refining as margins decreased significantly and demand remained weak particularly for distillates. Compared to last year, the overall global market refining crack spread decreased by over 40% resulting in a $1 billion earnings decrease for refining. As shown on the graph in the margins and other market impacts bar, overall margins were down by $770 million reflecting some claw back from higher relative values for secondary co-products such as coke and fuel oil.

US refining market capture was less than 50% this quarter, which is down compared to recent quarters and the second quarter of 2008. The main driver of this lower capture was low distillate margins and compressed light/heavy crude differentials. Compared to the second quarter last year, distillate cracks were down over $20 per barrel and heavy crude sour differentials tightened by more than 70%.

On the volume side, we had a 5% decrease in global refining utilization compared to last year due to continued weak hydro-skimming economics and optimization of margins based on market conditions. In addition, we also had higher turnaround activity in our international operations this past quarter.

Pretax operating costs were down around $400 million. This was fairly equally split between market factors and operational savings, which included lower turnaround costs, staff costs, and other maintenance and operating items. Included in the bar labeled Other is a non-cash after-tax impairment of $72 million primarily due to the allocation of goodwill to the pending sale of our interest in the Keystone Pipeline project.

I will now move to page 9, which shows the variances for our LUKOIL segment. LUKOIL earnings were $682 million for the quarter which is down 11% from last year. The biggest driver of the change is lower estimated prices and market impacts which account for more than $500 million of the decline and is consistent with the results we are seeing in E&P. Offsetting this market decline is a benefit from the true up of our estimated results to LUKOIL's reported earnings, which occurs on a one-quarter lag.

In the second quarter last year, we had a negative true up of $120 million compared to a positive true up of $192 million for this quarter. This gives us an overall true up delta of $312 million. The reported earnings also reflect a variance of $73 million related to basis amortization differences.

Page 10 shows the variances for all our other segments. In Midstream we experienced lower results due to significantly lower LNG -- NGL prices and lower volumes. Our share of CPChem results were $50 million higher due to cost reductions and lower turnaround activities which were partially offset by lower olefins and polyolefins margins.

Corporate expenses were $157 million after-tax for the quarter. Compared to last year, larger foreign currency gains and lower costs were partially offset by higher net interest expense.

That's completes the review of our second-quarter results. I will wrap up with some comments on our operational and strategic items that are shown on page 11. I'll start with our outlook for the balance of 2009.

As we signaled last quarter, we expect E&P production to be up slightly for the full year compared to 2008. We expect to give back some of our year-to-date gains over the next two quarters as we execute our normal seasonal maintenance programs and begin to see the impacts of reduced gas drilling activity in North America. Additionally, we are experiencing some unplanned decreases due to the Ekofisk platform incident and expropriation of our Ecuador interest.

Our global refining utilization for the balance of the year is dependent on economic conditions. In an environment like we are experiencing today, we would expect it to be in the mid-80% range average across the portfolio with higher rates in the US and lower rates internationally. We are still assuming a capital program of $12.5 billion for the year.

With respect to cost reductions, we have realized savings of around $900 million pretax so far this year, excluding exploration. This compares to our full-year objective of $1.4 billion. We set our full-year objective based on an expectation that we would see benefits from the price environment as well as operating savings from activity levels, service cost deflation and personnel reductions. So far this year, we've seen a benefit of around $800 million for market factors such as energy costs, utility rates and currency impacts. Operationally, our net reduction is around $100 million, which includes savings in our base operations, partially offset by higher costs on our new E&P projects.

Continuation of the market savings will depend on future commodity prices and currency rates. Given our current outlook, we expect to meet our full-year target.

Moving to an update on some of our projects, I mentioned earlier that new production from our major projects and developments are more than offsetting decline. The projects are performing in line with expectations and are in various stages of ramp up. We will continue to see volume increases in Canadian heavy oil projects and in Bohai Bay as we move into next year and through 2011.

In the third quarter, we expect to bring on the North Belut field which is part of our Block B PSC in the Natuna Sea. On the downstream side, we plan to commission the new hydrocracker at our San Francisco refinery during the third quarter. After the unit comes online, we will see clean product yield increase by around 15% or more and will also get a small increase in the amount of heavy sour crude that the refinery can process.

On the exploration front, we are encouraged by the promising results from our Poseidon well in the Browse Basin of Australia. Additional appraisal drilling and testing will be needed to determine the size and commerciality of this discovery. We are currently drilling the Kontiki prospect in the same area and will be going back for additional appraisal drilling on the Poseidon structure once this well is finished.

