Clayton Reasor - VP, Corporate Affairs

Paul Sankey - Deutsche Bank Doug Terreson - ISI Mark Gilman - Benchmark Robert Kessler - Simmons & Company Blake Fernandez - Howard Weil Arjun Murti - Goldman Sachs Jason Gammel - Macquarie Doug Leggate - Merrill Lynch Ryan Todd - Morgan Stanley

Good day ladies and gentlemen, and welcome to the fourth quarter 2009 ConocoPhillips earnings conference call. 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). I would now like to turn the call over to Mr. Clayton Reasor, Vice President of Corporate Affairs. Please proceed, sir.

Thanks, Anton. Good morning and welcome to ConocoPhillips fourth quarter 2009 earnings conference call. Today I will be focusing on the company’s results for the quarter using material you can find on the web. And during the presentation, I will refer to adjusted earnings which are reconciliation of two adjusted earnings can be found in the appendix of our presentation material. Before we get started, I would like to refer you to our safe harbor statement which is on page two, which is a reminder that I will be making forward-looking statements as part of the presentation and the Q&A and that actual results maybe materially different. So I am going to move to slide three, which provides a summary of our fourth quarter results and business highlights. Adjusted earnings for the quarter were $1.7 billion or $1.16 per share generating cash from operations of $5.1 billion. We ended the quarter with debt of $28.7 billion resulting in debt-to-cap ratio of 31%, down 2% versus last quarter. Total production, including our 20% share of LUKOIL was 2.26 million BOE per day in the fourth quarter. It was a challenging period for R&M with an overall loss in net income driven by depressed refining margins which were particularly low in the U.S. Global refining utilization was only 76%, reflecting economic run cuts made in this difficult environment as well as increased turnaround activity. On the cost side, we achieved a normalized full year reduction of 12% or around $1.7 billion pretax for the year. This compares to our original target of $1.4 billion and I will provide more detail on the sources of these cost reductions later in the presentation. During the quarter, we recognized non-cash asset impairments of almost $575 million after-tax primarily related to the impairment of our equity stake and Naryanmarneftegaz joint venture in Russia and matured Western Canada gas properties as well as miscellaneous impairments in our E&P and R&M segments. In Naryanmarneftegaz, equity accounting rules for impairment testing resulted in write down this quarter, and while the current producing field YK has met our expectations, our view of probable resource has declined as a result of additional data and drilling activities around some of the flank areas of the reservoir. In Western Canada, the impaired properties were impacted in varying degrees by a combination of lower prices, royalty rate increases, strengthening of the Canadian relative to the U.S. dollar and operating performance. These Canadian impairments represent a small portion of our total capital employed in that region. Turning now to slide four, you can see total adjusted earnings for the fourth quarter were up sequentially, but down by about 10% compared to last year. This slide shows changes by segment. Our E&P business increased earnings by more than 20%, due primarily to the improvement in oil price, which more than offset lower gas prices. As I mentioned, R&M had a loss for the quarter due to significantly lower realized margins and utilization rates. LUKOIL adjusted earnings were higher than the fourth quarter of 2008 reflecting our estimates for fourth quarter 2009 results. Slide five shows the progress we've made on reducing controllable costs. We started 2009 with a goal of reducing costs by 10% or $1.4 billion. For the full year, we achieved nearly $2 billion all in savings, and if you exclude one-time severance accruals, the normalized reduction was around $1.7 billion nearly 40% of these savings were related to base operational expenditures while the remainder resulted from market factors such as currency movements and lower utility costs. We also saw a significant savings in the equity affiliate operations such as CPChem and DCP which are not included in this amount. Slide six outlines our cash flow performance. In the fourth quarter we generated $5.1 billion from cash from operations with capital spend of $3.1 billion in dividends of $750 million. Total debt was reduced by $1.8 billion. Our 2009 full year cash flow detail is shown in the pie charts on slide seven. As you can see on the left, we generated $12.5 billion in cash from operation. Asset sales including the disposition of our interest in Keystone Pipeline along with other changes provided $1.1 billion of additional cash. Uses of cash are provided on the right hand side of the slide and show our 2009 capital program of $12 billion, which was slightly below plan due to the timing of expenditures on major projects. Our dividends were $2.8 billion which included the quarterly increase we announced in October. As a result total debts increased $1.2 billion