ConocoPhillips (COP) Q3 2011 Earnings Report, Transcript and Summary

Welcome to the Q3 2011 ConocoPhillips Earnings Conference Call. My name is Kim, and I will be your operator for today's call. [Operator Instructions] Please note that this conference is being recorded. I will now turn the call over to Mr. Clayton Reasor, Vice President of corporate and Investor Relations. Mr. Reasor, you may begin.

Thank you. Well, good morning, and welcome to ConocoPhillips Third Quarter Earnings Conference Call. We appreciate your interest in the company. I'm joined today by Jeff Sheets, Senior Vice President of Finance and our CFO. This morning, we'll provide a summary of our key financial and operating results for the third quarter, as well as our outlook for the remainder of 2011. You can find our presentation material in the Investor Relations section of the ConocoPhillips website. But before we get started, I'd like you to take a look at the Safe Harbor statement that we have on the next slide. It's a reminder that we will be making forward-looking statements during this presentation and during the Q&A. Actual results may differ materially from what's presented today, and factors that could cause those actual results to change are included in this slide, as well as in our filings with the SEC. So with that, I'll turn the call over to Jeff Sheets to take you through our prepared remarks and presentation.

Thanks, Clayton. I'll start on Slide 2, which highlights some of our third quarter results. During the quarter, we had adjusted earnings of $3.5 billion, which is $2.52 per share. This compares to adjusted earnings of $1.50 per share in the third quarter of 2010. We generated cash from operations of $4.10 per share during the quarter. Third quarter production of 1.54 million BOE per day was lower than the prior quarter, but in line with our expectations. In R&M, with 92% global refining utilization, we were able to take advantage of the improved refining margin environment. We generated $5.6 billion in cash from operations this quarter. Our annualized return on capital employed was 16% and our cash return on capital employed was 24%. During the quarter, we completed the sale of the Wilhelmshaven Refinery in Germany and announced that we are marketing the Trainer Refinery in the Philadelphia area. These steps are consistent with our stated objective to reduce refining capacity by rationalizing low-returning refining assets. Our purchase of 46 million shares this quarter represented 3% of our shares outstanding. So let's turn to Slide 3 and we'll discuss some of the details of our performance for the quarter. Total reported earnings were $2.6 billion, which included $837 million of special items. Special items included $329 million in noncash charges related to the Trainer Refinery, a 275 -- $279 million loss on the dilution of the company's interest in APLNG, a $109 million increase in deferred tax expense from tax legislation enacted in the United Kingdom, as well as losses on the sale of our Wilhelmshaven Refinery and costs related to the Bohai Bay incident. Total company adjusted earnings were $3.5 billion, which is up about $1.2 billion compared to the third quarter of last year. Our E&P segment improved by $686 million due primarily to higher prices, but this was partially offset by higher taxes and lower volumes. R&M adjusted earnings increased $928 million due largely to higher global Refining and Marketing margins. In the third quarter of 2010, our earnings included $436 million related to our ownership interest in LUKOIL. And since we've disposed off our interest in LUKOIL, we no longer have similar earnings in our third quarter 2011 results. Our other segment earnings were $38 million higher than a year ago as a result of higher Chemicals and Midstream earnings, offset by higher corporate expenses. So next, we'll look at more detail on our segment earnings, starting with our Upstream business, which is highlighted on Slide 4, and we'll talk about production first. Our production decreased approximately 10% compared to the third quarter of last year. And on this slide, I'm going to walk through the key factors behind this change. We had asset dispositions of 39,000 BOE per day, about 20 of which was North America natural gas production. The events in Libya reduced production by around 48,000 BOE per day. We continue to see significant decline in Russia. Our production in Russia this quarter was down 24,000 BOE per day, which is about half the production level we saw in the third quarter last year, and that's due to poor reservoir performance at the YK field. We also saw a reduction of around 28,000 BOE per day in our North America natural gas production due to our decision to reduce capital directed toward North America natural gas. So when you look at Libya, Russia and North America natural gas, about 50% of our decrease this quarter was from these areas. And these are areas where we have low-margin production. These areas average $10 to $15 per BOE of cash margins, which compares to around $27 per BOE for our portfolio overall. In China, production decreased by an average of around 32,000 BOE per day for the quarter, primarily as a result of the suspended operations in Bohai Bay. We had more downtime this quarter than we did in the third quarter of last year. The 28,000 BOE per day impact was related to both planned turnaround activity in the North Sea and unplanned downtime in Alaska and Indonesia. We expect that this production will largely be back in line in the fourth quarter. In the rest of our portfolio, increases from exploitation drilling, well performance, as well as new production from major projects, primarily higher-margin production from Qatar and the Lower 48 liquids plays, more than offset normal fuel