Clayton Reasor - VP, Corporate Affairs Sig Cornelius - SVP, Finance and CFO

Neil McMahon Evan Khalil [ph] Mark Flannery Arjun Murti Doug Leggate Jason Gammel Paul Cheng Robert Kessler Mark Gilman Powell Maltunal [ph]

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

Thanks, Keisha. Well 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 and updated supplemental information package, and posted the slides we'll be using on this teleconference. You can find this information on our Web site. 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 two. This is our standard reminder that we're going to use for forward-looking statements that maybe 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'll turn the call over to our Senior VP Finance and CFO, Sig Cornelius.

Thanks, Clayton. I'll start my comments on page three, 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 were 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 four, 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 in margins were also the largest driver in our downstream segment, and resulted in a loss of $52 million compared to earnings to $664 million last year. For all segments, prices, margins, and other market impacts decreased 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 five 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 $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 six. 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 are 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 in other operational factors. We had a total increase of over 175,000 BOE per day from new developments and project start-ups. This includes YK in Russia, BritSats and other new wells in the UK, 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 seven, 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 impact 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 over lift 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 pre-tax basis, costs were down around $275 million compared to last year. Market factors such as foreign currency and utility rates, represented about 75% of the savings. The balance is due to savings and operations from lower activity levels, lower service cost, and portfolio changes, which is partially offset by higher cost 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 8th at our Ekofisk 24/W 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 start-ups that I referenced earlier. The R&M earnings variance is shown on page eight. 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 and 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 were less that 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 have a 5% increase in global refining utilization compared to last year, due to continued weak harder scheming economics and optimization of margins based on market conditions. In addition, we also have higher turn around activity in our international operations this past quarter. Pre-tax operating costs were down around $400 million. This was fairly equally split between market factors and operational savings which included lower turn around 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'll now move to page nine, which shows the variances for local segments. Local 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 the decline. And is consistent with the results we are saying 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 ten shows the variances for all our other segments. In mid stream we experienced lower results. It is 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 completes the review of our second quarter results. I'll 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 a signaled last quarter, we expect E&P production to be up slightly for the full year, compared 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 interests. 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, averaged 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 $900million pre-tax so far this year, excluding explorations. 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 personal reductions. So far this year, we've seen a benefit of around $800 million from market factors such as energy cost, 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 on our 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 on 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 we'll 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 and the Browse Basin of Australia. Additional (inaudible) 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 we'll be going back for additional (inaudible) 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) Your first question comes from line of Neil McMahon [ph]. Please proceed.

Hi, Neil McMahon of Sanford Bernstein. Just a few questions, just looking at the chemicals results, a small in the overall scheme of things. Has the cost reduction there’d been a structural change? Or has it been driven more by your energy cost reduction over the first half of the year? I just wondered if it’s structural versus something like that could be actually changed based on input cost drivers. I’ve got a few other questions too.

It’s primarily on the input cost. There had been some structural changes flow through with the JV, with the Dow [ph] and the styrenics. But that’s largely the environmental things that are flowing through.

Okay. Just turning to the Browse Basin, is there anything like -- you just started. I think you’re a week or two into the Kontiki well. Is there anything that you’ve come up with in the last few months, on Poseidon, that’s given you any additional information, versus when you had finished the drilling of the well? I need 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’ll give any further information about the potential from both? 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 drillings so far.

They are separate structures, so it will depend on how the drilling goes at that point, so that’s all I‘d say about it right now.

Just a last quick one on Yanbu, 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 around their JV at Jubail, confirmed the BPC 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 of bids, all the project premises at that time. So everything’s basically still in place and on schedule the way we had previously communicated.

Great. Thank you.

Next question comes from the line of Evan Khalil [ph]. Please proceed.

Good afternoon. And thank you for taking my call. I have two questions. One is a little follow-up on Neil’s call on Yanbu. Just to understand, did you and Saudi would jointly agree to proceed with the project when you see more numbers, meaning 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 will 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.

Oh. I see. So financing at the asset level?

Correct.

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’re about $1 billion short, and you’re cash flat with $1 billion of incremental debt. So going forward, and you mentioned you're holding your CapEx at this point, in 3Q if it is more like 2Q, how do you do the work to balance the levers here with the CapEx, dividend, or increase borrowing?

As we look to the end of the year, we basically think that we can manage debt flat to lower at this point. And obviously, we’re 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 inventory target levels. So again, we’re very confident and I think that debt will be flat to down from this point forward.

Thanks, Sig.

Your next question comes from the line of Mark Flannery [ph]. Please proceed.

I have two questions. One is a bit of 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 level just from cash from operation? Is that the underlying plan? Or are we going to have to see a slight strengthening in the environment for the debt level itself to fall?

Well Mark, we’re still putting our plans together, 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’s a still 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 saved $900 million in cost so far this year, $800 million of which from market factors. And you cited to main ones, there’s energy and FX. Could you, first of all, try and split those? How much is from energy and how much from FX? And the second question -- second part of the question would be, if you think you’re 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?

Well 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 see the same run rates to get us to that $1.4 billion savings. Now, simultaneously 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 the controllable cost. But a lot of that is going to flow through the capital, which we’re not seeing as well. So there’s more to the cost story than just what’s showing in the controllable cost.

Okay. Thank you very much.

Your next question comes from the line of Arjun Murti. Go ahead, please.

Thank you, two questions. First is just on natural gas production in the US, which looked like it’s been doing a little bit better. I know you’ve cut back activity like many have. I wonder if you could 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?

I’m sorry, really. I guess both US and North America would be great.

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 around a 10% per year rate. So by the end of the year, we’ll be down about 10% from what we thought we would show at the first quarter. And again, from that point forward, it’ll be a little bit dependent on our activity levels. As you said, we pulled back our activity levels and redirected a lot of our drilling on the rigs that we had on the contract, where we could to oil targets.

