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

Good morning and welcome to our third quarter earnings conference call. I'm joined this morning by Jim Mulva, ConocoPhillips' Chairman and CEO, and Sig Cornelius, Senior Vice President Finance and Chief Financial Officer. As we have done in the past, there is presentation material; we will refer to as part of our prepared remarks, and you can find the information on our website. We'll begin this morning's call with Sig covering our third quarter results and sharing progress toward meeting our 2009 objectives. And following Sig's remarks, Jim Mulva will provide his thoughts and perspectives regarding our plans to enhance returns and strengthen our financial position through asset sales and modifications to our 2010 capital budget. After Jim's comments, we will open the phone lines to take your questions. But before I turn the call over to Sig, I need to direct your attention to the Safe Harbor statement we provided on page two. This is a reminder that we will make forward-looking statements as part of our presentation and the Q&A session, and actual results may be materially different. The sources of these differences may be found in our filings with the SEC. And now, I would like to turn the call over to our Chief Financial Officer, Sig Cornelius.

Thanks, Clayton. I will start my comments on slide three. At our analyst meeting last March, we discussed some of the significant challenges that were facing our company and the industry. I'm pleased to say that, as we have progressed through the year, we have begun to see some positive signs with respect to improvement in the global economy and corresponding energy demand, while there are still some challenges for North American natural gas marketing and refining, the picture today looks more encouraging than earlier in the year. From our own company perspective, we have been very focused on executing our business plan and have delivered strong operational results thus far. In addition, over the last several months, we have been focused on developing plans that will accelerate progress on improving our financial position and returns over time. As Clayton said, Jim will speak more about this last point at the end of my remarks. Slide four shows some of the major drivers to the company's performance in our view of the current status. Compared to earlier in the year, oil prices are higher than we expected and appear to be constructive for long-term investment. According to the Department of Energy, compared to a year ago global oil consumption declined by 3.2 million barrels per day in the first half of 2009 and an estimated 1.2 million barrels per day in the third quarter. For the fourth quarter, they are forecasting growth from last year, and if seen, this will be the first time that demand has increased in the past five quarters. In 2010 the EIA predicts world oil consumption will grow by 1.1 million barrels per day, while demand is showing signs of improvement, there are still some important factors that could influence future prices such as OPEC production levels, inventory draw downs and the pace of the global economic recovery. Although, North American natural gas prices have seasonally rebounded from very low levels this summer, we expect them to remain weak in the near-term due to record storage levels, driven by declining industrial gas demand and the continued impact on new supply from shale developments, while supplies are being reduced due to lower activity levels and voluntary curtailments, these factors can be reversed fairly quickly and will keep downward pressure on prices. In addition, the potential exists for a reversal of coal to gas substitution for power generation, which has provided significant demand for gas so far this year. In the longer-term, we believe prices will need to recover to a higher level to support continued investment in North American gas development. The other key driver of our business is refining margins, which have been very weak this year, while it may be too early to declare the bottom of the cycle, there are some indications that the supply/demand imbalance will be corrected over the next few years, as capacity is idled and demand increases along with the rebound in the economy. I will now turn to our third quarter highlights beginning on slide five. As you would expect, the macro factors I just discussed played a key role in our results for the quarter. Compared to last year, our earnings were down by around 70% with the primary variance due to prices and margins. Earnings for the quarter were $1.5 billion or $1.00 per share with cash from operations of $2.9 billion. We ended the quarter with debt of $30.5 billion, resulting in a debt to capital ratio of 33%, which is down 1% versus last quarter. On the operational side, total production, including our share of LUKOIL, was 2.2 million BOE per day. E&P production was up more than 40,000 BOE per day versus last year, and global refining utilization was also higher at 90%. Continuing the trend from the first two quarters, operating costs across the company were down by 16% due to market improvements and cost reduction initiatives. Turning now to slide six, as mentioned, total earnings were down by some 70% compared to last year. The slide shows the changes by segments. The biggest decrease was in our E&P segment, driven by lower oil and gas prices. Prices and margins were also the largest variants in our downstream segment. For all segments prices, margins and other market impacts decreased our earnings by nearly $4.4 billion in aggregate. This was partially offset by higher volumes, primarily in our E&P segment, and operating cost reductions of more than $400 million after-tax across the company. Slide seven outlines our cash flow performance. In the third quarter, we generated nearly $3 billion of cash from operations, including a small decrease in working capital. We had capital spend of $2.9 billion and dividends of $700 million. The other bar includes asset dispositions of $700 million, primarily related to the sale of our interest in the Keystone pipeline. Total debt remained essentially flat quarter-to-quarter. I am moving now to a review of our segment performance, starting with total company production on slide eight. Overall E&P production was up 2.2% or 43,000 BOE per day versus last year. In aggregate, market factors contributed 8000 BOE per day, due primarily to a benefit from lower royalty volumes in North America, which was partially offset by market related voluntary gas curtailments which began in late August. This included deferral of some new well hookups, as well as selected production curtailments. The total impact related to these actions was approximately 70 million cubic feet a day for the quarter. At the end of the quarter, we had approximately 300 million cubic feet a day of gas curtailed across North America. Moving to the left, planned maintenance was higher compared to last year, primarily in the U.K. and Norway. This was partially offset by improved volumes due to the absence of hurricane impacts versus last year. In our operations category, production from new projects more than offset decline and other operational factors and contributed a positive 57,000 BOE per day. When you add our share of LUKOIL production, which is an estimated 424,000 BOE per day, total company production was slightly above 2.2 million BOE per day for the quarter. Now turning to slide nine, total E&P earnings for the third quarter were nearly $1 billion, down from $3.9 billion last year. The tables on the bottom of the slide breakout the earnings variances by geographic area and by price realizations. On a percentage basis, U.S. earnings are down by nearly $1.3 billion or 80% versus last year, while