declines. So now, I'll turn to the E&P earnings on Slide 5. Our adjusted earnings for E&P this quarter were $2.2 billion, up $686 million from the third quarter of last year. This increase was driven primarily by higher prices. Realized prices were up for all commodities this quarter compared to last year, which drove adjusted earnings higher in both our U.S. and international operations. The benefit from higher prices was partially offset by lower sales volumes and higher taxes associated with the tax law change in the U.K. In the U.K., we had $125 million impact included in our adjusted earnings in the third quarter. $75 million of this was associated with applying the higher tax rates to our second quarter results and $50 million was associated with the higher tax rate in the third quarter. In the cost and other category, we saw a benefit to adjusted earnings, primarily due to lower DD&A rates, which was partially offset by increased dry haul cost and higher G&A. So I'll move on to Slide 6 and talk about some of our E&P unit metrics. Income per BOE improved from -- improved to $15.49, up from $9.53 a year ago, and cash per BOE improved to approximately $27 compared to $22.30 a year ago. The more -- majority of this improvement was attributed to stronger commodity prices. However, we continue to see benefits as we shift our portfolio towards higher-margin barrels. And now let's go to Slide 7 and talk about R&M earnings. Our adjusted R&M earnings were $1.2 billion in the third quarter, an increase of $928 million compared to the same period last year. And higher refining margins were the primary driver for this improved earnings in the quarter, making up nearly $900 million of that increase. As you can see from the table on this chart, our realized margins in the U.S. more than doubled compared to last year, resulting in significantly more adjusted earnings in the U.S. this quarter than in the third quarter of 2010. There was a small benefit from volumes and operating costs in the quarter. And refining capacity utilizations were 92% in the U.S. and 93% internationally. The $129 million that's in the other category, the negative impact there was comprised of several items, with foreign exchange impacts being the largest of those. The current quarter included approximately $120 million related to, primarily to hedges on inventory positions, and the cumulative net impact of that effect year-to-date is near 0. And as we look forward to the fourth quarter, we don't anticipate there'll be a significant impact from inventories -- from hedge-related inventory impacts as these inventories are liquidated. Now let's take a look at R&M unit metrics on Slide 8. The per barrel metrics for Refining and Marketing were very strong this quarter. Third quarter net income per barrel was $4.08 and cash contributions was $4.79. Higher realized margins drove the improvement in the unit metrics compared to the third quarter of last year, as well as the second quarter of this year. Now effective October 1, our refining capacity was reduced to 2.2 million barrels per day, resulting from our decision to either sell or idle Trainer Refinery. And with the removal of Trainer from our portfolio, we expect to see these unit metrics improve going forward. Now we'll take a look at our results from other operating segments on Slide 9. Our Chemicals and Midstream segments both had good quarters. Chemicals reported earnings of $197 million, a $65 million improvement compared to last year, and this is the third consecutive quarter of near $200 million earnings from Chemicals. The increase was primarily due to higher ethylene margins, as well as increased equity earnings from CPChem's interest in the Q-Chem 2 project in Qatar. Midstream earnings of $137 million were $60 million higher than in the third quarter of last year. The improvement was primarily driven by the result of higher NGL prices and increased trading and marketing results. Adjusted corporate expenses were $267 million this quarter. That's $105 million worse than a year ago, but this change was primarily driven by the absence of a foreign exchange gain that we recognized in the third quarter of 2010. So let's go to Slide 10 and look at our cash flow for the quarter. We generated $5.8 billion in cash from operations this quarter. In the quarter, we invested $3.8 billion in our capital program, $3.5 billion of which was directed to E&P. Distributions to shareholders totaled $4.1 billion this quarter, comprised of $3.2 billion of share repurchases and $900 million of dividends. So if you look at from the start of our share repurchase program in 2010 through the third quarter of 2011, we have repurchased 174 million shares at an average price of around $68 a share for a total cost of $12 billion. This represents 12% of our shares outstanding. We ended the quarter with $3.4 billion in cash and $2.6 billion in short-term investments for a total of $6 billion in cash and short-term investments. Turning to Slide 11, we'll take a look at our capital structure. Our equity was down $3 billion compared to the end of 2010 as the increase in equity due to earnings was more than offset by reductions from share repurchases, dividends and some foreign exchange impacts. Debt was $23.2 billion at the end of the third quarter. We expect to retire $500 million in maturing debt during the fourth quarter, and our debt-to-cap ratio at the end of the third quarter was 26%. We'll move now to Slide 12 and talk about our capital efficiency metrics. ROCE and cash returns improved compared to the third quarter of last year, driven by the growth in earnings and cash flow, as well as the lower capital employed, with the reduction in capital employed largely being a result of our share repurchase program. Third quarter annualized ROCE