ConocoPhillips (COP) Q3 2010 Earnings Report, Transcript and Summary

Good day, ladies and gentlemen, and welcome to the ConocoPhillips Third Quarter 2010 Earnings Conference Call. My name is Jen, and I will be your coordinator for today. [Operator Instructions] I would now like to turn the presentation over to Mr. Clayton Reasor, Vice President, Corporate and Investor Relations. Please proceed, sir.

Thank you. And thanks everybody, on the line for your interest in ConocoPhillips in our third quarter conference call. I'm joined today by Jim Mulva, our Chairman and CEO. And this morning we'll be discussing third quarter results and also provide an update on the status of our strategic initiatives. A summary of our key financial and operating results for the quarter will be provided, as well as our outlook for the remainder of 2010. And as in the past, you'll find our presentation materials on the IR section of the ConocoPhillips website. Before we get started, I'd like you to look at the Safe Harbor statement on Slide 2. It's a reminder that we'll be making forward-looking statements during the presentation and Q&A. Actual results may differ materially from what's presented today, and factors that could cause actual results to differ are included in our filings with the SEC. Moving to Slide 3, a summary of our key third quarter results and highlights. You can see that earnings for the third quarter, adjusted for special items, were $2.2 billion or $1.50 per share, up 56% from this quarter a year ago. Cash from operations was $4.3 billion. Cash returns on capital employed was 20%. Upstream production, excluding LUKOIL, was 1.72 million BOE per day. Our refineries ran at relatively high-capacity utilization. R&M's adjusted earnings topped $1 billion through the first nine months of the year. We completed $6.3 billion of dispositions, including $6 billion of LUKOIL share sales. Debt was reduced by $2.7 billion during the quarter, and we ended with an $8 billion cash balance. So turning to Slide 4. Total company adjusted earnings were $2.2 billion, up over $800 million compared to the third quarter of last year. Both E&P and R&M improved earnings year-over-year. Our E&P segment improved $559 million, primarily due to higher commodity prices, partially offset by lower volumes. Compared to the third quarter of last year, R&M adjusted earnings increased $174 million, mainly due to improved U.S. refining margins. The $149 million improvement in other reflects a reduction in corporate costs, as well as earnings improvements in our Midstream and Chemicals ventures. September 2010 year-to-date adjusted controllable costs were approximately $400 million lower compared with the same period in 2009. The improvement is evenly split between E&P and R&M segments. Total controllable costs, unadjusted for market factors and asset sales for the first nine months of 2010, were $9.6 billion compared to $9.4 billion during the same period in 2009. Moving to Slide 5, cash flow sources and uses. You can see that we generated $10.6 billion in cash during the quarter. $4.3 billion came from operations, and $6.3 billion in cash proceeds and dispositions, primary the LUKOIL stock sales. We repaid $2.7 billion of debt, funded $2.5 billion in capital, repurchased almost $900 million of ConocoPhillips common stock and paid over $800 million in dividends. At the end of the quarter, we had a cash balance of close to $8 billion, the majority of which we expect to use to repurchase ConocoPhillips shares. Now let's review our Upstream production on Slide 6. Third quarter production was 1.72 million BOE per day, down 4% or 74,000 BOE per day from the third quarter of last year. You can see from the chart that 14,000 per day of the reduction was due to market factors, including PSC impacts due to higher prices and royalty impacts at Foster Creek and Christina Lake. FCCL production continues to grow, however, higher royalty take caused a negative impact on reported production. Late in the quarter, we initiated production curtailments of approximately 180 Mcf equivalent or 30,000 BOE a day in response to continuing low gas prices in Western Canada and parts of the U.S. 27,000 barrels a day of production was lost due to asset sales of Syncrude and Lower 48 production. Maintenance activity was about the same as last year. The decrease in operations is mainly due to normal fuel decline, offset by new production. The majority of our decline came from North America, with almost 90,000 BOE per day and in the North sea, which had almost 40,000 BOE per day of lower production. Almost 75,000 barrels a day of new production from China, our SAGD operations in Canada, Australia and other locations partially offset this decline. Unplanned downtime was about the same as last year. And we'll talk more about the 2010 and 2011 production expectations later during the outlook portion of today's conference call. Turning to Slide 7. You can E&P's adjusted earnings for the quarter were $1.5 billion, up almost 60% from the same quarter a year ago. Higher prices and other market impacts contributed more than $600 million of the increase in earnings. The earnings improvement was partially offset by $207 million decrease from lower sales volumes, primarily coming from normal fuel decline. The positive $149 million in other is largely comprised of lower dry hole costs and DD&A, partially offset by increased impairments and lower contributions from equity companies in Russia and Canada. Year-to-date 2010, E&P adjusted controllable costs improved by about $200 million compared with the first nine months of 2009. And looking at the table at the bottom of the slide, you can see that both the U.S. and international adjusted earnings improved significantly compared to last year. Let's go to Slide 8, E&P unit metrics. You can see that our metrics were significantly better than a year ago, reflecting the improvement in realized oil and gas prices. Third quarter E&P income increased $3.78 per BOE or 66% compared to the third quarter of 2009. Compared to the second quarter of this year, income and cash per BOE were slightly better, in spite of realized oil prices being down about 2%, and this is due to LNG, bitumen and U.S. natural gas prices all sequentially improving. As our OECD-focused portfolio shifts more towards oil sands, LNG, lower freight [ph] liquids production, we expect to see additional improvements in our income and cash flow per BOE metrics over time. Turning to R&M on Slide 9. You can see that Refining and Marketing adjusted earnings improved 185% over the same quarter last year. Downstream market conditions were stronger as global crack spreads improved 15%, and helped increase earnings by about $100 million. However, this quarter's earnings were negatively impacted by about $75 million due to inventory impacts and how we valued inventory. And we expect to recover this loss in the fourth quarter. Year-over-year, we saw, a decrease in R&M earnings of $18 million from lower volumes, which were primarily driven by the sale of Conoco Flying J Truck Stops. Our U.S. refining capacity utilization was slightly lower compared to the same period last year, and our international refining capacity rate was 60% during the quarter compared to 81% for the same period last year. This decrease in international reflects the shutdown of the Wilhelmshaven refinery. Excluding the impact of Wilhelmshaven, R&M ran at 93% of capacity and clean product yield improved almost 83%. Compared to the third quarter of last year, operating costs increased $22 million due to higher utilities and turnaround costs, which were partially offset by foreign exchange and asset sale benefits. However, through the end of the third quarter, controllable costs adjusted for market factors and asset sales were down around $200 million compared to the first nine months of last year. Lower effective tax rates and foreign exchange benefits made up the majority included in the $114 million bar, labeled other. Sequentially, our Downstream business was negatively impacted by lower earnings of more than $50 million from our Premium Coke and Chemical Feedstock business, and $70 million from lower contributions from marketing. Now let's move to Slide 10, which shows year-over-year variances for other segments. Adjusted corporate expenses were $162 million for the quarter compared to $286 million a year ago. These results exclude a $114 million Mako premium for early debt retirement. The $124 million sequential decline in corporate is primarily due to lower interest expense and higher foreign exchange gains. Foreign exchange gains were driven by U.S. dollar weakening against the Canadian dollar and British pound. Results in our DCP Midstream segment were $15 million higher this quarter compared to a year ago, mostly due to higher NGL prices. Sequentially, NGL prices were down $1.45 a barrel, but it recovered as a percentage of crude oil. Our 50% stake of CPChem generated $132 million. This represents almost $30 million more than the third quarter of last year, and was due to higher ethylene and polyethylene prices and margins. These higher margins were partially offset by higher utility and turnaround costs. During the quarter, ConocoPhillips received a $220 million distribution from CPChem. The LUKOIL segment generated $436 million in adjusted earnings for the quarter, and it's based on LUKOIL's second quarter reported earnings. We will discontinue equity accounting of the LUKOIL segment at the end of the third quarter and no longer report LUKOIL reported proved reserves or production. Turning to Slide 11, which provides more detail on the impact of the LUKOIL share sales. You can see that the chart shows undiscounted cash increase generated by our investment in LUKOIL stock. The green bars represent proceeds coming from dividends and the sale of stock. The first two provide the amount of after-tax proceeds from the dividends and shares sold through the end of the third quarter. The third bar estimates the amount of after-tax proceeds we would generate if the sale of the remaining shares was done at the closing price on October 21, 2010. Together, these proceeds total about $10 billion. The original acquisition cost of $170 million or 20% of LUKOIL shares amounted to $7.5 billion, leaving a