During the quarter, we executed the agreements for Block N in Kazakhstan. Our next step is to obtain seismic data with the goal of drilling in the later half of 2010 or early 2011 on this world-class prospect.

That completes my prepared remarks and I will now open the call for questions.

Okay, Keisha, I don't know if we've got some people interested in asking questions, but now would be the time.

(Operator Instructions) Neil McMahon.

Neil McMahon with Sanford Bernstein. I have just a few questions. Just looking at the Chemicals results, a little small in the overall scheme of things, has the cost-reduction there been a structural change or has it been driven more by your energy cost reduction over the first half of the year? I just wonder if it's structural versus something that could actually change based on input cost drivers. And I've got a few other questions too.

It's primarily on the input costs. There have been some structural changes flow through with the JV with Dow in the styrenics, but it's -- but that is largely the environmental things that are flowing through.

Okay, just turning to the Browse Basin, is there anything -- I -- you have started -- I think you are a week or two into the Kontiki well. Is there anything that you have come up with in the last few months on Poseidon that has given you any additional information versus when you are finished drilling the well? Just wanting any more clarification on that.

No, no new information on the Poseidon well. As you might know, we had some operational difficulties that affected our ability to test that well and we had to abandon the well. So we don't have any further information to process at this point. We will be going back to the Poseidon structure after the Kontiki well is finished, which we anticipate will be in the next 60 or 90 days.

Do you think that when you do finish the Kontiki well you will give any further information about the potential from both -- well hopefully it's a discovery for you as well, but from the first two wells? Because we haven't had a news release from you yet on the drilling so far.

Yes, they are separate structures, so it will depend on how the drilling goes at that point. So that's all I would say about it right now.

And just a last quick one on Yanbu, it looks like yourselves and Aramco are going to contractors to sign up for the project. Is everything still in place in terms of the terms there and the timing?

Yes, I think the press releases that Saudi Aramco and Total put out about their JV at Jubail confirmed that the EPC markets have improved and validated the joint decision that we made to resume the bidding process. We don't have a specific price hurdle in mind for that project at this point and FID will be taken sometime next year after we relook at the cost, the bids, all the project premises at that time. So everything is basically still in place and on schedule the way we had previously communicated.

Great, thank you.

Evan Calio.

Good afternoon and thank you for taking my call. I have two questions. I guess one is a little follow-up on Neil's call on Yanbu. Just to understand, do you and Saudi would jointly agree to proceed the project and when you see more numbers, meaning that you have the ability to proceed or to not proceed if at that time you thought the project wasn't going to be in your best interest?

Yes, very definitely. That would be a joint decision and again we would look at all the factors that go into that, including one factor that I didn't mention would be the financing. Because financing is a part of that whole package, including the ability to IPO that into the Saudi markets.

I see, I see, so financing at the asset level.

Correct.

And then my second question is a broader kind of finance question. If I look at operating cash flow relative to CapEx plus your dividend for the quarter, you are about $1 billion short and you are cash flat with $1 billion incremental debt. So going forward and I know you mentioned you're holding your CapEx here at this point, in 3Q if it's more like 2Q, how are you going to work to balance the kind of levers here with CapEx, dividend or increased borrowing?

Yes, as we look to the end of the year, we basically think that we can manage debt flat to lower at this point. Obviously we are seeing some improvement in higher oil prices that didn't fully flow through into the second quarter, but are certainly with us into the third quarter and hopefully into the fourth quarter. We are going to see some positive impacts from some disposition proceeds coming through. And then as we approach year-end, we'll be back to kind of inventory target levels. So again, we are very confident I think that debt will be flat to down from this point forward.

Great. Thanks, Sig.

Mark Flannery.

I have two questions. One is a bit of a follow-up to that last one which is assuming no change in oil prices or gas prices from here, let's say if we look forward to next year, do you think you can reduce your debt levels just from cash from operations? Is that the underlying plan? Or are we going to have to see a slight strengthening in the environment before the debt level starts to fall?

Well, Mark, we are still putting our plans together. We are in the early stages for 2010 and of course that will involve a combination of capital and operating plans and all those input things that you referred to. So our plan certainly is to continue to bring our debt down back to our target range that we saw earlier and we fully intend to manage it to that level. And we feel like there is a lot of levers that we have to work with to move in that direction.