was 16% overall, with that breaking down to 15% for E&P and 21% for R&M. That completes the review of our third quarter 2011 results. I'll wrap up with some forward-looking comments before we open up the line to questions. I'll start with some guidance on the fourth quarter, and we expect to provide additional guidance regarding 2012 in January. In R&M, we had pretax turnaround expenses year-to-date of approximately $200 million, and expect full year expense to be around $300 million. And this is lower than the previous guidance that we've given of around $350 million. We expect global refining capacity utilization rates in the low 90s in the fourth quarter of 2011. At the Wood River Refinery, the CORE project construction remains on schedule for completion in October. Project start-up activities continue as planned and we expect will be completed in mid-November. On the Upstream side of our business, we anticipate fourth quarter production of 1.56 million to 1.58 million BOE per day, which brings our full year 2011 production guidance to 1.61 million to 1.62 million BOE per day. This outlook includes the impact of suspended operations at Bohai Bay. At Bohai Bay, we are currently seeing around 15,000 net BOE per day, resulting from activities to reduce reservoir pressures in the field, and we are in the process of developing our revised field operating plans. For 2011, we expect production per share to be 5% higher than 2010, excluding the impact of the loss production in Libya. There's no change to our 2011 DD&A guidance of $8 billion, our corporate expense guidance of $1.1 billion or to our anticipated $13.5 billion 2011 capital program. Now I'll switch to a discussion of some of our exploration activities. We continue to pursue high-quality unconventional opportunities. So far in 2011, we've added about 400,000 acres in North America shale plays, in areas that include Avalon, Wolfcamp, Niobrara and the Lower 48, Duvernay and Ken Allen [ph] in Canada. And if you look at it, that's about 60% of the North America acreage acquired in 2011 is in Canada. Internationally, we've announced that we've become a joint venture partner in the Goldware [ph] shale project located in the Canning Basin of Western Australia. The agreement will see us invest over 4 phases of exploration and earn and retain a 75% interest. Following completion of the initial drilling program, we'll have the right to assume operatorship of the Goldware project. In the Gulf of Mexico, the Coronado well spud earlier this month. We should know the results of this well in the first quarter of 2012. In Poland, the fourth well has been successfully drilled, and we will begin a several stage frac over the 500-meter horizontal section of this well in the fourth quarter. In Australia, drilling operations will begin at Poseidon early in the first quarter of 2012, and we are planning a 5- to 7-well appraisal program. In the N Block in Kazakhstan, the Nursultan well is expected to spud in the first quarter of 2012. We had a dry hole in the Arafura Sea offshore Indonesia with the Kaluka [ph] well, and we have no additional activity planned in the Arafura Sea at this time. Now shift to the discussion of our major projects globally. Activity levels in the Lower 48 liquids-rich shale plays continue to ramp up. Our third quarter production at Eagle Ford was about 31,000 BOE per day with 77% of that being liquids. We operated 15 rigs in this play in the third quarter, and we expect to be up to 16 rigs by year end. September production at Eagle Ford was 36,000 BOE per day, which reflected about 10,000 to 12,000 BOE per day of curtailments due to third-party trucking constraints. We continue to work closely with other companies to increase production offtake capacity in the near and long term. We expect continued rig activity -- rig count activity and production levels to continue to increase at our other liquids-rich plays in the Bakken, Barnett and Permian. In the U.K., the Clair Ridge project received government approvals in October. We have a 24% working interest in the project. We expect gross peak production around 200 -- around 120,000 BOE per day. We announced approval of the final investment decision for the initial train of the APLNG project. The 2-train project has an anticipated net production of 115,000 to 120,000 BOE per day. And this long-lived, low-F&D cost project provides a long-term earnings and cash flow source to our portfolio and delivers returns that are competitive with other LNG projects. Regarding asset sales, the company continues to expect to sell $15 billion to $20 billion of assets in the 3-year period from 2010 to 2012. We've completed $8 billion since 2010. We expect an additional $1 billion to $2 billion in the fourth quarter of this year or the first quarter of next year, with the balance of the program being completed in 2012. We continued to repurchase shares and expect to do so at a rate similar to the third quarter in the fourth quarter this year, and we expect to complete the $11 billion share repurchase program this year. And finally, turning to our announced spinout transaction. Earlier this month, we announced the future leaders of the 2 independent companies that will result from the repositioning. Ryan Lance will become the CEO of ConocoPhillips, the E&P company; and Greg Garland will become the CEO of the Downstream company. We expect to file the initial ruling request with the IRS this month, and the initial Form 10 with the SEC by mid-November. And this Form 10 will be a public document. It's still our expectation that the distribution of the Downstream company shares, which would complete the spinout, would occur in the second quarter of 2012. So that concludes our prepared remarks, and we'll now open up the line for questions.