cash increase of about $2.5 billion. As mentioned, we'll discontinue the use of equity accounting for the LUKOIL segment after this quarter and report earlier realized gains on future share sales as we reduce our ownership interest, which was 4.6% and 39.2 million shares as of yesterday. Looking at the impact of this decision on earnings per share and cash flow basis, if we assume an estimated proceeds of a $9 billion from our sale of the entire interest in LUKOIL were use to repurchase ConocoPhillips stock at $60 a share and we assume no equity earnings for LUKOIL were recorded , we estimate the net reduction on adjusted EPS to be about $0.16 per share this quarter or about 10%. Looking back over the last three years, a reduction in adjusted EPS would also have been about 10% on average. On a cash flow basis, the decision to sell LUKOIL and buy ConocoPhillips stock is accretive. This is due to the difference in dividend yield, as dividends received from LUKOIL, which were the only source of cash flow from the segment, we're less than the ConocoPhillips dividend saved from those shares purchased. Looking more narrowly at cash from operations on a per-share basis, on the average over the last three years, cash flow per share would have been about 10% higher. Moving to Slide 12, our capital structure. These graphs provide the last several quarters and two years history of equity and debt levels. During the first nine months of 2010, we reduced debt by more than $5 billion, bringing our debt level below $24 billion. We ended the quarter with a cash balance of about $8 billion due largely to the sale of LUKOIL shares combined with the cash we had on hand at the end of the second quarter. And considering this cash position, our growth in equity net the cap rate would be around 18%. Majority of current cash position is expected to be used for the repurchase of ConocoPhillips stock. And while our debt-to-cap level is above our target of 20%, we don't plan to significantly reduce debt further over the next year or two. Let's move to Slide 13, which provides some history on distributions to shareholders. Since the formation of ConocoPhillips in 2002, we've grown dividends per share by 13.5% per year through the eight consecutive years of annual dividend increases. In addition to those dividend payments, we purchased $16.1 billion of stock during 2006 to 2008 time frame, and expect to purchase another $10 billion of ConocoPhillips stock in 2010 and 2011. These share repurchases have been divided by the fully diluted share count and are shown on the graph above on a per-share basis as the blue bars. Share repurchases have ramped up over the last couple of months. And through October 26, we've repurchased about 37 million shares at a cost of $2.2 billion. The average fully diluted share count during the third quarter was 1.493 billion. We believe this increase in shareholder distribution is an approach that differentiates us from most of our peers. We expect that the share repurchase will allow us to improve returns on capital while growing production on a per-share basis. Moving to Slide 14, which provides capital efficiency metrics. Our ROCE and cash returns have improved during the year, driven by earnings and cash flow growth while constraining capital employed expansion. Compared to this quarter last year, returns are higher. However, third quarter results were sequentially lower. And this decline was due to primarily to the third quarter adjusted earnings being about 10% lower than the second quarter, as well as some expansion in capital employed. We ended the third quarter with about $93.5 billion of capital employed, of which $24 billion is in R&M and $57 billion was in E&P. 2009 average capital employed was $87.5 billion. The $6 billion increase in third quarter capital employed came from currency translation effects and growth in retained earnings. The increase is partially offset by debt reduction and share repurchase. If we had repurchased about another $1.5 billion of additional shares, our ROCE for the quarter would have been closer to 11%. As execution of our capital allocation plans shift our spending toward E&P and our asset dispositions result in better margins per BOE, we expect to see our returns on capital employed expand further. That completes the review of the third quarter 2010 results. I'll wrap up with some forward-looking comments before asking Jim to make a few remarks and then open the line for questions. Consistent with the previous full year 2010 production guidance, we expect production to be flat with 2008 or about $1.8 million BOE per day, before dispositions and market factors. We anticipate fourth quarter E&P production to be close to that what it was in the third quarter. And during the fourth quarter, the production impact from asset dispositions will be between 40,000 and 50,000 barrels per day, natural gas production curtailment of 20,000 to 30,000 BOE per day, while price and PSC effects are expected to reduce production by 10,000 to 20,000 BOE per day. We expect 2011 production to be 2% lower than 2010 before considering the impact of 2011 E&P dispositions, so around 1.7 million BOE per day. We'll give you more information about our 2011 production targets, sources of production growth and regional plans early next year. In our R&M business, we expect fourth quarter turnaround activity to increase significantly, with pretax expenses to be around $200 million and total pretax expense for the year of around $450 million. Fourth quarter utilization rates should be almost 80%, and capacity utilization in the U.S. would be around 85%. And the international utilization rate is expected to be in the low 60% range, which includes the impact of Wilhelmshaven. Regarding controllable costs, we are on track to deliver our cost reduction targets of about $350 million from E&P and $200 million from refining and marketing. For full year 2010, we expect unadjusted corporate expense to be approximately $1.3 billion. Our capital program for 2010 is expected to be between $10 billion and $11 billion, down from earlier guidance and from 2009 levels. This is due to permitting delays and slow pace of development, primarily in Asia-Pacific, North Sea and North America. 2011 capital program is expected to increase to around $13 billion, with the ramp-up of Lower 48 shale activity and the APLNG project being key drivers of the increase over 2010 spending levels. We'll provide you with more information on our 2011 capital program in December and give you more detail at our March 23 Analyst Meeting in New York. Moving to exploration. We expect 2010 exploration expense of $1.1 billion to $1.2 billion. We completed Wildcat in the North Sea, which was determined to be a dry hole. Our 30% interest in the well resulted in a $6 million after-tax charge. In the Caspian, the Rak More well spud in the third quarter, and we may be able to provide some well results on our January earnings conference call. In the Arafura Sea, we expect to spud our first well in the fourth quarter and the second well in 2011. We have 51% interest in those wells. Additionally, the 20% owned Dalsnuten Wildcat that spud in the third quarter, we expect it to TD late in 2010. And we will begin the next appraisal phase on Poseidon Offshore Browse basin in Australia during the first half of 2011. Several development options are being discussed, and the final determination regarding development is dependent upon the upcoming appraisal wells. We continue to increase the pace of drilling activity in the liquid-rich shale plays at the Eagle Ford, Bakken, North Barnett and Cardium. At Eagle Ford, we had eight rigs drilling at the end of the quarter, nine are drilling currently, and 11 are expected by the end of October. Additionally, we have secured two dedicated frac cruise for 2010, and expect to increase that number to three early next year. We've drilled a total of 33 wells in the Eagle Ford shale, completed 20, and are seeing production of roughly 8,000 BOE per day from the 14 wells that we brought online to date. In the liquids-rich Cardium area at Western Canada, we'll be drilling nine operated wells and participating in six non-operated wells during the fourth quarter. These wells are almost all oil-producing with some associated gas. Also in Canada, we continue to see good return and production growth opportunities in our SAGD areas: Foster Creek, Christina Lake and Surmont. We expect production of around 60,000 BOE per day this year from these projects, with a compound annual growth rate over the next five years estimated between 10% and 15%. In Australia, APLNG is engaged with several potential LNG buyers in support of moving to FID, but we're not in a position to discuss information regarding specific market discussion at this time. However, we plan to have an announcement regarding the sale of two trains of LNG before year end. Our plans to sell $10 billion in assets by the end of 2011 are on track. And so far this year, we've closed transactions with proceeds of $5.6 billion and expect proceeds of roughly $7 billion by year end. We may sell more than $10 billion in assets during 2010 and 2011. The assets being sold in 2010 have a production of approximately 55,000 BOE per day. Most of the Lower 48 and Western Canadian E&P assets will be closed in the fourth quarter and will generate about $1.5 billion in proceeds. We expect the 2010 full year average production impact of asset dispositions to be roughly 20,000 BOE per day, with a reduction of reserves of about 310 million BOE. Assets which may be sold as part of the 2011 program include our Wilhelmshaven refinery, additional Lower 48 and Western Canada E&P assets and other international assets in both Upstream and Downstream businesses. The REX pipeline is outside the 2011 scope. As we did this year, we intend to provide you with production, reserve and earnings impacts resulting from our asset sales program during the first quarter of 2011. Our guidance of spending $10 billion on share repurchase over 10,000 on '10 and 10,000 in '11 remains unchanged. Our current Board of Directors authorization is for $5 billion. So that concludes my prepared remarks. I'd like to turn it over now to Jim Mulva for his comments before we open the call for questions. Jim?