for the year. Slide eight shows the history of our debt-to-cap ratio over the last several quarters versus our target of 20% to 25%. As you can see while we're currently above our goal, we've made progress at reducing debt-to-cap this year and as we go forward, we expect the proceeds from our two year $10 billion asset disposal program and cash flow from operations to move us back within our targeted range. I would like to take a couple of minutes to review our segment performance starting with total company production for the fourth quarter you can find on slide 9. Overall E&P production was down 2% from 39,000 BOE a day versus the fourth quarter of 2008. Market factors decreased production by 16,000 BOE a day reflecting reduced gas production North America driven by economic conditions as well as PSC-related, price related reductions and international OPEC curtailments. As we discussed in our third quarter conference call voluntary gas curtailments began in late August and continued into the fourth quarter and during the fourth quarter total curtailment was around 145 million cubic feet per day. Moving to the right side of the slide you can see the changes to the portfolio reduced production by 12,000 BOE per day primarily reflecting the sale of our Netherlands assets next appropriation of our interests in Ecuador. These declines were partially offset by a benefit from improved volumes due to the absence of hurricane impacts in 2009. In the operations category, we saw a significant benefit from new production was not able to offset normal field decline. Although the fourth quarter was down compared to last year, our full year production was up around 3% to 1.85 million BOE per day versus the 1.79 in 2008 as shown on slide 10. Excluding market related improvement of 17,000 BOE per day we are up over 2%. This was driven by nearly 140,000 BOE per day in production from new major projects and oil sands expansion. We were also helped by strong operation; we had a strong operational year and had lower impacts from external events such as hurricanes. So now turning to slide 11, you can see total E&P adjusted earnings for the fourth quarter were $1.7 billion, up from $1.4 billion last year. The main drivers of the improvement were higher oil prices and lower operating costs which more than offset lower gas prices, sales volumes and other cost. You can see that on the right hand side of the table, at the bottom of the slide, on realized oil and NGO prices went up by 36% compared to last year while global realized gas prices decreased by about 25%. Although North America gas prices were challenged for the majority of the year, our fourth quarter performance to lower 48 benefited from somewhat better gas prices and continued cost reduction programs. The chart shows a breakdown of the major variances. In total prices in other factors such as production taxes increased earnings by $500 million. Lower sales volumes decreased earnings by about a $160 million. This decrease reflects lower gas sales due in part to voluntary reductions which were partially offset by higher liquid sales. Operating costs were improved by a little less than a $100 million after tax. Unlike previous quarters, when market factors comprised a majority of savings, cost reductions this quarter relate to underlying operations as market factors worked against us. The other bar primarily reflects foreign currency loss compared to a gain last year and we also had higher DD&A expense this quarter due to project start-ups and some specific deal dismantlement accruals. The R&M adjusted earnings variance is shown on slide 12. R&M lost money during the quarter driven by low global refining margins and compressed crude differentials. As shown on the table at the bottom of the slide. U.S. adjusted earnings fell by nearly $700 million due in large part to a nearly 60% decline in integrated margins. Although the U.S. refining 3:2:1 crack spread was virtually unchanged versus the fourth quarter of 2008. Our realized margins decreased significantly and this was caused by several key factors. First, light, heavy and sweet, sour crude differentials were significantly lower this quarter compared to last year. Our U.S. refineries are configured to run around 55% advantage crudes such as WTS, Canadian Sour and South American Heavies. On this advantage crude every dollar decreased in differential creates between $15 million and $20 million decrease in quarterly earnings. When compared to last year's quarter, the Maya Differential decreased by nearly $7 a barrel. We also saw negative impacts from the decrease in distillates spread. Although the market 3:2:1 crack spread was flat. Distillate margins decreased by over $11 a barrel, while gasoline spreads increased. Because our production and configuration is more biased toward diesel with an average yield in the mid to high 30% range. We were adversely impacted by the distillate spread. The third source of year-over-year earnings decline not reflected in the three, two, one market crack. It’s the impact of higher crude prices on secondary product margins. We saw a certain refinery products on a fixed price basis which makes their margins