international earnings are down by $1.7 billion or 72%. These changes are generally in line with the changes in realized prices, which are shown on the right side of the table. Compared to last year, gas prices were down nearly 60%, crude prices were down some 40%, and NGL prices dropped by 50%. In total, lower prices negatively impacted earnings by around $3.5 billion. After including the price impacts on production taxes, the overall decrease was slightly over $3.1 billion, which is shown by the second bar from the left on the chart. The higher production, combined with reversal of the under-lift position from the second quarter, resulted in nearly a $350 million increase to earnings. Operating cost reductions contributed nearly another $200 million to earnings. The other bar primarily reflects the absence of asset disposition benefits seen last year and a small foreign currency loss compared to a gain last year. We also had higher dry hole costs this quarter, primarily related to the Kontiki well in the Browse Basin. The R&M earnings variance is shown on slide 10. Although, our sequential results were better and we were able to generate positive net income this quarter, overall refining margins remained challenged. Compared to last year, realized margins reduced earnings by more than $1 billion. The decrease was particularly acute in our international business as the realized margins dropped by 67%, driven primarily by a similar reduction in the market crack. Although, overall refining volumes were up, this was more than offset by lower marketing volumes due primarily to the disposition of retail assets. Lower operating costs improved earnings by around $180 million, due primarily to lower utility costs and some operational savings. The improvement in the other bar is due to the absence of foreign currency losses, partially offset by an accrual for a tax related audit. I will now move to slide 11, which shows the variances for our LUKOIL segment. LUKOIL earnings were $545 million for the quarter, up 24% versus last year. Estimated operating results reduced earnings by some $90 million, reflecting the impact of lower prices, partially offset by the lower export and extraction taxes and higher volumes. The net change in the true-up of our estimated results to LUKOIL's reported results was a benefit of $135 million, which includes $33 million from the second quarter 2009 true-up. The reported results also have a current quarter benefit of approximately $50 million related to basis amortization compared to a loss of $25 million last year. Slide 12 shows the variances for all our other segments. In Midstream, we experienced lower results due to significantly lower NGL prices, slightly offset by higher volumes. Our share of CPChem results were $58 million higher due to lower operating costs and higher utilization rates, partially offset by lower margins. Corporate expenses were $283 million after tax for the quarter, generally in line with last year. That completes my review of our third quarter results. I will wrap up with some comments on our year-to-date business plan performance and outlook beginning on slide 13. The boxes along the top show the focus areas that we outlined in March, along with some specific areas of emphasis under each box. The red bar on the bottom of the slide shows a high level assessment of where we are in achieving these objectives. On the capital optimization effort, we outlined a lower capital budget for 2009 to live within our means while still funding key growth initiatives and preserving option value in our asset base. This proved difficult in the first half of the year, as low prices and working capital increases resulted in lower cash flow and somewhat higher debt levels. However, as you saw earlier in the cash flow slide, results are significantly improved, and we now expect yearend debt levels to decline the balance of the year. On our cost reduction efforts, we expected to see cost reductions back to or below our 2007 levels, which represented a 10% reduction versus 2008. Our goal was based on capturing market driven reductions, along with driving self-help opportunities. Through the third quarter, we have achieved our full year objective and continue to seek additional cost reduction opportunities. Our final focus area is on operational excellence, which remains a key competitive strength. As you will see on the next slide, we are driving strong operational results, which have helped lessen the impact of commodity price decreases. Slide 14 provides you some highlights of some of our key operational results so far this year. With production up more than 5% year-to-date versus the same period last year, we have exceeded the target communicated in March due to strong performance in our base assets and a significant amount of new production from major projects. In addition, as I noted, we have achieved our full year operating cost reduction target, representing a 14% reduction versus last year. We are also continuing to progress our key growth projects such as Canadian Oil Sands, QG3 and APLNG that will drive production growth in the future. On the exploration front, we have delivered several key successes in our refocused exploration program, as well as enhanced our future portfolio with new positions in Indonesia, Coal Bed Methane in China and Shale Gas in Poland. Finally, in early October, we announced a 6% increase to our quarterly dividend. I will conclude my remarks with slide 15, which provides an outlook for the fourth quarter. We expect full year E&P production to be 1.85 million BOE per day or more than 3% higher than full year 2008. Our global refining utilization for the fourth quarter is expected to be in the upper 70% range, primarily reflecting an expectation that our [Wilhelmshaven] refinery will be in turnaround for the majority of the quarter. In the fourth quarter, we expect to resume premium coke production at Humber and Lake Charles based on increasing product demand. During the fourth quarter, we also plan to draw down discretionary inventory positions that have been held during the year in response to Contango market opportunities. These positions have negatively impacted working capital and earnings year-to-date due to mark-to-market accounting. We expect to realize a benefit of around $1.5 billion in cash and $150 million in earnings related to this draw down. With respect to some of our major projects, in the fourth quarter, we will see incremental benefit from the startup of our North Belut field in the Natuna Sea, as well as improvements in clean product yield at the San Francisco refinery due to the recent startup of the new hydrocracker. We made the final investment decision for further expansion on Christina Lake 1D and are nearing final investment decision on Surmont Phase 2. On the exploration front, the operator of the Tiber exploration well [BP], announced its giant Gulf of Mexico deepwater discovery during the third quarter. We also had the Shenandoah discovery earlier in the year and are currently drilling the Rickenbacker Prospect which is located near by the (inaudible) discovery. Also, in the lower 48, we have been encouraged by recent drilling results in the Eagle Ford Shale, where we hold a sizable low cost acreage position. In the Browse Basin in Australia, we have spun an appraisal well of the Poseidon discovery announced earlier. We expect to reach TD on this well in the first quarter of next year. Finally, late in the fourth quarter, we expect to spud a well in Laurentian Basin in offshore Canada near Newfoundland. This concludes my overview of the third quarter results and the fourth quarter outlook. I will now turn the call over to Jim, who will elaborate on our strategic guidance provided a few weeks ago.