Okay, Jeff, thanks a lot. In the remaining time of the call, we'd like to give all those interested an opportunity to ask questions. Our second quarter call, we ended up with some analysts that weren't able to get in. So we'd ask those that -- we request those that are asking questions, if you could limit to one question with one follow-up, and then re-up the second time around, we'd like to give everybody the opportunity to ask a question if they'd like to chime in. So, Kim, I'll turn it over to you now to open the line.

[Operator Instructions] And at this time, we have a question from Ed Westlake from Credit Suisse. Edward Westlake - Crédit Suisse AG, Research Division: Just, I guess, a quick question on the onshore acreage. You've continued to pick up acreage mainly in Canada, but it would make sense, I think, to be more aggressive in that area. Can you talk through your strategy for growing acreage in terms of what your ability is at the moment?

As we mentioned, we added around 400,000 acres so far this year, and that isn't -- it's not just Canada, it's a mix of Canada and the Lower 48. We have a substantial acreage position already and, of course, we'd like to continue to add to that longer term, but we need to do it at prices which make sense. So we are out there trying to develop acreage positions in areas that are still rather prospective in nature, where the costs are more reasonable. And we're going to be as aggressive at that as we can be, but always with our eye on what kind of returns do we think we can get out of these plays. So you're not likely to see us be competing in areas where acreage costs have already come up to very high levels. Edward Westlake - Crédit Suisse AG, Research Division: Okay. And just a specific question on China. Obviously, having to redo your plan before perhaps resuming drilling. What sort of scale of delay is there going to be before we can see production back?

Well, it's not going to happen near term. As we think about the fourth quarter, we are probably going to be at the same kind of levels that we've talked about, our current rates are at. It's going to be an extended period of time as we get production back in the field. We need to develop this operating plan and work with the authorities to get that plan approved, and we can't give you a real precise timetable on when that's going to occur.

Our next question comes from Jacques Rousseau from RBC.

Just wanted to get your thoughts on the 2012 buyback program. I believe you thrown out some guidance of $5 billion to $10 billion. But with your comments on asset sales, a few billion over the next few quarters, should we imply from that, that much of this buyback will take place in the latter half of 2012?