vulnerable to crude cost moving quickly higher. On the international side, the variance is more straight forward. The table shows that international earnings fell by 70% and this generally consistent with the international refining 3:1:2 spread decrease. In total global realized margins reduced earnings by more than $800 million as shown on the graph. Utilization rates and sales volumes were also down caused primarily by economically-driven run cuts. Lower operating cost did help adjusted earnings buy back $50 million despite the higher turnaround activity, and all other impacts such as currency movements, decreased adjusted earnings by about $30 million. I'll now move to slide 13 which show the variances for all other segments. In midstream we experienced higher results due to higher NGL prices compared to last year, index price for DCP were up around 40%. And our share of CPChem results were $60 million higher due to improved specialties, aromatics and styrenics margins, a lower control over cost partly offset by lower olefins and polyolefins margins. Earnings from our emerging businesses segment decreased primarily due to the lower sparks rising international power. LUKOIL earnings were $388 million for the quarter compared to an adjusted value of zero for the fourth quarter 2008. Corporate expenses were outlined at $311 million after tax for the quarter compared to $354 million of adjusted expenses last year. This decrease is due to the absence of foreign currency losses and lower staff cost partially offset by higher net interest expense. So that completes my review of our fourth quarter results. I'll wrap up with some summary comments on slide 14. We performed well in 2009 despite difficult global economic conditions that severely impacted the energy industry. In 2009, we initially expected our E&P production to be flat versus 2008, excluding market factors we delivered slightly more than 2% growth driven by improvements and operating efficiency and lack of any external events such as hurricanes. Looking at 2010, we expect to return to the more normalized production we achieved in 2008 in large part to having a full year impact of reduced North America drilling as well as lower production growth from new projects. While we do have a good portfolio of major projects such as QG3, Canadian Oil, Jasmine, Gumusut and others, they will contribute growth as these developments are continued but we do plan to reduce our capital spending in some of our more mature assets which are significant perimeters to near term production. We are intentionally reducing our spending levels in support of our stated effort to improve our return on capital employed and increase our per barrel cash flow and earnings in our Australian business. In addition to delivering production results improving safety performance and having a good environmental stewardship year we took steps to reduce our cost structure to capturing market opportunities and driving reductions in our underlying business. While we can’t predict how market factors such as currency and utilities will impact us in 2010, we are committed to holding on to the operational savings we achieved this year from procurement initiatives, controllable cost reductions, and portfolio changes. In 2009, we also began to see results from our commitment to exploration with discoveries in the Browse Basin of Australia and lower tertiary trend in the Gulf of Mexico. We also added several prospects in some exciting new areas. In spending on exploration we remain relatively flat in order to strengthen our portfolio from future organic reserve replacement. Late in the year we announced plans to enhance returns and strengthen our financial position. Consistent with these objectives we announced our 2010 capital budget if $11.2 billion and initiated our asset disposition plans. We started the sales process for our same crude interest and received quite a bit of interest on this asset. And we identified other targets and are very confident we will reach our $10 billion target over the next two years. Finally, we are taking appropriate steps to manage our downstream business in the phase of prolonged margin pressure. We do not expect the magnitude of losses to continue on this business given the specific actions we are taking. Our strategy is constant and starts with operating excellence. We must run safely and reliably. Next, we focus on controlling our cost and we have a good track record in this area. In addition to running well and keeping cost in check, we focus on optimizing the plans and capturing the highest margin available on any given day. This not only includes making economic run reductions as we did in the fourth quarter, but also changing operations in response to market movements. Lastly, we have adjusted our capital plans for this business with the objective of ensuring that is cash positive. You can see this on the deferral of the upgrade project at Wilhelmshaven and a reduction of discretionary capital. Through all these steps we feel confident in our ability to manage through this challenging environment. So, Anton that concludes my prepared remarks and I will open the call for your questions.