Okay, Sig. Thank you. Earlier this month, we did put out a media release regarding our program to enhance our returns using normalized assumptions for our portfolio. This was a two-year program, but it is more than two years. It will continue beyond. So, what I would like to do in this conference call is give you a little bit more information on what we just announced. If you look at ConocoPhillips, we've created the company you see today over the past 10 years, and we certainly believe we have the scope and size to compete. We have the technology and the people to compete. But the business environment has quite dramatically changed here recently in the last 12 months to 18 months. First, as everyone knows, we are going through a very deep worldwide recession and its impact on the credit markets. And then the other very important point is access continues and will be an issue for companies like ConocoPhillips and international oil companies. So, we started our response to this different business environment in the latter part of 2008 and early 2009 by constraining our capital program to $12.5 billion and delivered within our means. So, what we announced in October was really a continuation of what we started in late 2008, early 2009. As a company, we have 50 billion barrels equivalent of resources to develop, and so it is important for us to really have our eye on the 50 billion barrels of resources how we can develop and commercialize them. We will continue as an international integrated company, but as we announced, we will be somewhat smaller. Our emphasis will be on return enhancement over growth, and let me explain why. First of all, as I said, we have resources and the portfolio of opportunities to do and to develop our company, for us it is really a prioritization of which projects we really need and want to do, which is going to have the impact on improving our return on capital employed. As I said, the business environment has changed dramatically. Access is and will continue to be quite an issue. So, what can you expect from us over the next several years? Well, as I said, the objective is to enhance the portfolio and the returns in our portfolio. We are going to do this by constraining our capital spending in 2010 to $11 billion. We have done exhaustive reviews over the last six months with respect to our portfolio, our opportunities under all different pricing environments, and we believe $11 billion is really the sweet spot for us in terms of our capital spending given the business environment in 2010. We intend to sell $10 billion of non-strategic assets over the two-year period of 2010 to 2011. And the asset dispositions is not dependent upon the commodity markets up or down or crack spreads. This is just a plan that we intend to be doing over the next two years. A substantial part of the asset dispositions will be directed towards debt reduction, as we might get back toward our 20% to 25% debt ratio. We think and believe that annual increases in dividends is a very important discipline for our company and is recognized and our shareholders like to see that. In terms of our capital spending of $11 billion, about 90% of the $11 billion will go to the development of Exploration & Production, and we do not see any real reduction in our exploration spend, as we organically believe that we have the opportunities and we are really improving on the exploration aspect of the company. The 10% of the $11 billion will be directed towards the downstream, and that is really towards maintenance capital and not really much for growth. With the above, you can see strategically, and we will share more of this at the Analyst Meeting in the early part of 2010. We are going to be moving E&P towards nearly 80% of our portfolio with time in terms of what we dispose and how we spend nearly 90% of our capital towards E&P with downstream with time moving towards 15% to 20% of the portfolio. Doing the things that I have outlined, we expect that we will replace our reserves after we give consideration of the asset dispositions that we will be making over the next two-year period of time. And the replacement of reserves are going to come from existing opportunities, discrete projects we have, not from assumed exploration success. And in the latter part of the next several years, we will see some growth from this after we make our dispositions. There will be some growth in production and that will be in the latter part of this several years. And we will share more of that with respect to you when we meet with the financial community in the early part of 2010. 40% plus of our reserve adds over the next several years will be coming from a very strong position in the oil sands of Canada, and I suspect there may be some questions about the oil sands in Canada and Sig has some metrics. We have very good metrics in terms of what we are currently doing and expect to do with the oil sands. So, what is it that we are thinking of selling? Well, I'm not going to go through the exhaustive or complete list, but I'm going to give you some indication of what we have in mind. For the last five years, we have received a great deal of interest in our 9% ownership interest in Syncrude. We are not the operator. It is a good investment, but we think that there is plenty of interest. And so, we are going to be looking and testing the market on our 9% of Syncrude, and you can expect that early part of next year. We will also be looking at disposing the bottom 10% of our North American E&P position. That is Canada and the lower 48. On the downstream we will be looking primarily in the U.S. on downstream pipelines and terminals. In terms of the Southern North Sea assets, primarily gas, we think that certain of these assets may be of more interest to someone else than to ourselves. And then, there are quite a number of things that we are looking at that we have on our list, but either for competitive or confidential reasons, we really don't feel it is appropriate to comment at this point in time, but there will be more information, as we go through 2010. I'm merely trying to give you some more information from our media release. So, what we are going to be concentrating on the early part of 2010. With respect to refineries, it is not a very good market to part with or sell refineries. And so that is not in our $10 billion program, although, if we have an opportunity, we certainly will be looking at disposition of the less sophisticated refineries or less competitive refineries. So, what we do have in mind is that we believe that the refining market will improve somewhat from what we have experienced here, such that we will be looking at disposition of refineries in the years 2012 to 2013. So, the plan that you see on asset dispositions in 2010 and 2011, we will continue to always look at how we can continue to improve and upgrade the return enhancement of our portfolio. So by prioritizing our future investments, the asset dispositions and cost constraint, why we expect that over this two-year period of time there will be a several point improvement in our return on capital employed using normalized assumptions. And when we look at normalized assumptions, we are using $70 WTI, $5 Henry Hub natural gas price and $5 Gulf Coast cracks spread. And that's a comparison of several percent improvement on these normalized assumptions by following this program versus not following the program. So, some will say that what we are doing is essentially shrinking to grow. That can be a fair assessment, but what I would really like to stress is what we are doing is return enhancement and not stressing growth as much as we have had in the past because we have the resources to develop, and as well as the business environment access speed and issue is why we are embarking upon the program that we have outlined. So, those are the comments. Clayton, I think it is time to open up for questions.