That’s great. Thank you. The second question, which is just on refining, Sig, in your remarks you 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 at least temporarily shutting an entire plant. Where is Conoco in that sort of thought process on refining? Are you looking at more, bigger changes to either how you aggressively you run your plants? The mid-80s still sounds like a decently high number. Wondering if you had any thought on that?

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

And when you think about those decisions, is it a refinery or unit decision? Or is it sort of an integrated decision? You obviously have a lot of crude oil production though, in the US. I personally don’t think of it as integrative of a decision. But perhaps, you do and obviously, I’m talking besides being kind of joint venture refineries.

We make it pretty much on a stand alone decision.

That’s great. Thank you.

Your next question comes from the line of Doug Leggate [ph]. Please proceed.

Thanks. Good morning.

Good morning, Doug.

A couple of things. First of all, on gas production, I know it’s not a 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 cost, 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 independents here do that. But I’m just wondering what you’re thinking is, right now?

We 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 -- a few weeks ago you mentioned the -- or you (inaudible) started confirming the go ahead for the Shaw development. Obviously, this had been 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 (inaudible) perhaps improve the economics? And 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 cost there may be coming down quite significantly as well. Any update you can suggest that maybe mixed economics will come out better on both those projects will be appreciated.

Sure. Let’s just talk about Shaw first and to clarify, we have been operating under an interim agreement at Shaw. And what you saw recently with our announcement on -- that we’ve had signed the Shaw gas deal joint venture and field entry agreements with ADNOC, basically was just the replacing interim agreements that we’ve been operating under, informally. And these agreements just formally established the joint venture. Regarding the economics, we are out for bids or going out for bids on Shaw. And we will take FID some time in 2010, once those EPC bids are in and evaluated. So the bottom line is, there’s 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 relates to Origin, we’re very pleased with the progress we’re making in Origin. We’re very close to identifying a site for the LNG plant and then 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’re seeing a great deal of interest from potential buyers from Australia. They have a very favorable view of our project, given our leading position in the resource base there in Queensland. As 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 to 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 in that project the cost were at a fairly high point in the cost curve. So we would expect things to be coming lower than that. But again, it would be premature to speculate at this point.

Okay. Well, I appreciate your comments. Thanks, Sig.

Thank you.

Your next question comes from the line of Jason Gammel [ph]. Please proceed.

Thank you, and good morning. I just wanted to come back to the refining business with the class in light and 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 of the 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 core tiles supplier of distillates in Europe. We’re 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 then maybe if I just could, Jim Mulva [ph] has obvious been one of the industry’s 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 the climate change goes, we’re 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, that we think the legislation that passed the House does not represent a fair and balanced and integrated approach as a Bill. And we cannot support and can’t predict the outcome it’s going to take in place in the Senate. But we are certainly, hopefully that the Bill that passed in the House will not be with the final version, ultimately, it 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 health care 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.

Your next question comes from the line of Paul Cheng [ph]. Please proceed.

Hey guys.

Hey, Paul.

Sig, a question. When I looking at your international E&T 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 primary due to the impairment charge, or there’s other reason behind? And if you can give us an idea then, how should we look at the year for the remaining of 2009?

I have to get back to you as far as the variants. I am focused on the variants being that dramatic, but Clayton or Diane will get back to you on that.

Okay.

What was your second question with that--?

And also on the international E&T versus the first quarter, if we add back the impairment charge to the second quarter, you went down about $50 million. But the oil and gas realization is up about $2.50 to $3 on a BOE basis. And so that seems it might have a swing. That means that you should contribute about $150 million or so, to you. And so that’s a -- will sponsor a swing about $200 million. Is that because of their higher implied unit cost? Or that’s just 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 going to go 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 their gas pipelines for you guys, and where we are on that? And also with Iraq finish there, the first bidding ran, and that based on the terms that’s being offered by the government there, is that still a -- really an interested area for you guys?

Well, with respect to the Alaska situation, it’s very early days with the new government 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’re doing. It would be helpful to move their project along. But then again, its 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. We’ll 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 risks that we would undertake.

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

Well, we’ve 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.

Your next question comes from the line of Robert Kessler [ph]. Please proceed.

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 the storage is going to be 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 the operational constraints.

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

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

Okay. Thank you.

Your next question comes from the line of Mark Gilman [ph]. Please proceed.

Sig and Clayton, good morning.

Good morning, Mark.

A couple of things, on Shaw, 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 I don’t care to talk about it at this point.

We typically don’t disclose what those agreements contain. So that one’s probably out of bounds.

Even in terms of type as opposed, you know, PFC 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 have been considerable interests from domestic Australian customers?

No LNG buyers, in Asia. Maybe I said Australia, but I meant to say Asia. Mark Gilman - Benchmark Company: 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 phase?

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’re certainly open to that opportunity.

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

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

Is that BOE, Sig?

BOEs, yes. 2010.

Is that an entitlement number?

That’s in a PFC area so that would be as basically, current prices.

Okay. And just one final, when you referenced in your remarks on the production side about 30,000 equivalent a day, net impact of market factors, including OPEC curtailments, PFCs 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 will help you out. Indonesia was about ten of that, and that’s the PFC; Australia is about three, PFC related; Canadian situation is about 24; and we had about 8,000 barrels a day in Libya due to OPEC restrictions.

Thanks a lot, Sig.

You’re welcome.

Your next question comes from the line of Powell Maltunal [ph]. Please proceed.

Hi. 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. It’s start-up I believe is 2000--

In '11?

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’re interested in?

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

No. No. It’s 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 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. Appreciate everybody’s involvement, participation in the call this morning. Certainly, Diane 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.