We haven't given any guidance on timing on share repurchase. I think you're correct, though, in that, that we've said that the asset sales program of $5 billion to $10 billion is primarily what would be used to fund the share repurchase program of $5 billion to $10 billion. So depending upon exactly how our asset sales program is developed, that could impact our timing on share repurchases. But other than that general guidance, there's nothing more specific we can give you right at this time.

Our next question comes from Paul Sankey from Deutsche Bank.

Back again to the share repurchase. I was just wondering how the split will affect that in 2012.

Again, kind of following up on the comments on the previous questions, the asset sales program is primarily what will fund the timing of the share repurchases. If you look at what comprises our asset sales program, it's a mix of Upstream and Downstream assets, but it's dominated, in terms of value, by Upstream assets. So as you think about share repurchase program to the extent share repurchases aren't done and asset sales aren't completed prior to the spin and they're completed after the spin, then the proceeds are most likely going -- more of it is going into the Upstream part of the company, which would be available to fund share repurchases in the Upstream part of the company.

That's great. Is there going to be -- I understand. But yes, that's clear. The split process presumably would suspend the buyback?

No, that doesn't. There is no requirement to suspend the buybacks.

Okay. So you can literally just keep going as a combined company with the buybacks guidance until you split, and then the split will continue along the lines of the asset disposals that occur for the rest of the year?

Right, well, in -- I mean, it -- just asset disposals are a big part of it. But, of course, we're always looking at the balance of cash flow and capital and what other investment opportunities are. So there could be buyback programs in both the Upstream and the Downstream company, just depending upon how all those different factors are mixing in.

Okay. I noticed that your proceeds from dispositions in Q3 were $2.2 billion. Is there a backlog of cash to come from previous dispositions? Or is the guidance that you gave of $8 billion completed, if you're like fully paid for in cash to you?

Yes, the $8 billion is completed with cash received. We are working on a lot of different potential asset sales which have different timing of when they are likely to close. As we look at the list of things we're doing, we can see that $1 billion to $2 billion of those will close either in the fourth quarter of this year or the first quarter of next year. And when we say close or closed, we mean close and fund. And then, like we've said previously, we've talked about the general categories of asset sales. But other than that, we're -- it's just not in our interest to really be a lot more specific about exactly which asset sales we are pursuing.

Okay. So you're saying that the $5 billion to $10 billion is majority Upstream, but you haven't given any more specific guidance on what those assets would be?

That's correct.

So it's just more than 50% is all we can...

More than 50%...

I mean, majority. Just to get the majority...

No. Let's say, no, it's more like 80% or 90% Upstream.

Our next question comes from Doug Terreson from ISI.

Jeff, in E&P, the new production there is generating much higher margins in 2011, I think, because you talked about almost irrespective of the time period that you want to compare against. And so my question in regards to drivers. Meaning, I think Gutter in Canada were mentioned last quarter as being pretty supportive. But I want to see if there are other positive drivers in the current period as well that might be a little different?

Yes. In the third quarter, we've -- the drivers are Gutter and the Lower 48, the liquid shift there. Though in the third quarter, we lost a little bit of ground with the unplanned -- with both the planned and the unplanned downtime because the downtime was in areas like Norway, the U.K., Alaska, Indonesia, all of which are relatively high, higher than -- average or higher-than-average margins. So that production will come back on in the fourth quarter as we don't anticipate that same kind of levels. And then we continue, as we talked about earlier, to ramp up production in the liquids-rich areas in the Lower 48, and we continue to have declines in some of the lower-margin areas, particularly in North America natural gas.

Sure. And also in divestitures, I think Vietnam and Kashagan -- or Kazakhstan appear fairly saleable in this environment. And so on those 2 positions, can you provide any insight on the company's level of investment in those 2 countries?

No. I think both of those are things that are talked about and are in this general category of looking around our portfolio in places where we have maybe not long-term strategic good opportunities, and our potential is being part of our sales program. But other than that, we don't really want to provide a lot of color on the process for asset sales.

Our next question comes from Arjun Murti from Goldman Sachs.