Okay, Clayton, thank you. I think you covered most of the points, so just maybe confirm a few points. First, from an operating point of view, we've operated quite well all of this year and through the third quarter. We're doing really quite well on not only the operations but the cost constraint. We're maintaining our facilities certainly, but we're doing well in cost constraint, and as a result of good commitment by our employees and the help of our contractors. In terms of the portfolio restructuring, we're right on track, no change in strategy, quite covered the asset dispositions. I think there to see opportunity as we go through 2011. And we'll update you what time. We could be doing more than somewhat more than $10 billion of asset sales. We're on track on the restructuring where we want to move E&P up towards more as a portion of our portfolio and refining and marketing from 25% with time closer to 15%. Capital guidance, we're probably going to spend closer to $10 billion this year, with expectations of capital spending closer to or above $13 billion this next year. Clayton indicated LUKOIL dispositions, we still have about 4.6% ownership. At LUKOIL share prices we are currently experiencing, we continue to sell our shares. So I think if these market levels continue, you'll see us dispose of all of our interest in LUKOIL far more quickly than when the guidance of which would be the end of 2011. We continue to buy ConocoPhillips shares in the marketplace. And as the slide indicates, guidance shows that we would spend may be closer to about $4 billion in 2010 for purchase of ConocoPhillips shares, with about $6 billion this next year. The board has approved $5 billion program, but we've indicated the proceeds from the LUKOIL disposition would go essentially towards share repurchase. In terms of debt reduction, our debt is in the neighborhood of $23.5 billion. We don't have any required maturities left this year. The debt is quite efficient. In this next year, we have some required maturities which might be in the neighborhood of about $0.5 billion to $1 billion. We'll certainly retire those. But we have no real compelling economic reason to accelerate and buy more of our debt. So we're quite satisfied with the debt. It will come down over the next several years with required maturities, but still, longer term, I think we question going much below $20 billion in debt because we have a strong balance sheet across is quite acceptable. In terms of the utilization of our free cash flow, as I just said, we don't feel any compelling reason to bring the debt down more quickly than where it is right now other than required maturities. We feel we have the cash flow to support the capital program that we've outlined. We like the discipline of increasing our dividends. Of course, it's subject to board approval. But in the past several years, we've been raising our dividends early in each of the years. And then that we'll probably operate with a cash balance of about $2 billion for opportunities and liquidity purposes. So to the extent that we sell more assets and that we have good cash flow, after we fund capital program and dividends, it would be available for additional share repurchase. So I think Clayton that covers what I'd like to do. I think we should open it up for questions now.