If there are some people who would like to ask a question we will be prepared to take them now.

(Operator Instructions). Your first question comes from the line of Doug Terreson. Please proceed with your question.

Jim, on the divestiture program, you mentioned that there are several interested parties in Syncrude, which is not surprising. And so, while I realize it is early, can you talk a little bit about the level of interest on the other portions of the initial $10 billion package?

Well, it is a little premature to tell, but we would not have them in the package if we did not think we had really some interest in it. We have demonstrated the Keystone pipeline we sold earlier several months ago. There is quite an interest from TransCanada. So, we will be looking at some of the pipelines for instance, the REX pipeline. We are very pleased that it is essentially close to completion and starting up. But from a strategic point of view, we don't need that. We think there will be a fair degree of interest in that. With the commodity markets, we believe that the bottom 10% of our North American portfolio will have a lot of interest, and we have received a lot of phone calls and interest in that. So, we look at that as cleanup. Essentially, what it does is it really moves some of these properties to someone that sees a lot more value than we do ourselves. And then, in Southern North Sea gas, we know there is a lot of interest in that. So, I would have to say it's just the response we have already seen and received that there is a lot of interest in this. So, we think that what we have in mind is achievable.

That is a good sign. And just second, during the past decade, all of the super majors have sought investment in Russia with the expectation that economic conditions would justify doing so, although, the reality has been somewhat more challenging. So, I wanted to see if you would comment on your strategic thinking towards your position in Russia, which has turned out well in relation to a lot of the competitors. And it is obviously significant because it is around $11 billion in the market today. So, would you comment on that on your thinking there?

Well, we have had a great relationship and do with LUKOIL and with the Russian authorities. And I think, it is probably most appropriate that I would say, we recognize what is taking place and the opportunities in oil with respect to Russia. But I think the appropriate and right response is really that we intend to maintain a strategic relationship with LUKOIL.

Your next question comes from the line of Robert Kessler. Please proceed with your question.

Good morning guys, I wanted to see if you might spend a little bit more time clarifying the 300 million cubic feet a day of North American natural gas that shut is in. Specifically, I'm wondering, if you can give us some color around the illogic on shutting that in? Is it just a price driven shut-in? It looks like it happened around, say, 250, yes, and as a consequence, should we think of that as the cash breakeven threshold for roughly 10% of your North American production, or was there some other logistical constraint at play there? And then also, if you could provide some color around the geographic split of the production that was shut-in?

Sure. I would be happy to, Robert. First of all, the decision was made as you premised correctly basically on a price related decision. It really had nothing to do with the cost aspect of it. We made a decision based on the expectation that we could realize significantly higher prices in the near-term of those August to September lows, which would more than offset the cost of shutting in. You might ask, why did we shut-in 300 million? Basically it came down to a do-ability issue. We looked at several factors in determining which properties we were going to curtail, the cost of shutting in, partner alignment, reservoir suitability, decline characteristics and contractual obligations, and we made a value based judgment taking all these factors into consideration. As far as the split goes, it was about 2/3 in Canada and about 1/3 in the lower 48. And as far as kind of the cost basis, our cost to production, variable cost of production is very low and sub $2, so it was not a cost issue.

And then, you mentioned 300 offline at the end of the quarter, any comment as to what that rate is now, how much it might still be offline, or given that gas prices have doubled off the lows, have you brought some of that back online?

Yes, we started bringing some of it back on this month, and I would think in November that the lion's share of it would be back on production.

Thanks for that clarification.

Your next question comes from the line of Mark Flannery. Please proceed with your question.