Thank you. Ladies and gentlemen, (Operator Instructions). Your first question comes from the line of Paul Sankey with Deutsche Bank. Please proceed with your question. Paul Sankey - Deutsche Bank: Yeah. Hi, Clayton. You talked about upgrading the portfolio and general actions over the course of the year. Can you just give us some more detail on any more specific progress how we'll be looking at the annual meeting on March the 24 for example, any further comments on LUKOIL and so on? Thanks.

So I guess the questions that are out there around status on the asset sale program and when we announced this in the fourth quarter, we said it was a two-year program because we knew it was going to take a little bit of time to get lower interest that we wanted in certain assets and to find where we wanted to invest and also measure the market response. So nothing has really changed. I can't give you any more color on the assets as far as where we are with the bottom 10% of our North American assets, or Syncrude or the REX pipeline or the Southern North Sea, so those are all still being worked. I can say we don't have any reason to believe we're not going to be able to generate to $10 billion that we stated. As far as LUKOIL again, I can't really say anything that but repeat what Jim had said, which was we've got a really good relationship with LUKOIL and the Russian authorities. We recognized what's taking place there, and we are aware of the situation and it's really appropriate the comment that we would like to make as we just intend to maintain a strategic relationship we have with LUKOIL, and I don't know if there was anything else that you wanted to ask. Paul Sankey - Deutsche Bank: I did. You generated enough cash to pay down debt this past Q4 assuming, given what you said about the expected disposal proceeds being in line with what you previously told. What would be the next phase for the additional cash thus implicit beyond what you wanted to do in terms of paying down debt?

Some of this just going to depend upon on what the market does but when we see this free cash flow coming you think about $10 billion of asset sales and you think about some of the other things worth considering you think about free cash flow we certainly would like to have annual dividend increases and we want to keep our CapEx at the $11 billion range may be 200 million higher but not much more we don’t see it going back up into the $13 million to $14 billion range. But once we get our debt down covered 11 billion or so CapEx raise our dividends I think we've got to consider share repurchase. Paul Sankey - Deutsche Bank: I didn’t quite understand what you said about volumes for the year did you say that '08 was normalized in which case what would you call a normalized number for '08 because we could have done quite sharply basically '08 versus '07.

Okay so when we started year 2009 the guidance we were providing when we are going to stay flat over the next couple of years from that level and so that’s the guidance we are really giving for 2010 is going to be inline with 2008 volumes.

Your next question comes from the line of Doug Terreson with ISI. Please proceed with your question. Doug Terreson - ISI: I have another question on the E&P as well your production rose by a full 4% in 2009 and that’s obviously impressive for a company of your size and it's higher than I think the company thought a year ago and so the press release talks about reliability and PSAs in some of the regions that drove the performance but it appears that they were broad-based and so my question is that is whether or not their strategies, or processes that you guys have in place that are leading to this positive performance ahead of expectations that is their common theme amongst the commentary that you made in the press release today that are driving these positive results may have been so if you could just comment on what they might be, it would be appreciated.

Okay, so I guess Doug are you looking at fourth quarter versus fourth quarter a year-over-year? Doug Terreson - ISI: Full year.

Full year. So, I guess there is the up, we just ran very well in 2009, our uptime and reliability was higher, I think the things that I would look at, you had some major projects startups around the BritSats and Bohai Bay, Canadian heavy oil projects increased a bit as well as YK field in it offset the declines that we saw in North sea. Also I would say the North America decline was less than expected with the lower activity. So, I would say those are the big parts, we just ran very well this year. Doug Terreson - ISI: Let me ask you one more question about the debt reduction plan, you guys have talked about lowering debt to total capitalization from 31% to 20% to 25%, although its consensus estimates are on the ballpark in 10 or 11 and you should be able to attain that target just from growth and equity alone by the middle of 2011. And so my question is how do you guys plan to manage as part of the program meaning is there an absolute level of debt that you are more comfortable with? And if so, what is that level of that range and if could just talk about how that part of the plan if I could be managed that would be great.

I think that might be something that would be better talked about in March but there is no specific number that we are targeting, I think a part of that will depend upon what's happening in the market. Doug Terreson - ISI: Okay.

What kind of opportunities we see, but I think we like the idea of being in the 20%, 25% debt-to-cap ratio, but don't see a real big benefit in going much below that level.