Just a question on your Lower 48 liquids production. It looks like it's been picking up nicely here. I think, Jeff, you alluded to the ramp up in the Eagle Ford. Given the nature of these shale plays, is it reasonable to now assume an ongoing sequential increase near Lower 48 liquids? I don't know if that's 5,000 or 10,000 barrels a day a quarter. Is it okay that we -- is that a reasonable way to start thinking about this now that you've kind of gotten on the shale growth mode here?

Yes, I think that's right, Arjun, and particularly in the Eagle Ford. And so we've said on the Eagle Ford that we were around 35,000 a day in the third quarter -- the actual rate in the third quarter. And with -- when we're still dealing with production constraints and probably will be from now through 2013, we think we're going to get to 100,000 barrels a day in Eagle Ford in 2013. And as we bring on the field, it's just fairly constant increase between current production levels and about 100,000-barrel-a-day level in the Eagle Ford. We're also starting to ramp up some activities in the Bakken as well.

Yes. So if you just looked at the Eagle Ford, Bakken and Permian, in the third quarter, we're around 100,000 a day in those 3 areas. We expect to be around 250,000 a day some time in 2013.

That's a BOE number, Clayton?

That's correct.

And 75%, 80% of oil, I presume?

I would say it is around 70%, that's right.

Got it. The related quick follow-up was just, I think you alluded to trucking constraints and so forth. I thought you all had your own Midstream infrastructure here? Maybe it's just the timing of hooking things up and so forth, but can you just try and connect the dots there please?

We are building out our own Midstream infrastructure.

Yes. I think there was a new trucking facility that was built in Eagle Ford and a couple at Bakken, but they really didn't move the needle that much in terms of increasing capacity, only maybe 1 or 2 a day. We have talked about building pipeline gathering system, kind of a trunkline to get us to a liquid trading point out of Eagle Ford. We think that's done, is it the middle of next year? But we've got a lag of 10,000 to 15,000 a day of Eagle Ford that we can't get out just because of constraints. And really, that will continue until more infrastructure is built up in the area. So I guess it's a good problem to have, to be producing more and these wells to be more productive than what we thought they were, and we are investing in additional infrastructure in that area.

Our next question comes from John Herrlin from Société Générale.

Two quick ones. With the Eagle Ford, you said that you were constrained infrastructure-wise. How many wells still need to be frac-ed and what kind of a quarterly inventory should we expect you to build?

Well, let's see. You're talking about inventory of wells in -- I don't think the backlog is on completion of the wells or frac-ing, John. I think it's hooking the wells up.

Okay. That's fine.

So actually, we have 3 dedicated completion crews at Eagle Ford. And that's more than enough to satisfy the 15 rigs that are running. It's to condensate trucking is the specific constraint.

Okay, thanks, Clayton. Last one for me is, you're selling more assets next year. Do you have a ballpark figure for what kind of volumes are associated with those Upstream sales?

Yes. I think we can go with the same guidance we had previously. It depends very much on what the composition of that -- the asset sales are, of course. But it's in the range of 50,000 to 100,000 BOE per day.

Our next question comes from Ian Reid from Jefferies. Iain Reid - Jefferies & Company, Inc., Research Division: A couple of questions. First one, one of your competitors in Queensland yesterday talked about a very significant rise in U.S. dollar-denominated CapEx due to movements in the Aussie dollar. The Aussie dollar is obviously very strong at the moment. I wonder if you're seeing the same sort of impacts as you start to award contracts there and whether you've done anything to mitigate that sort of impact?

Yes, that's certainly one of the major factors we're dealing with, with APLNG. And to the extent we can, we're trying to do as much of the project outside of Australia, not just because of the Aussie dollar impacts but just because of the general condition with labor there and the fact there's quite a bit of activity in a fairly concentrated area there. So we're moving things and trying to build as much modularize as we can, moving things, like I say, out of Australia. We have seen -- if you look over the last several years, of course, the Aussie dollar has strengthened considerably against the U.S. dollar. If you just look more recently, the U.S. dollar's gained a little bit of that back. But that is one of the major impacts that we'll be watching as we move forward with the construction on the APLNG project.