Okay, I guess the follow-up is on costs. You mentioned you've saved $900 million in costs so far this year, $800 million of which are from market factors and you cite the two main ones there as energy and FX. Could you first of all try and split those, how much is from energy and how much from FX?

The second question, second part of the question would be if you think you are going to meet that target of $1.4 billion for the full year, do you expect the balance of the cost savings to be from the operating line? Is that the implication from what you said?

I think -- first of all, I think as far as the split between those two we may have to get back to you offline on that. And as far as the run rates, we would expect to kind of see the same run rates to get us to that $1.4 billion savings now. Simultaneously kind of going on with our focus on cost reductions, we have captured another $500 million in cost reductions from working with the vendors and service providers through June. Some of that is flowing through to controllable costs and -- but a lot of that is going to flow through to capital, which you are not seeing as well. So there's more to the cost story than just what's shown in controllable cost.

Okay, thank you very much.

Arjun Murti.

Thank you, two questions. First was just on natural gas production in the US, which looks like it's been doing a little bit better. I know you have cut back your activity like many have. I was wondering if you can provide any comments on your net gas production outlook over the remainder of the year and into 2010?

Are you talking about US or North America, Arjun?

I'm sorry. Really I guess both US and North America would be great.

I think the basic -- the same general trend there, Arjun, is you're going to see that at these activity levels we would see base decline rate starting to impact at about around the 10% per year rate. So by the end of the year, we will be down about 10% from what we thought we would -- showed at the first quarter. So again, from that point forward, it will be a little bit dependent on our activity levels. As you said, we have pulled back our activity levels and redirected a lot of our drilling on rigs that we had under contract where we could to oil targets.

That's great, thank you. The second question was just on Refining. Sig, in your remarks you I think referred to a mid 80s range across the portfolio, I think a little higher in the US, a little lower outside of the US. Some of your larger peers are talking increasingly about shutting down or at least temporarily shutting down entire plants. Where is Conoco in that sort of thought process on Refining? Are you looking at more -- bigger changes to either -- how aggressively you run your plants, mid 80s still sounds like a decently high number. I was wondering if you had any thoughts on that?

Yes, Arjun, we look at all of this as probably all our peers do as well on a market by market, refinery by refinery basis basically in making optimization decisions daily, weekly. So that's an ongoing process and we don't see any plants -- refineries in our portfolio that are on the verge of kind of a total shutdown mode that we would get to that level. And we are just continually optimizing the portfolio and certainly making sure that they always cover the cash costs.

And when you think about this decision, Sig, is it a refinery or unit decision or is it sort of an integrated decision? You obviously have -- you have a lot of crude oil production, though in the US I personally don't think of it as integrated of a decision, but perhaps you do. Obviously I'm talking besides the EnCana joint-venture refineries.

No, we make it pretty much on a standalone decision.

Yes, that's great. Thank you.

Doug Leggate.

Thanks. Good morning, Sig. A couple of things. First of all on gas production, I know it's not normal for a major to think along these lines, but given how significant your US gas production is, and given where the forward strip is relative to cash costs, where is management's head in terms of potentially considering some kind of hedging on at least some of those gas volumes? Obviously a lot of your independent peers do that but I'm just wondering where your thinking is right now?

We have thought about it and again, are not currently active in that area and are not inclined to do so.

Okay, so it's not on the table. This follow-up I have is -- I guess a few weeks ago you mentioned -- or you put a press release out confirming the go-ahead for the Shah development. Obviously this had been I guess ongoing now for quite some time. Can you just provide any update you can in terms of what's changed by way of the capital commitment? How the -- that's perhaps improved the economics?

If you could roll that into maybe some discussion as to how things are looking in Australia, because my discussions with Clayton a few weeks back suggested that the capital costs there might be coming down quite significantly as well. So any updates you can suggest that maybe makes the economics look a bit better on both those projects would be appreciated.

Sure, let's just talk about Shah first and to clarify, we had been operating under an interim agreement at Shah and what you saw recently with our announcement on -- that we had signed the Shah gas field joint venture and field entry agreements with ADNOC basically was just to replace interim agreements that we have been operating under and formally -- these agreements just formally established the joint venture.