Jen, if you'd like to line up some questions for us, we'd be happy to take them.

[Operator Instructions] Our first question comes from Doug Leggate with Bank of America.

Jim, one of the things that you've talked about, I guess, more recently than anything else is the issue of remaining as a fully integrated company. I wonder in light of what's going on in refining right now and the refocus of capital towards the Upstream, if you could just bring us up-to-date as to your latest thoughts on the potential of maybe being a little bit more aggressive and perhaps separating the company sometime down the line?

Okay. So the question is on the refining side of the business and the aggressiveness to reduce our exposure restructuring wise. Well, I just would say that it's certainly, it's a confidential area when we're working and talking with others with respect to either shut down our facility or doing venture in a facility, selling a facility or taking, looking at a region by which we take our refineries in the region and how we can partner them up with someone else or who should have an economic interest. We did indicate about a year ago that we felt that the environment for transactions and restructuring would be more amenable to be in the 2012 time period. But I think you make a good point that we're starting to see that there is maybe a little more interest and opportunities for restructuring more quickly than waiting until 2012 and 2013. So we are working pretty hard. We want to make sure that whatever we do, we're doing it in a way that's not really destroying value for the shareholder. But you make a good point, and we're pretty aggressive and we're really focused on how we can accelerate this a little more quickly than what the guidance we've given in the past.