Thanks. I would like to talk about the cost reductions that you mentioned in the release and on the call. The 14% year-over-year cost reduction, could you split out for us how much of that was lower energy and utility costs and how much was down your own self-help actions? And maybe comment on, is there anymore self-help you can do to push that cost reduction program forward in 2010?

Sure, Mark. I would be happy to. I think what we alluded to earlier in the second quarter call the same percentages basically hold true that we were looking at about 70% of the cost reductions due to market impacts, and that is split between FX and other commodity prices, utilities and fuel. On the E&P side, most of the improvements are coming from FX, and on the refining and marketing side, most of the improvements are coming from the utility side. So a little bit different composition between the segments there. So, the balance is really kind of self-help initiatives and cost control initiatives. We continue to pursue aggressively cost reductions across the board in working with our service providers and our other suppliers out there. So, we will continue to work the cost numbers going forward. I would say that some of the cost reductions are starting to moderate certainly compared to the first of the year, but we still see room for improvements.

I wonder, if I could just jam in a quick follow-up on the cost of gas in North America. You mentioned the variable cost of production was under $2. Do you have an average idea for us what the capital costs associated with maintaining that level of production is for the portfolio as a whole?

Well, I think, yes, I assume you're talking about what kind of capital we need to reinvest to keep production flat. We have not worked it to that level. We do know we have the inventory and the portfolio that we could not only keep production flat but grow production, and really it comes down to kind of a value question. So, it is just not strictly a capital question. It really is there value in pursuing either flat growth, flat or growth at this point.

Your next question comes from the line of Paul Sankey. Please proceed with your question.

Hi, good morning, everyone. Jim, if I think about the program, the ultimate aim is to raise returns. But you're not selling refining because the market is too poor. Surely a lot of the assets that you are selling here are relatively high return assets, and therefore, it is going to be dilutive on your returns, at least certainly in the near-term, to sell these assets?

Well, you make a good point. The improvement in return is really going to come from where we invest our money and where we don't invest. So the projects going forward that don't have the returns that we need. So, it really doesn't come from asset dispositions. The return enhancement on normalized assumption is really going to come from where we invest and where we don't invest. And then also, we believe, as Sig indicated, that we will continue to make a modest improvement in our cost reduction. I think I would say on the cost issue, we are going to be even a lot more aggressive, continue to be a lot more aggressive. And the question is, how much are we going to be able to sustain? But our targets are to do at least as good as costs, we had back in 2007.

Right. And not investing I guess thinking as well in the context of $11 billion a year of spending, which I think is an ongoing guidance as opposed to just 2010. There are really four major projects that come to mind that would be difficult to fit within that $11 billion level. One would be Wilhelmshaven, another would be Yanbu, another would be Abu Dhabi, and the last one would be Origin. Would those be the ones that you were thinking about pulling back from? Thanks.

In terms of the capital spend, you are correct. The last several years other than unusual items we have been spending $14 billion, $15 billion a year. I think the guidance going forward is you can expect us to be in the $11 billion range over the next several years. It will tend to trend up a little bit after several years, but I think the guidance is, you should be looking at $11 billion. In terms of investment decisions, the investment decisions regarding Yanbu and Shaw are going to be coming up in the first quarter, maybe the latter part of the first quarter, early second quarter of this next year. And so, those projects are going to have to meet our return expectations and there is not a lot of money in our $11 billion program for those projects at this point in time. In term of Wilhelmshaven given the market conditions and all we really don't have money in our $11 billion program next year, so you can expect that as likelihood that that look at deferred. In terms of our Queensland project with Origin, that is a project that we really feel quite strong about in terms of resource, capability, the cost. And the real question for us is, we are working very hard and our expectations of selling LNG, and for competitive reasons we would rather not go into that. But you are not going to see too much change at all in our plans with respect to development of the project in Queensland.

Right. And then, you have really highlighted the word organic, which I guess rules out the expansion from an acquisition point of view. But I understand from the $11 billion base you would be looking at around a 1% volume growth aspiration kind of going forward from that lower base, which would then, I guess, be returns accreted?

That is right. And I think what you will see from us, and it is early at this point in time, but our thought is that from a new base of production after we look at dispositions, holding our production at a plateau and then in the subsequent years raising it 1% or 2%. So, the description of shrink to grow is pretty valid.

Yeah, and if I think upon the fact that you said that the initial interest has been very strong, I am concerned that the $10 billion program involve that marketing assets well an excessive $10 billion value which by extension could mean that you generate more than $10 billion of proceeds and if I continue, I would then say that that would take you beyond the pay down of debt aspiration you have. Would you then get into buyback?

Well, I think you make a good point. So, we have a list of assets, it is quite exhaustive that goes quite a bit more than $10 billion. Because we don't know which assets someone would really have more interest in, and we can get a better price for than another. And we also want to make sure that it is tax efficient from that point of view. So, to the extent a number of people look at going forward your consensus views on what the market expectations will be, and quite a few people see some pretty strong free cash flow for our company, as we go into 2010 and 2011 with these assumptions and spending $11 billion. If the market gets much, much stronger, meaning oil prices, crack spreads or gas prices. Well, you may see us increasing our capital a couple of hundred million dollars or so, and those would make sense because their quick drilling opportunities are all that we would do. So, the free cash flow that comes, debt is not an issue in terms technically or with the cost of the debt, but as we bring the debt down and reach our objectives, and what can we do with our cash flow? Well, we said, we wanted to increase our dividends annually. So then, after we have satisfied our capital spending say a little bit more than $11 billion, we are certainly reaching and getting our debt down, raising our dividends, and we will consider a share repurchase. You are right.