Your next question comes from the line of Mark Gilman with Benchmark. Please proceed with your question. Mark Gilman - Benchmark: A couple of things, can you comment on the cash that changed hands with respect to the recently announced Statoil swap?

Not really, we tried to keep those assets swaps, the commercial terms confidential, so can't really say anything about that. Mark Gilman - Benchmark: Okay, let me try one or two more, if you could?

Sure. Mark Gilman - Benchmark: Implicit in your comment regarding 2010 production is how much in the way of voluntary gas curtailment?

I don't think we're making any assumption around voluntary gas curtailment, so we've got around a 140 for the quarter, we were down 140 Mcf a day and we're all back on now. So essentially we don't make any assumption that there is going to be gas curtailed in 2010. Mark Gilman - Benchmark: Okay. This comment in the press release Clayton regarding Bohai production, a number about 45 KBD, I don't know what that number is, is it fourth quarter, is it full year, is it Phases 1 and 2 or just Phase 2, is it entitlement number? Can you help?

So I think that is a net year-end number. For everything inside Bohai. That's our production that at Bohai. Mark Gilman - Benchmark: And it's an entitlement number?

Yes. I'm glad, I'm not sure no one else not just, not to agree with you but if its not an entitlement number I will call you back. Mark Gilman - Benchmark: Yeah, okay and your net share under the applicable production share and contract.

Correct. That’s right. Mark Gilman - Benchmark: Okay, just one or two of the quick upstream things, can you give us any kind of color on the kinds of results you are seeing on the Eagle Ford program at this point?

Not a lot I mean we had good success there what’s been encouraging are the existence of some condensates and other liquids. I would say the drilling program is being developed now for 2010 but I don’t think we want to get into any specific production of well results. Mark Gilman - Benchmark: Okay, there’s been some confusion in the trades and in the media regarding the Poseidon appraisal. Could you set the record straight on exactly what happened with that well, was it a well where we really didn’t see any meaningful results because of mechanical considerations or did the well in fact not confirm what you saw on the initial discovery.

You are talking about Poseidon, the most recent well or… Mark Gilman - Benchmark: That’s correct, Poseidon 2.

So there were some technical issues that didn’t allow us to test the well, the way we wanted to so we are waiting for technical results. So nothing conclusive we’ve gotten from that well testing now. Mark Gilman - Benchmark: Okay, I’ve got just one more arithmetic related. Looking at the waterfall charts, for the segment earnings, okay I’ve got $95 million in cost reduction in E&P in the fourth quarter I’ve got $47 in R&M in the fourth quarter you know if I put it together and multiply by four gross it up on a pretax basis I am looking at a number that’s perhaps in the $1.1 billion range. That’s no way near the kind of numbers that you talked about as having achieved. What am I missing?

Well this may be something we want to take offline but I don’t know if you are looking at the market related impacts or you just looking at the…? Mark Gilman - Benchmark: I am just looking at what you are defining as cost savings in those two slides. Okay, these are your numbers and on the fourth quarter basis versus year ago, frankly the run rate ought to be a lot higher and therefore if anything I ought to be exceeding the number that you are talking about.

Fourth quarter can't be annualized because the market factors of natural gas and foreign exchange went against us. Mark Gilman - Benchmark: Okay.

So, in the other quarters we actually had helps from FX and that gas this quarter all the savings came from internally generated and actually we gave some back on the market related ones. But I am happy to walk through the, we feel pretty good that we delivered on this, $2 billion in savings, 1.7 if you exclude severance accruals and I'd be happy to walk through that with you. Mark Gilman - Benchmark: Okay. Will do. Thanks very much.

Your welcome.

Your next question comes from the line of Robert Kessler with Simmons & Company. Please proceed with your question. Robert Kessler - Simmons & Company: Thanks. Good morning, Clayton. I wanted to revisit the off share impairments a bit and see if there is any associated reserve impact for those. Its kind of like for the Russian affiliate, it was you were fairly explicit in saying those were unproved and are probable reserves and that there was an implication on assuming no [1P] effect. But I am wondering if the Canada reserves may have had an associated write off of barrel in addition to the write down of assets?