My follow-up is completely unrelated. It's really the progress in Poland. This is obviously an area that the industry is watching very closely. And I'm just wondering if there was any additional color that you can give on the results you've had there to date and what your future plans might be?

Well, we are the first ones drilling several wells, and we're doing a lot of tech -- we're using a lot of technology and evaluation of the wells. And we kept this rather confidential. And I think it's going to take us a little bit longer before we determine just what the results are from those wells. But I think that's something you're going to hear from us over the next several months or so.

Your next question comes from Jason Gammel with Macquarie.

Jim, I was hoping that you could make some comments on the management changes that were announced over the course of the quarter, how you feel about this new team that you now have in place, and what that potentially means for your remaining tenure as CEO?

Well, first of all, with respect to the management changes, the overriding objective is to put in place a real robust succession process that really looks out on any ambiguity both internal and external of the company. Here is the new team that will emerge, provide the leadership in the company over the next five- and 10-year period of time. The changes for executives that are retiring has nothing to do with health or performance issues. The objective is very clear and very simple: to put in place the future management team. And out of that group of individuals will come my replacement and this will be down over the next couple of years, and then that table continue on. I'm 64 1/2 years old, so we don't have a mandatory retirement age. But you can expect from this group will come my replacement just over the next several years. We want to make sure that putting this group together that have a lot of operating expertise. We wanted also to bring, develop our own senior management within the company, but we wanted to augment it with others from the outside with experience both Upstream and Downstream. That can give us also fresh set of eyes to help us with respect to as we restructure and execute, implement the portfolio changes, become a more Upstream and less Downstream. So without any ambiguity, that's essentially what we're doing. It's in place. It's been worked actually with our Board of Directors over this last one or two year time period. We're quite pleased with the team we've put in place. And I think you'll see -- you'll get the opportunity to see all of them in presentations together in March. But we'll make sure that the financial community get to see them in presentations individually as we go through the year.

And maybe one more if I could, Jim. A couple of the coalbed methane to LNG projects in Queensland were granted environmental approval by the Australian Federal Government just over the last week or two. I was wondering if you could give us an idea on when you plan to submit your own EIS and what that means for the overall track to final investment decision?

Actually, last year 18 months, we've really caught up with everyone else. We've made our submissions and all, and we would expect similar approvals here within the next month. So we essentially are working at FID in about the same time, point in time.

Your next question comes from Ed Westlake with Credit Suisse. Edward Westlake - Crédit Suisse AG: Just on APLNG. Obviously, there is this ground water contamination investigation origin. They've said it's a bit of a storm in a teacup. But in terms of is that impacting your discussions with potential buyers in terms of potentially having delay? And then just on the APLNG CapEx, how much of the $13 billion next year, how much is APLNG included in that total?

Clayton can answer the second one. With respect to the information on some of the wells, it's really not having an impact with respect to discussions with potential buyers of LNG from this project. Certainly, most concerned to ourselves, we address this. We think we're going to be able to handle this, but it's not having an adverse impact with respect to potential buyers. In terms of our capital spend, I guess, Clayton, you could...

Yes. It's between $1 billion and $1.5 billion of additional capital in APLNG over what we spent this year. Edward Westlake - Crédit Suisse AG: And then on the outlook for European refining sales, I mean, obviously, the Humber refinery complex has got a lot of scale. If you were to sell it presumably, you should be looking for a reasonably good price, not a fire sale on that?

Well, we're not looking to do a fire sale on anything. Humber is really a complex great refinery, so it's one that we really look at. It really fits our portfolio for the long term. But then on the other hand, you never know, it's possible that for the right price and/or the opportunity for joint venture, these are things that we have to consider when we look at restructuring our portfolio from 25% or 26% down towards 15%. Wilhelmshaven, we'll really not going to continue it as a refinery. We will look at selling it if someone wants to take it or converting it into a terminal. Our equity interest in other refineries, these are good equity interest, but they are relatively small, and so you have to ask yourself, "Do we have the opportunity to monetize them." So the real legacy asset here that we have with respect to refining is this Humber refinery.

Your next question comes from Robert Kessler with Simmons & Company. Robert Kessler - Simmons & Company: I was wondering if you could quantify the incremental CapEx headed to the Eagle Ford in 2011 versus 2010?

So I think the 2010 Eagle Ford spend is somewhere around $300 million, and 2011 Eagle Ford spend -- of course, these capital programs haven't been approved yet, but it's between $1 billion and $1.5 billion a year. Robert Kessler - Simmons & Company: And is that all organic so to speak or is there any incremental acreage acquisition embedded in that?

That's all drilling and completion, and there's so additional acreage in that number.

Your next question comes from Paul Sankey with Deutsche Bank.