Regarding the economics, we are out for bids or going out for bids on Shah and we will take FID sometime in 2010 once those EPC bids are in and evaluated. So the bottom line is there is economics and everything else are subject to what -- and the go-forward decision are subject to the bids we receive and the evaluation that's done at that time. So it should not be construed as a decision was made to go forward with the project based on the announcement that was made regarding those particular agreements.

As it relates to Origin, we are very pleased with the progress we are making on Origin. The site -- we're very close to identifying a site for the LNG plant and then in final stages with discussions with the Queensland government at Curtis Island on that. Hopefully we would make an announcement on the site in the very near future.

On the marketing side, we are seeing a great deal of interest from potential buyers from Australia. They have a very favorable view of our project, giving our leading position in the resource base there in Queensland.

As it relates to the cost update, we remain comfortable with our plans to reach FID late in 2010, early 2011 and that will be depending again as kind of how the bids are coming in and I'd say it's probably a little premature to comment as far as what the costs are looking like. But again, I think when we entered into that project the costs were at a fairly high point in the cost curve, and so we would expect things to be -- come in lower than that. But again, it would be premature to speculate at this point.

Okay, well I appreciate your comments. Thanks.

Jason Gammel.

Thank you and good morning. I just wanted to come back to the Refining business and with the collapse in the light/heavy differentials, I wanted to first of all ask if it has made any changes to your potential decision to move forward with the upgrade at Wilhelmshaven refinery?

And second of all, just following up on what Arjun was saying, are you actually considering then shutting in coking units for instance as a result of the very narrow light/heavy differential currently?

Okay, on Wilhelmshaven, that project still remains important to us as we reposition that refinery to be a top quartile supplier of distillates in Europe. We are going to continue to evaluate the options on how to best move forward from a strategic standpoint on that. No decisions have been taken on it yet. We would expect to make a decision around that later this year.

Regarding the coke question, we have cut back our coker runs modestly based on current economics, but we haven't shut down any of them totally at this point.

Okay, great. And maybe if I just could, Jim Mulva has obviously been one of the industry spokesmen on carbon legislation. Do you have any comments as an organization on what the existing carbon legislation looks like and what effects it might have?

Well, as far as climate change goes, we are currently very disappointed in the bill that passed the House. We remain committed to the national legislation to address the growth in greenhouse gases, but nevertheless, we think the legislation that passed the House does not represent a fair and balanced and integrated approach. It is a bill that we cannot support and can't predict the outcome it's going to take place in the Senate. But we are certainly hopefully that the bill that passed in the House will not be what the final version ultimately looks like to the extent there is any climate change.

With regard to kind of legislative activity in general, it seems like climate change has taken a little bit of a back seat to healthcare going on right now and we don't anticipate action being taken on climate change perhaps until 2011 at this point.

Thank you, I appreciate the comments.

Paul Cheng.

Sig, a question. When I'm looking at your international E&P tax rate, 69.4% versus the first quarter of 64.1%, I would have thought the tax rate to be lower in the second quarter because of the higher oil price. Is it primarily due to the impairment charge or there is another reason behind? And if you can give us an idea that how should we look at yield for the remaining of 2009?

You know, I will have to get back to you on that as far as the variance. I hadn't focused on the variance being that dramatic, but Clayton or Diana will get back to you on that. What was your second question? I believe it was for outlook.

Okay, and also on the international E&P, versus the first quarter, if we add back the impairment charge to the second quarter, you are down about $50 million, but the oil and gas realization is up about $2.50 to $3 on a BOE basis. So that seems like there's a swing. That means that you should contribute about $150 million or so to you and so that responds to a swing about $200 million. Is that because of the higher employee unit cost or that is because of other reasons?

Again, maybe we can get back to you on that one, because I'm not sure that -- there's probably multiple things kind of going on with that on both the cost and the revenue side, so let's just get back to you on that one.

Okay, two final questions. One, with the change in the governorship in Alaska, any change in the plan for the gas pipeline for you guys and where we are on that? And also that with Iraq finished their first bidding run and that based on the terms that are being offered by the government there, is that still really an interesting area for you guys?

Well, with respect to the Alaska situation, it's very early days with the new governor at this point. We would hope to have a very constructive dialogue with them on moving the project forward and having them consider what we are doing that would be helpful to move that project along. But again, it's early days and we really haven't engaged in any conversation yet with the governor on that project.

With respect to Iraq, we look at opportunities as they come along. They recently announced their schedule for basically a second round of bidding at this point. You know, we will look at the opportunity, but every opportunity not just in Iraq but around the world has to compete with our existing portfolio. And we'll seek opportunities as long as we realize the appropriate returns for the risk that we would undertake.