So, I will start with Canada. There are several things that drove the Canadian impairments, one was royalty rate reduction, there was royalty rate reduction for a big portion of Canadian production, but in some specific wells and fields, including some of the deep wells, royalty rates actually increased. Impairments in Canada were isolated to a few fields, some of them did see negative impacts from royalty rate changes but there was no impact on reserves, are very little on reserves. As far as Naryanmarneftegaz, the biggest driver on that was our view of the probable reserves around the JV area and the fact that we see those reserves as less than we had. There were some other things around cost and currency to the impact of the valuation, but also in Russia, you have to keep in mind, the equity impairment rules are different where you use a discounted cash flow against book which is more stringent than you use for consolidated. Robert Kessler - Simmons & Company: Sure. I just would have thought that the year in 2009 would have been more benign than the year-end 2008 tests in terms of market factors there but?

That's true. I think that's right. I think around Russia, it was just our assessment of the resource after we've got additional information. Robert Kessler - Simmons & Company: So it sounds like YK itself has done reasonably well, but the surrounding areas have changed in terms of your perception, how do you view overall net production from the JV now for Conoco going forward the next several years?

I don't think that our position is changed on that. I think YK is operating as we expected, I don't really view this as having an impact on our overall assessment of our Russian operations.

Your next question comes from the line of Blake Fernandez with Howard Weil. Please proceed with your questions. Blake Fernandez - Howard Weil: Good morning, Clayton. A question for I wanted to clarify the 2010 production guidance does that contemplate any divestitures?

No it does not. So we're not assuming impact of divestiture in; obviously there could be divestitures that have an impact on production but we're not including that in the guidance. Blake Fernandez - Howard Weil: Okay thanks and then moving on to the lower tertiary, obviously the transactions was Statoil moves you more levered to the lower tertiary and as I understand that at somewhat early days with not a lot of production history or data points from the play from industry and I'm just curious do you have enough tangible data points to kind of have a good understanding of the economics out there or how much of this is kind of betting on the comp?

No I think the people that we have at exploration understand lower tertiary pretty well they've got us into Tiber and some other things that have been successful. The thinking behind this is that we just are looking to balance the portfolio between a different exploration opportunities that we have and Chukchi is highly perspective but we wanted and the deal at Statoil allows us to manage some of those cause of risks while we're maintaining control in exposing ourselves to material prospects that have running room and that are early in the lower tertiary position we think does that for us. So it's going to be another area of references for us in our exploration program. Blake Fernandez - Howard Weil: Okay great and the last one I have for you, you mentioned the kind of the net earnings impact as a result of crude differentials which are clearly compressed. I'm just curious if there's any outlook from you guys going forward as maybe more OPEC barrels coming to market potentially ramp up of Canadian oil sands development? Do you have any sense that differential environment is going to materially improve over the coming year?

Well some people believe that the heavy light differentials will move with improvements in general economic activity so if overall demand crude oil increases then you’ll see additional heavy sour barrels coming out of the Middle East. The Canadian production is going to take some time to materialize the new capacity that we have seen in Asia and also some of the capital spending that U.S. refiners have done and then pointed towards coking and other heavy oil handling investments and so that that kind of puts more demand for heavy oil. So, I don’t think we expected to go back to where it was, lets say in the middle part of the decade 2005, 2006, I don’t think we are expecting $20 heavy, light debts but maybe a little bit wider than it is now. Only other comment on refining, I notice this isn’t really to your point but we do expect the West Coast to get better than its been. The West Coast margins have really got creamed over the fourth quarter and that was part of what contributed to our results and that we have few refineries on the West Coast. Blake Fernandez - Howard Weil: Right. Okay, well thanks so much Clayton, I appreciate it.

Your next question comes from the line of Arjun Murti with Goldman Sachs. Please proceed with your question. Arjun Murti - Goldman Sachs: Thanks. Clayton just a question on the Surmont announcement from this week, do you have a CapEx number to go with the production increase you talked about in the release?

We are not sharing it. We have. Arjun Murti - Goldman Sachs: I'm glad you have one, that's at least good. So can you provide any color of how you kind of see that versus Foster Creek? Chrisitna Lake, I guess is part of the question as well.