Going back to the cash, use of cash sums, if I look at on numbers, we're about $18 billion of cash flow from operations next year. You said there's a higher $13 billion CapEx, giving me $5 billion to spare. I've then got around $4 billion of disposals, giving me $9 billion. And you've got $8 billion in cash, approximately equating to $17 billion spare. But your guidance is only for $6 billion of buyback next year. This is what you're saying in terms of planning opportunities related to the potential for bigger acquisitions. I think that you've guided towards $2 billion potentially to be spent in the Gulf of Mexico. Is there a risk here that we get back on the acquisition path to regenerate the organic opportunities there or are you really lowballing this buyback number?

Well, Paul, you make a good point. The numbers are consensus views of cash availability for the company going forward. And so I think you make the following, if we spent $13 billion for capital, there's no more required for debt reduction, maybe required repayments of $1 billion next year. But like we've indicated, we'd like to increase the dividends 5% to 10% a year. We're not looking at acquisitions other than the opportunities we might have in the Gulf of Mexico, in Lower 48, where which we can farm in or get a handle on an asset. We potentially could spend $2 billion or $3 billion doing that. So what's left then as we have a lot of cash that's available not for making a large acquisition, that's available for additional share repurchase above the $10 billion number. It's not that we're trying to signal in any way that it's available to make a significant acquisition. No, we're not changing our strategy, it's more available for distributions to the shareholders.

And on the kind of financial theory level, the stock x the LUKOIL earnings is looking obviously more expensive than it did when the planned strategy was outlined, where you were, I think, under $50 a share. Can you just talk about how you view the investment at these relatively elevated multiples as opposed to the other opportunities you would have in terms of other reinvestment opportunities and why you feel that buyback is the most appropriate way forward?

Well, we look at the valuation of our shares and certainly, we have improved the share price over this past year. And with the announcement of the strategy of what we've been doing with the company this past year, we'll continue going forward in 2011 and subsequent time periods. Management is never happy with the share price being what it is today. But if we look at what we're trying to do is it really increases and normalized earnings and cash flow per share given our asset base and our opportunities. We feel that we can, over the next number of years, be spending $13 billion, $14 billion a year, and we can convert our resources and replace our reserves, and then ultimately in the 2014, 2015 time period, drew our absolute level of production. We can do that on $13 billion, $14 billion, $15 billion a year of capital and still raise our dividends, 5% to 10%. And so if you believe there will be a somewhat better oil price, which I think we believe with time there will be and are somewhat better natural gas price, not $3.50 per MCF, but maybe closer to $5 an MCF, then we think even at the levels of $60-plus distributions to our shareholders in the form of additional share repurchase gives us the best opportunity to be raising the share price on a normalized basis going forward with whatever assumptions you have for commodity prices. We do that by having fewer shares outstanding, more capital discipline and ultimately replacing our reserves and growing our production in absolute terms, but even more so on a per-metric, per-unit share. And so we feel that we continue to look at it, but we think there's an opportunity for quite a bit more share repurchase.

And I'm sure you'd be considering a special dividend within the various tools that you've got available to you, Jim?

Well, that's an alternative and an opportunity, but that's something for the company and for the board to determine. I think our priority would be primarily raising the normal dividend and share repurchase before special dividend.

The next question comes from Mark Gilman with Benchmark company.

Can you provide us with some individual well metrics on your Eagle Ford effort up to this point? And any trends in terms of well costs, reserves per well and IP rates?

I can't do that right now, Mark, but we can get that information. I mean, I think what we've said is these wells are generally around 1,500 BOE per day. Well costs are running in the $8 million to $9 million per well range. I don't know if we've given a ultimate reserve number on the field or by well, but we're really encouraged by what we've seen so far. I think there is some information that's out there publicly that I could share with you on our well results. We think we're in the just the right spot at Eagle Ford, and we're really encouraged by the results. But I can get more detail to you following this call.

Is that 1,500 a 30-day, 24 hour?

That's a 30-day average rate.

Jim, I'm hoping you might be able to clarify your decision a little bit regarding the REX pipeline and the decision not to offer it for sale currently. Does this reflects an expectation that you might get better value down the road or a change in sentiment? If it's the expectation of a better value down the road, help me understand the basis of the belief?

It's not a change in sentiment. It's not -- we didn't feel that the bids that we got were meeting our expectations of what we could get at a later date. And so we're not changing the direction, we're just saying we feel that we can come back at a later point in time and get at a price. So what we're really saying is we're not going to dispose of assets in a fire sale. We think this asset is worth more than which we got. So we're going to go back out, whether it could be late 2011, 2012. When we think the market is better prepared for this or more interest in it, that's when we will do it.

The trend in Bohai reduction has, I guess, surprised me a little bit that we're not seeing a bit of a larger ramp-up. Clayton, Jim, can you talk about that a little bit and when you would expect to see the plateau level reach from Phase 2?

Well, it's taking us longer. The well performance is more difficult, more challenging. It's not that it's unexpected, but it's taken us longer than we expected. I was just over in China, Beijing, about two weeks ago, and I think Clayton can confirm this, but I think we're getting up to 150,000 growth, 150,000 barrels a day, maybe a little bit more than 150,000 barrels a day. and As I recall, I think ultimately, we were trying to get up to 160,000, 170,000 barrels a day gross. Clayton, you can update those numbers.