And do you guys see the security situation in Iraq currently as sufficiently improved for you to actually put your own men on the ground?

Well, we participated in the first bid round, as you probably know, and we got comfortable that we could do that in those instances. So I guess the answer to that is yes.

Okay, thank you.

Robert Kessler.

Good morning, just circling back to your US natural gas portfolio and thinking through the balance of the injection season, are there any cases where you expect you might be shut out of some production because of pipeline pressures or other logistical bottlenecks?

Well we think if we do get into a situation where it looks like storage is going to be an overfill position, that would be certainly signaled into the market with the price signals as a result. And certainly then people would adjust based on those market signals more than they would be operational constraints. So --

And obviously some areas would fare better than others. Have you stress tested your portfolio to that scenario to see what sort of magnitude effect it would have on ConocoPhillips?

Well, we continue to look at our portfolio on a lease-by-lease and a field-by-field basis, so we are following the market very closely and believe we are on top of the situation.

Okay. Thank you.

Mark Gilman.

Sig and Clayton, good morning. A couple things. On Shah, Sig, can you talk about the fiscal regime and whether there was a front-end entry payment? And is the fiscal regime in fact nailed down at this point?

It's provided for in the agreements and -- but don't care to talk about it at this point.

We typically don't disclose what those agreements contain, so that one is probably out of bounds.

Even in terms of type -- as opposed -- PSC or standard concession, something along those lines?

I think that's all we're going to say about it right now, Mark.

Okay. Regarding origin, Sig, did I hear you correctly when you said that there has been considerable interest from domestic Australian customers?

No, LNG buyers in Asia. Maybe I said Australia but I meant to say Asia. Sorry.

Okay, is there any thought on your part of affiliating with one of the other alternative ventures that appear to be moving ahead at a slightly quicker pace?

There have been conversations with all of them at certain levels and we remain open to that possibility, but I would say it's doubtful that it would come together that it would make sense for all parties at this point. But we are certainly open to that opportunity.

Okay, just a little bit more specifically, can you give us a plateau production number for North Belut please?

Yes, North Belut should plateau at about 20,000 barrels a day.

Is that BOE, Sig?

BOEs, yes, 2010.

Is that an entitlement number?

That's in a PSC area, so that would be at basically current prices.

Okay and just one final one. You referenced in your remarks on the production side about a 30,000 equivalent a day net impact of market factors including OPEC curtailments, PSCs and Canadian royalties. Can you dissect that number a little bit in terms of those three factors which contributed to it?

Well, I can give you some of the areas and hopefully that'll help you out. Between -- Indonesia was about 10 of that and that's a PSC. Australia is about three PSC-related. Canadian situation is about 24 and we had about 8000 barrels a day in Libya due to OPEC restrictions.

Thanks a lot, Sig.

Pavel Molchanov.

Thanks for taking my questions. Two quick points. Number one, can you give us an update on where things stand on the Wood River expansion project?

Wood River expansion project is moving along as planned. The startup I believe is 2011, I think late 2010 or 2011, but moving along as per planned.

We can follow up and give you -- is there something specific about Wood River that you are interested in?

No, just whether or not your -- since one of the plans is to install a new coker, I was wondering if you are reconsidering any of those investments?

No, no, going forward as planned.

Great and then secondly in terms of your downstream optimization program, do you have any retail assets that you have yet to divest based on your previous plans?

So we've divested of essentially all of our Company-operated stations. There are between 100 and 200 dealer-operated stores on the West Coast that are still being marketed.

Got it. Thanks very much, guys.

(Operator Instructions) There are no further questions in queue. I would now like to turn the call back over to Mr. Clayton Reasor, Vice President of Corporate Affairs, for any closing remarks.

Thanks, Keisha. I appreciate everybody's involvement and participation in the call this morning. Certainly Diana and I are available to answer any follow-up questions and look forward to seeing you in the near future. Thank you.

Thank you for your participation in today's conference. This concludes the presentation. You may now disconnect. Good day.

Company Disclaimer

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..

This transcript includes certain non-GAAP financial measures. Such non-GAAP measures are intended to supplement, not substitute for, comparable GAAP measures. Investors are urged to consider closely the GAAP reconciliation tables provided in the Appendix or on our website at www.conocophillips.com.