Great. And then, if I could just clarify an early question. We are saying that you will not be selling out of any of the LUKOIL state? Thanks, I will leave it there. Thank you.

Well, what I said is, we will maintain our strategic relationship with LUKOIL.

I think we said also that the $10 billion in asset sales don't include any of the LUKOIL share.

Thanks guys.

Your next question comes from the line of Neil McMahon. Please proceed with your question.

Hi, just a few. Just looking at exploration catalysts, you have mentioned the Rickenbacker prospect that is drilling. When do you expect that to finish drilling? And just looking out over the next six to nine months, apart from the Poseidon appraisal well, what other exploration catalysts have you got coming up, and I have got a few follow-ups?

Sure. I think the Rickenbacker well is scheduled to TD early next year. And that we have a 45% interest in that well operated by Anadarko. The Poseidon well, I mentioned it is going to TD, we anticipate the first quarter of next year as well. I mentioned the Laurentian well on the call in my prepared remarks. That is the well-off Canada in the Newfoundland area. So that is a highlight well that you should watch from a portfolio standpoint. And then block-in, yes, that will be a 2010 drilling and block-in. Of course, we'll have the analyst call before then, and we can go through all the exploration catalysts and high profile wells then.

Great. Just a quick one on you mentioned some of the refineries have starting to produce premium coke again indicating that demand is coming back. Are you really seeing that across the spectrum apart from gasoline in the U.S.? Are you getting any indication whatsoever regionally that diesel demand or distillate demand is coming back?

We are starting to see some moderate improvement, but it is sluggish. And certainly the premium coke market, as you probably know, is kind of a niche market opportunity, but does indicate some strength in the overall economy starting to improve.

And the last one for Jim. Jim, what you have outlined is pretty radical change based on what we are seeing from some of your peers. Do you think this sort of signals end of the large integrated business model? It seems like the investors have reached this conclusion some time ago. Maybe you could just give us your thoughts on what made you go down this route and what you think it means for the rest of the industry? And potentially could we see this as a strategy others might follow down the road as the integrated model continues to be not one shareholders want to buy into?

Well, you make an interesting point. And I guess, Neil, what I would say is, it is difficult for me to talk and not appropriate for other companies. But I think the industry and our company we have noticed that our access is just not what it used to be, and there is no indication that access is going to change in terms of the opportunities. They become more challenged in the expense of capital and the returns that you achieve. And I think, we distinguish ourselves to some extent. We have got some very large positions already that we have put in place and developed over the last 10 years. So, we really, and the terms and conditions associated with them are really pretty attractive compared to what the access opportunities we see going forward. So for us, it really dictates for the value creation for the shareholder a different model. We continue to be an international integrated company, but I think we are going to be somewhat smaller. So, what it really argues for, at least for our company is a somewhat smaller company, but still have the capability of doing things, will create a lot more value for the shareholder than distressing the growth and taking the opportunities that are available in terms of access. So, I think longer-term, I can't speak for the other companies, but it is time, it has really changed compared to the prior decades. I think it is going to take a somewhat different model. This is the right approach for us over the next number of years, and I think international oil companies are going to have to really look at a somewhat different model by which how do they participate in work with national oil companies and sovereigns with respect to this issue of access and development of returns. If it is not there, well, then obviously the companies will get somewhat smaller.

Your next question comes from the line of Jason Gammel. Please proceed with your question.

I think you wanted to come back to the exploration program. Can you talk qualitatively about what you have done to increase your internal capabilities and then possibly also the asset portfolio that has led you to become more comfortable with increasing the investment in the exploration program? And then, address possibly when you would expect to see contributions from the exploration program to the 1% to 2% production growth target that you talked about earlier today?

Well, that is a lot of aspect to that question, Jason, but I will try to give you some color to it. First of all, we bought in different people going to starting with the top. Larry Archibald is our new Exploration Manager, as you probably know. Larry came in and was asked to kind of take a look of what we have been doing from an exploration program standpoint, our portfolio, our people and kind of look at it from a top-down. I think Larry would tell you that it wasn't a major overhaul, but basically kind of tweaks from a standpoint of reemphasizing different things, looking for different plays, higher impact plays where there was more running room for the company if we were successful. So a company our size needed to have a higher percentage exposure to those kind of plays versus drilling a lot to put it in baseball terms, singles as opposed to what I'm referring to there is basically the kind of closed in low risk exploration drilling around some of our existing assets. So, there was a little bit of a mindset change, a little bit of a different allocation of where the capital was going. And then, as far as winter, we are starting to see some results. I think we are already starting to see some very encouraging results, and I would point to the Poseidon discovery and also the Tiber discovery in the Gulf of Mexico, as well as the Shenandoah discovery that I referred to.

I think with respect to Sig's comment and I would add a further point, not only do we feel we have the people with the processes, but we are really looking out, we are getting some interesting access to acreage. For instance, shale plays in Poland, Coal Bed Methane in China. The other thing, we would say is it is not necessarily increasing our spending in exploration, as we maintain our spending in exploration compared to 2008. So, even though, we are constraining and cutting back our capital spending, we are going to continue our exploration effort at the same level essentially as what we did in 2009. So, it is not increasing, but it is not cutting.