Yes. I see what you're saying, Mark. Our net production out of Bohai is running at 55,000 a day right now. I think there are, as Jim said, the development of the productions has been slower than we expected. But overall production growth in Bohai has continued with the earlier guidance that we have given.

The next question comes from Doug Terreson with ISI.

Jim, you guys have seven to eight major E&P projects, which appear likely to lead to almost full reserve replacement through 2014 by themselves and you have pretty attractive economics too. And at the same time, the company has a new exploration program that's gearing up also. And so my question in regards to the conversion process on these reserves, meaning, what is your level of confidence that the team can execute such a large plan of commercial conversion for these reserves over that period of time? And on the exploration front, where are you most optimistic when you think about how the profile might be supported over the longer term?

Conversion of reserves, we really feel what we're doing in the oil sands in Canada, Surmont, Foster Creek, Christina Lake, we feel very good about that. And I'll ask Clayton, I'd like to share with you what our breakevens when I get done answering your question. But conversion of the oil sands is a pretty significant part of our conversion and reserve replacement over the next five years. We feel really good about that. And then the oil, we've really -- our portfolio, I don't think it's well understood in the marketplace. Our portfolio, what we have in Eagle Ford and the Bakken and the oil play of Barnett and other areas that we have, we're really getting more and more encouraged all the time that's why we're increasing our spend by about $1 billion or more in 2011. So we feel really good about that. Obviously, we got to deliver what we say we're got to do at APLNG, but we really feel that project is coming together, and that's pretty important, LNG projects in the future. And then we're having discovery success in Alaska, like Poseidon, but it's a little bit longer term. So LNG projects, what we are doing in the Lower 48, oil sands, and then we are going to go forward with the redevelopment of Ekofisk field and Eldfisk, we pretty certain about adding reserves there. So those are some of the big areas. Now on the exploration front, we've got Rock More, Moray well. And we've got more opportunities, more features to drill in the Caspian. We're looking for more acreage in Turkmenistan. We're looking for more acreage essentially in other place in the world. But we also think we're uniquely positioned as a company, exploration-wise and maybe at BD wise for larger companies and smaller companies in the deep water Gulf of Mexico. We don't know what the rules and regulations are going to be. We don't know for sure what the risk/reward is going to be. But that's why we said in prior responses to questions that we've reserved a couple of billion dollars that we feel that we could go into some discovered resources and participate as an opportunity for all of these reasons. We really believe pretty strongly, and we'll update everyone in the March Analyst Meeting of the conversion process, the reserve replacement and doing that competitively finding and development costs. We feel pretty good about this over the next five years, and we'll share that with everyone. Now Clayton, maybe would you in our March Meeting, but would you go through just, I think, the breakevens on what we have for Foster Creek, Christina Lake as well as Surmont, it gives you a better feel. We've got the resources here, but why we're committing the money and why we feel we can grow production 15% compounded over the next number of years for a long period of time.

Yes. I think most people believe that oil sands require significantly higher prices to generate 13% returns. Our cash breakeven at Foster Creek and Christina Lake for the third quarter were $15.08. And on a net income basis, it's $25.70. And that's representative of about where it's been running on average for the entire 2010. At Surmont, Surmont is not quite as good as FCCL, but the cash breakeven at Surmont is $21 a BOE. And on a net income basis, it's $27.65. So very competitive projects. They will continue to attract capital.

Yes. And the other thing I didn't mention, Doug, is not only can we replace our reserves and grow our production, not just on a per-share basis, but absolute level as we get into 2014 and 2015 from these type of projects. But they do have very good returns, so they really deserve. And that's built in to our capital spending plan.

Your next question comes from Blake Fernandez with Howard Weil.

I wanted to go back to the REX pipeline. I just wanted to confirm, are there additional expansion or operational opportunities over the next couple of years that are going to enhance the attractiveness of that asset or you're just simply needing the macroenvironment to improve?

I think it's just the macroenvironment to improve. I don't think we're looking at expansions through that. I think there is a question, a concern that has an impact to potential buyers of the REX pipeline, how quick and fast? Is Marcellus going to develop? Does that back up the purpose of the REX pipeline? And it's not over the next 10 years. That's pretty well signed up for the throughput and the users of the pipeline and questions beyond 10 to 20 years out. So I think that's really the impact. It's just not because there's going to be changes in the pipeline. It's how does it fit longer term and that has an impact in a rather skeptical business environment to buy assets like this. But we think that will improve.

And the only other one for you. The 180 million cubic feet that was curtailed late in the third quarter, would you mind providing any specifics on regions on basins that that's coming from?

I can give you a little bit. I think 150 MCF a day is Western Canada, and then there's six a day -- or about 35 MCF a day out of San Juan in the Bossier.