Sure. And we don't provide project level CapEx, but I would say it's competitive within our portfolio, I'd say I think it's in line with where we see FCCL CapEx or requirement, we want to stage these things at different times. Surmount Well begin construction this year. This is a build on of from an earlier phase, and I think peak production from Phase 2, we're expecting in 2017. Arjun Murti - Goldman Sachs: I guess Foster Creek Christina Lake seems to be clearly be an excellent project and no disrespect to Surmount, it has been viewed as difficult to measure up the Foster Creek Christina Lake, but it sounds like you always had some encouragement as you've run the pilot that the economics are actually quite competitive.

That's right, and in this way, this in no way crowds out investment into Foster Creek or Christina Lake. Arjun Murti - Goldman Sachs: That is terrific. That's it Clayton. Thanks a lot.

Okay.

Your next question comes from the line of Jason Gammel with Macquarie. Please proceed with your question. Jason Gammel - Macquarie: You kind of answered my question on refining but on the West Coast, we've been looking at margins that were probably not covering cash operating expenses which I believe were confirmed by another report today, could you confirm if you are seeing something similar and also does it help you to reduce run rates or your cost effects in such that you would probably still run at a higher utilization even if you bring in cash?

No, I think what you know when you're making these decisions around run rates, you have to take a perspective view on where you think cracks are going to be and for us we always say you have to cover your variable costs. So you’ve got to be positive cash. The rates that we saw in California, the crack spreads were so low that you know they are just not sustainable. Refineries will take additional run cuts or shut down. But we don’t want to burn cash but when we are making those kinds of decisions we are making a set of forward look on what we expect those cracks to be, what we expect the differentials to be on heavy light, what we expect movements in crude impact on secondary products but if we are not covering our variable costs we have to take steps to curtail production. Jason Gammel - Macquarie: Okay. Thanks for that. Also if I could just clarify on the gas curtailments, the $145 million a day that you mentioned in the fourth quarter is that U.S. only or is that total North America.

Its total North America. Jason Gammel - Macquarie: Okay and now you’ve got production down sequentially about 320 a day versus the third quarter so is the incremental effect simply a decline effect as a result of lower level of drilling activity.

That’s correct. Jason Gammel - Macquarie: Okay. And then finally if I could there’s been quite a few heads of agreements or purchase sale agreements signed in the Pacific Basin over the last six months, is that affecting how you are marketing ALNG and can you talk about any progress that’s been made on the marketing front for that project.

So we are still active you know we’ve announced some things over the last month around mostly upstream awards of engineering and project awards. We haven’t said anything about our marketing activity, given that these things are fairly sensitive and you don’t want to tip your hand on commercial negotiations. So all I can tell you is you know we are actively pursuing the marketing of two trains, of LNG out of Queensland and there is a lot of interest and we expect to announce something before the end of the year.

Your next question comes from the line of Doug Leggate with Merrill Lynch. Please proceed with your question. Doug Leggate - Merrill Lynch: Clayton, I wanted to jump back to the production guidance. Can you give any sense of what the magnitude of disposals might look like and how that may impact the production for the year? What was behind my question is as your debt targeting, as I guess your cash flow, your assumed cash power of the portfolio has a production capacity in mind when you do that. So, if you could give us some help just around how you are thinking about that would be great?

Yes, so we really haven’t tried to give order of magnitude on what the impact of asset sales is going be. Syncrude is around 25,000 a day but that depends on when the asset would be sold. Right? So the 2010 guidance really isn’t factoring in any impact from asset sales. Doug Leggate - Merrill Lynch: Okay, I guess you will give more color on lots of these and strategy there.

Yeah. Doug Leggate - Merrill Lynch: Okay, the another one I have is, I wanted to jump back to CapEx. What exactly is the pacing of the CapEx coming out of ALNG? How much is in for this year because that was expected to ramp up, but my understanding is that you managed to negotiate so much better I guess E&C contracts and so on may be those CapEx numbers are coming down. So some idea of that would be appreciated?