A fair point. Maybe just as a follow-up, I believe this you referenced the Eagle Ford Shale in the press release today. Would you be able to talk about any progress you have made it on a joint venture for that acreage, whether you would be willing to give up operatorship on that acreage, and maybe either how many wells you have drilled, or how many rigs you are running in the play?

Sure. I'd be happy to. I referred to some successful results that we've had recently on our well, our last well, the Brodsky A7 well. We had online for relatively short period of time but we are very encouraged it's got a flow rate of nearly four million cubic feet a day, but more importantly around 1500 barrels a day of compensate. So that has been part of our strategy to focus on plays that have a very high these shale plays that have a very high liquid content, obviously very important on the economics. We have a very substantial position there, close to 300,000 acres when you consider our interest in the Eagle Ford and the adjoining Austin Chalk play. You are correct. We have been entertaining some offers for potential farm out of our position, but we are not going to farm it out unless we see a compelling value proposition. So far we have not seen that so.

Great. Any comments on how many rigs you might be running there?

Right now, we are just running one rig. And as we get into next year, because we're still in the learning mode, we haven't drilled that many wells in the play. But every well that we drill like other shales, we are learning as we go, and we will ramp up in due course.

Your next question comes from the line of Arjun Murti. Please proceed with your questions.

Jim, can you provide any quick update on Iraq? I think various pressure points have at times had you winning and then maybe not winning West Qurna. Where do things stand for you all in Iraq right now?

Well, it is probably not going to be all that satisfactory response to you, because what I'm going to do is essentially say that we are just not going to comment or speculate on ongoing discussions or negotiations taking place with respect to Iraq on West Qurna. As a company, we think we certainly would like to be in Iraq. We have interests in the second round of looking at the opportunities in the second round as well as, although, there is not a third round, what ultimately will come after the second round. But as it relates to the issue of West Qurna-1, we are just not going to comment or speculate at this point in time.

Your next question comes from the line of Mark Gilman. Please proceed with your question.

A couple of things if I could, please. Jim, how are you defining the bottom 10% of the U.S. Canadian gas production base? Is that production, is it reserves, is it some other metric?

I think it is existing production in terms of what the high cost, what kind of cash flow and income we get from it, and does it have any really potential upside in our opinion. That is what we are really talking about. It is the old 80/20 rule. You know, 80% of what we is really good for us, it really drives the results, come from 20% of the positions, and so we just look at that bottom 10%. We think, we can sell a couple of billion dollars worth of value, and it probably will have more value to someone else from their view than it does to us.

And just somewhat similarly, in terms of the Southern Basin U.K. gas acreage and opportunities, put a number on that in terms of scale.

No, I would rather not do that, but we just look at it. We have been there for a very long period of time, one of the pioneers in the whole area. It's just pretty mature. Its going to take a fair degree of capital spend going forward and maintenance, and there are other people who we think that can do that have more interest in doing that than we do.

With respect to the Eagle Ford position that was the subject of a couple of prior questions, how much of that acreage position is held by production as opposed to acquired specifically for Eagle Ford potential?

Mark, the majority of that acreage is term leasehold, and we have the option of maintaining it through drilling, lease extension or renewals. So

So, let say they got outlined over the last several months or actually over the last year or two to develop quite a position. And it started with Burlington. They got into this position, and we have continued to access and get more acreage at a pretty low price over the last several years before it has really developed into promise. We have money in our exploration program that we can clearly ramp up, what we see as the opportunities in Eagle Ford, and we have also been doing a lot of seismic work and technology work. And so, all we are really sharing with you is to some extent a change in direction. It just looks a lot more promising to us. And so before we part with acreage, we are going to make sure that we really know and have what we have. And, as Sig said, if we part with some acreage, it's going to be lot better terms than we thought even recently.

So, can I assume that the lion's share of it is held by prior production as opposed to having been recently acquired specifically for Eagle Ford potential?

No, I think, Mark, as I said earlier, the majority of that acreage is term leasehold. So, there are some explorations on it, and that is one of the things that we have to consider as we plan for the next couple of years.

Yes, we are going to have to ramp up our drilling.

Is there any broader partnership in place with BP regarding participation of a Lower Tertiary in terms of exploratory licenses, or is Tiber more of a one-off?

Right now it's just a one-off.

Okay. One final one for me if I could. Interest expense ramped up very significantly pre-tax in the quarter. Is this at all associated with the indicated redemption of the Ashford Energy interest?

No, interest expense I think if you are comparing quarter-to-quarter from a year ago, it just reflects a higher level of debt that we are carrying –

I'm comparing against prior quarters this year.

Well, we have refunded out some long-term debt versus commercial paper that might be part of it.

That probably is.

Okay, guys. Thanks very much.

Yes, we can come back to you on that interest question. We will follow-up on that one.

Your next question comes from the line of Paul Cheng. Please proceed with your questions.

Jim, you are talking about assessed return I know you are not going to comment specifically on Iraq, but can you tell us for a resource basin like that, what kind of minimum return you will need in order for you to say, yes, it is a good project for me to go into?

In Iraq?

Yes.

Well, I think you have got to be looking well in excess of mid-teens towards the 20 levels.