We'd actually do more curtailment if we could, and the reason is, is that we have partners and we have maybe smaller companies or independents or whatever, leaseholders who go along with curtailment. I mean, we would do more if we could because we just think it has more value in the future. Now you can look at our production guidance, where the fourth quarter guidance would ultimately come in 2011. I mean, we could make our production 1.75, 1.78 by spending more money and not curtailing production, but we look at it and we see say, "It doesn't make a lot of sense to spend money for dry gas in a lot of places in the North America. And we should really be curtailing production. But if you want production to be 1.75 or 1.78, we could do it, but we don't think that's a wise spend of our money. That's why we've come up with the numbers we do for guidance for production.

The next question is from Khan Faisel with Citigroup.

But just following up on the last question in terms of the volumes that are shut in. I guess, how long do you guys plan to keep the volume shut in? Or I guess, the more important question is what was the break-even price that you kind of bring back at that production?

In many respects, we can get to breakevens where even at price levels you're seeing today, you can maybe argue that you would produce this. But on the other hand, we're not willing to just put volumes to push volumes and essentially just breakeven. We think that market will sort out not in a short term, but ultimately will sort itself out and become less dysfunctional. And we'll see the economy improve somewhat. And we'll see more demand, and there won't be as much drilling for economic reasons, opportunities to take the cash from previously hedged positions with the other independents or whatever. The market becomes less dysfunctional. So we really are looking at it. We say, as you go forward and look, we think that really price levels we see today are really unsustainable. So we got to start seeing price levels moving toward $4 and $5 that we think, with time, will come. So that's really what's factored into our decision.

Yes. Faisal, the Western Canada gas breakeven on a net income basis are between $5.50 and $5.75 an M. And in Lower 48, that number is around $3.75.

And then you might go through what the cash...

On a cash basis, looking at this year, it's been between $1.65 and $2 an M for Western Canada, and around $2 for Lower 48, San Juan and Mid-Continent BUs as well.

And then if you could give us a little more color on the sequential change, of the change in U.S. refining income? It looked like you went from $782 million in the second quarter to $199 million. And it looks like the capture rate is kind of went down over the quarter, too. Can you talk a little bit what's going on there?

Yes. Sequential change in R&M of about $500 million. We identified the inventory impact, so that's just how we value the underlying physical against the paper position. We expect to get that $75 million back. But we did have lower marketing margins of around $70 million. And then our Coke business and our Chemical Feedstock business combined had a negative impact of about $50 million. And then the balance really is realized in our crack spreads.

And just another thing, too, Clayton, and that is we embark upon a very major turnaround activity late in the third quarter just going through the fourth quarter, and this certainly impacts our performance. We gave out the guidance in terms of turnaround costs. But we complete these turnarounds. We're really setting ourselves up. We feel quite well for the long run as we go into award [ph] or turnaround requirements in the subsequent years of 2011. So we're going through some pretty extensive turnarounds right now. That has an impact on performance and financial results.

The international realized margins of 1027 to 441, that's substantially lower than what the indicated margins did. Any color on that?

International, are you talking about international R&M?

Yes, R&M, yes. So realized margins went from 1027 to 441.

I'm going to have to come back to you on that one.

The next question comes from Pavel Molchanov with Raymond James. Pavel Molchanov - Raymond James & Associates: First, just on the upcoming exploration, can you give us any pre-drill reserve estimates for the Wildcats in Kazakhstan and Norway.

We generally don't, Pavel. We just have historically not given any kind of orders of magnitude on the size of the structures that we're looking at. They're significant, obviously, especially on the Caspian. But we don't typically make those kinds of comments. Pavel Molchanov - Raymond James & Associates: Can you say if these are more oily or more gas related?

I wish we knew.

Obviously, everyone is looking for oil, but I think it's just not appropriate or we're not really willing to get into that. Pavel Molchanov - Raymond James & Associates: And then the second one just on -- a little more conceptually, a lot of your peer companies have been getting into biofuels, particularly next-generation biofuels through JVs, partnerships, et cetera. You guys have generally stayed away from that. Are you looking for the right opportunity or are you generally inclined to just stay away from that trend for now?

Well, two things. First, we believe from a political process, let's not create winners and losers and get any into things that are heavily subsidized or the only way they work is you need to have continuation of governmental incentives. But we have quite an opportunity, so it's prior question [ph]. We have so much to do in our traditional Oil and Gas business or the E&P. We're going to allocate all of our money essentially towards that. And about $1 billion, $1.5 billion in the Downstream, primarily for maintenance capital and some payout opportunities. But then you'll see us ramping up more, our spend for technology and research. A lot of that goes towards more on the business side. But also just to the things you're talking about, we think it makes a lot more sense to be spending money in understanding and making some technology breakthroughs than to start spending hundreds of millions or billions of dollars in businesses that are questionable value creators for the shareholder and dependent upon subsidies from the government. So we're going to study and work this, but we're going to do it primarily through ramping up money that we're spending on research and technology.

[Operator Instructions] Ladies and gentlemen, this does conclude our Q&A session for today. I would like to hand the call back over to Mr. Clayton Reasor for closing remarks.

Right. Well, we appreciate the interest in the company. Obviously, if you have further questions, we're available to take those. You can find a replay of the call and a copy of our slides on our IR website on conocophillips.com. So thanks, again. We look forward to talking to you soon.

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