I don’t have that and I would assume that we didn’t. We don’t give project-related CapEx guidance, I don't know if we had provided it in our 2010 capital press release that we may done it for the region or for the country. Its early days in APLNG, contracts are been awarded, but I don't see a lot of capital going into that project right now. I think generally, on the projects like these, you need to get certain things in place before you ramp up on capital spending, so I would say the bulk of the capital going to APLNG is going to be later in the decade. Doug Leggate - Merrill Lynch: I guess just one final one if I can squeeze it in, kind of related question.

Sure. Doug Leggate - Merrill Lynch: There was some noise on the wires a few weeks back about what was going on Shah, and I know that Jim has been very clear that that was not in the 2010 budget. So are you basically going to be sort of pulling out of that project altogether, or any update, will be appreciative.

So I think, I can just give the same answer Jim has been giving and that's we continue to work the project and no decision has been made and when we get to the point, when we're going forward, or not going forward, then we'll share that with you. I think when we look at Shah or look at other projects, all these things have got to compete for capital and have got to general higher returns, and that's how we look at it and other major projects like it. Doug Leggate - Merrill Lynch: All right, terrific, thanks Clayton.

Your next question comes from the line of Ryan Todd with Morgan Stanley. Please proceed with your question. Ryan Todd - Morgan Stanley: I just had a quick question on U.S. refining I mean is it safe to say from your comments that other than maybe some efforts that cost control that you're not considering anything out in the ways of rationalization or sell there or JVs or anything out to there to handle the situation that's just cost control and then riding out the environment?

Well I don’t think we're just sitting our hands I think that we are going to look at run cuts in certain areas but that where the refineries aren’t covering the variable cost. Your probably familiar that we had Wilhelmshaven down for most of the fourth quarter. I think there are other, so yes you can cut costs you can constrain capital that would be going into projects for expansion type projects as part of our design to improve our returns over time we said that we want to have a smaller downstream business you know 15% to 20% of our total portfolio being downstream, instead of the 20% to 25% where we are now but that's going to take some time given the environment for refineries. So I guess I would say a little bit differently there may not be a lot that we can do from a portfolio perspective in 2010 in terms of finding creative ways to generate higher returns out of that business but over the next several years as we go forward in this you could expect us to look at creative ways of reducing our exposure to the downstream. Is that fair? Ryan Todd - Morgan Stanley: Yes, that is. Earlier you'd said that you would expect this in terms of asset divestitures it would be more likely that you refining divestitures a couple of years out down the line and…

And I think that’s a function of the market. Ryan Todd - Morgan Stanley: And then that would still seem to, that would still be the position.

I think that’s right, that’s probably a good question for Willy or Jim at the end of March at the analyst meeting. Ryan Todd - Morgan Stanley: And on the West Coast you mentioned obviously there has been tremendous weakness in west coast margins and what do you think from your perspective out there what has been driving the weakness? Is it just a blow down of winter grade gasoline and you commented, you expected it to get better, any comments on why the weakness and why you would expect it to get better in the near term?

I think you have already seen it improve a little bit here in the last week or so, but I think its imports and demand levels on the west coast that had been very low, but I can't give you specifics to why the West Coast has done so poorly but its at a level or it was at a level that it was operating below variable cost and at that point you start seeing refineries curtail and you start seeing imports or you start seeing water-borne clean products go to different markets. So, that has a tendency to clean itself up. When we hadn’t seen product spreads at that level, I don’t think that we did – it’s a historical. That’s what was behind that comment. Ryan Todd - Morgan Stanley: Okay. And on a different note, you mentioned the Origin JV and the Australian LNG project. Can you give us any, as we look towards 2010, an idea of potentially what project sanctions you might have in store or potential project sanctions for the year?

So that would be one of them. We've got to make a call where were another on Shah, I think obviously QG3 is going forward. You've got the Jasmine project in the North Sea. Let's see because I've got project slide here somewhere. They are I think the Alpine West has been pushed out, Gumusut in production. Let me come back to you on as far as specific project sanctions or, and this is going to be something that we'll talk about as well in March. Ryan Todd - Morgan Stanley: Okay.

Okay. Ryan Todd - Morgan Stanley: Okay, I appreciate the help.

Mr. Reasor, there are no further questions at this time.

Great, I just want to thank everybody for their participation in the call, and information's available on our website, will certainly available to follow-up, if you've got any additional questions. Thank you.

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