And you also have said that refinery that is another good market out there that you sell, and some of the independent refiners like [Funaro] and Sunoco have been looking at shutting down their facility on a permanent basis. Have you done any strategic review on your portfolio and identified perhaps that some of your facilities may need to go through a more aggressive strategic review?

Well, I did say we are going through a more strategic assessment because there are some that are less sophisticated that we think long-term when the market gets a little bit better for selling some refineries we think that is going to be subsequent to the next two years for 2012, 2013. We have in mind a number of facilities that we think might have some value to someone else. But we think the time to do that is not now. So, we have done and continue to do quite a strategic assessment. Now, in the day's market some of the less sophisticated refineries will make adjustments to production to respond to the market. So, we need to really recover our variable costs or we start cutting back production.

So, in other words, I guess my question is that do you have any plan to permanently shut, not to sell but to shut-down any of your refinery? I guess that is my question.

Well, we don't see it at this point in time because we look at the marketplace and we also look at our cost structure, and so we don't have plans to shut anything down at this point in time. Permanently shut down anything. We have gone through some pretty extended turnarounds and all, but we do that because of the marketplace it is a good time to do it.

And a final question. Maybe this is for Sig. Sig, versus the second quarter, your upstream unit cost has gone up?

Well, I think you might be looking at the DD&A and taxes other than income and when you look at the total cost. Because controllable costs are certainly, controllable costs as we look at them are down. But we can come back with you on some specifics there. Let us follow-up on that one.

That would be great because when we're looking at that, your oil and gas price realization sequentially may be up about somewhere in the $6 or so, $5 to $6. But your unit profitability looks like only about $1.00 per BOE. So, I mean, your tax is not 70% or 80%. So, I mean, there seems like that there is something we are missing here.

It could be foreign exchange. It could be the DD&A. Let us do some work and come back to you Paul.

Your next question comes from the line of Evan Calio. Please proceed with your question.

Hi guys, thanks for taking my call. Many questions have been addressed in the Q&A and the comments, but maybe a broader question for Jim and a follow-up on your other industry comments. In your broader strategic assessment here to drive shareholder value, could you share with us your thoughts on regarding the value of integration of the upstream and the downstream business? And maybe excluding Borger and Wood River, share any of your thoughts on any broader asset separation if it could be conducted in a tax efficient manner? Thanks.

Well, when you say integrated operations, we certainly have a very strong joint venture that we are pleased with EnCana (inaudible). We believe we are in the strongest SAGD projects with our (inaudible) at Foster Creek and Christina Lake. And then we tie in Wood River and the Borger refinery. In terms of the opportunities of doing that kind of transaction with other people, it seems there is nothing immediately that comes to mind. But, on the other hand there could be some interest by sovereigns or national oil companies that would like to have positions and access to markets. So I think it's a little bit different than the EnCana transaction. But no, I don't think we see, necessarily that we linked E&P with the downstream in terms of integration. Historically, there is one period of time one might do another. It takes volatility out of earnings, but I don't think the argument of the need for integration is as strong as it was decades ago. Which is why we are really moving toward the strategy and portfolio that's ultimately 80% E&P and lessening back down over a number of years by investment, ultimately some dispositions of refining capacity towards 15% to 20% downstream. So, our answer is we don't see that it's linked anymore.

Your next question comes from the line of Blake Fernandez. Please proceed with your question.

Two quick ones for you if I may. The first I was trying to see if we could get an update on the detail and timing of the growth opportunities in the Christina Lake development? And then secondly, I guess this kind of ties in with Mark's previous question on the Lower Tertiary. But just given your new emphasis on higher impact type of wells and your recent success with Tiber, is it fair to assume that, that will be an area of focus or potential expansion going forward?

Yeah the oil sands in general in Canada we are very pleased with and we basically see a progression ramp-up over the next several years, including Foster Creek, Christina Lake and now Surmont. And then we follow-on opportunities outside of those projects, namely Thornbury, Clyden and Saleski. So we have a very long runway here for oil sands projects. These projects are sanctioned kind of project-by-project. Each individual project kind of rule of thumb is about 30,000 barrels of oil per day, once it reaches full production. The ramp takes several years to ramp-up to productions. For instance, we will probably sanction the Surmont project, as I mentioned in my prepared remarks, sometime this quarter. That will reach full production about 2012. So, it just takes that long to kind of ramp-up. But then we'll produce essentially flat for the next 30 or 40 years. So, as it relates to Foster Creek, Christina Lake, we produced net out of there around 43,000 BOEs in the third quarter. That's going to go up probably close to 50 in the fourth quarter. And then by 2011, that will be in the 55,000 to 60,000 net range. So, that should give you some feel for the oil sands development opportunities that we have in place. And your other question was about exploration?

Yeah, on the Lower Tertiary. Just, as you mentioned given the focus toward more high impact type of wells and your initial success out in the Lower Tertiary, just did not know if that would be an area where you might consider expanding.

Yes, it is. We continue to be active in the lease sales and look to do additional farm-in opportunities. But we also have some existing positions that we are looking to bring partners in with us so.

This concludes the question-and-answer session of today's conference call. I will now turn the presentation back over to Mr. Clayton Reasor for any closing remarks.

Okay. I would just like to thank everybody for their participation in today's call. You'll find a recording of the presentation and slides on our website. I do appreciate your listening in and your interest in the company. Thank you very much.

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