Yes, and we've built a little bit of that into capital program. Part of the increase from the $13 billion to $15 billion in 2012 E&P capital is due to foreign exchange impact, both in Canada and Australia. So there is part of that that's already embedded in our capital program. Iain Reid - Jefferies & Company, Inc., Research Division: Yes. They were talking about potentially 70% of the CapEx being denominated in Aussie dollars. Is that the sort of number you're looking at?

We're probably a little less than that, but not far off of that range. Iain Reid - Jefferies & Company, Inc., Research Division: Okay. Sorry, just one other very quick follow-up. In your asset sales program, you're talking about for 2012 onwards, is there kind of embedded in that any Downstream disposals?

Yes, there are.

Yes. We've talked about pipelines and we've talked about terminals. We've also talked about reducing our refining capacity down to around 2 million barrels a day. So that would imply that -- we're at 2.2 million barrels right now. So that would imply that there are possibly some refinery sales in that number. Iain Reid - Jefferies & Company, Inc., Research Division: Is it possible to say whether that's kind of something that could emerge in the short term, next 6 months or so?

Perhaps towards the end of that window. We're looking at various assets around our portfolio and have processes going on. But as -- as much like with the Upstream asset sales, we would prefer to talk about those when they get closer to being actualized.

Our next question comes from Mark Gilman from The Benchmark Company.

Was wondering if you could give us a little bit of an idea on the kind of tight curve and decline rate you're seeing on the Eagle Ford wells on average? And what the current producing well count is?

Let's see. We've got -- well, by year end, we're saying we're going to have over 150 wells drilled. I don't have -- and I'm sorry, Mark, what were the other details you were looking for? I need to...

I was looking for, was there kind of tight curve or EURs as well as decline rates that you're seeing?

The only thing we've got out there so far, and I would imagine we're going to provide more detail as we get more experience with the field, but the average 30-day well rate is still running around 1,400 BOE. We've got -- we've initiated pad drilling. We've got some details on the -- let's say more of an E&P type of approach to Eagle Ford that we could probably run you through, but I don't have EURs or decline rates on Eagle Ford for you.

So we had a 150-well program for the year, and we've been progressing that on through the year. I don't have the exact well count, but we're here in nearly November now, so we're obviously a long ways through that program. But, yes, I don't have the exact number of wells completed and wells waiting to be completed.

Okay. Let me try if I could shift to the Downstream for a sec. I'm a little bit curious about the decision to actually shut down Trainer in advance of sale when I believe it was generating positive cash margins. I wonder if you could talk about that a little bit. And at the same time, give any idea what the selling price or the proceeds were on the Wilhelmshaven sale?

We haven't disclosed the number on Wilhelmshaven. It was not a significant number in our overall asset sales program. The Trainer Refinery was not producing net income. It was depending upon the exact refining margin of the time. The cash generation was also not very strong. We were at a point where we were having to decide about the timing on turnaround cost and future capital expenditures, which had a lot to do with the timing of the decision to shut it down in October.

Our next question comes from Paul Cheng from Barclays Capital.

Two quick ones. Trading on just on Eagle Ford and Bakken, what is your well cost right now? And also that you'd given IP for Eagle Ford. Do you have an IP for Bakken? And also the EUR? The second question is on the Bohai Bay. Based on my estimate that at $100 brand [ph], look like their unit margin on those is going to be over $40 per barrel. Just want to see if that's on the ballpark, correct? And also I think Sinopec seems to suggest that a earliest of the resumption of their operation may be second quarter 2012. Want to see if there's any comment that you can make on that.

Why don't I take the Eagle Ford one. We haven't been real specific on well cost. I mean, these things are -- I can give you some data around -- well depth is somewhere between 16,000 and 19,000 feet. We're running 3,500 to 5,800 laterals. And on average, about 15 stage fracs. I think well cost that I've seen, drilling and completion are probably in the $6 million to $8 million per well range.

Okay. How about Bakken?

Let's see. I don't have that on Bakken, Paul, so that will be something we'll need to disclose later.

And that you disclosed about Eagle Ford on the IP? Do you have IP for Bakken?

Well, that's not IP. That's average 30-day rate. So IPs are actually higher than that. Average 30-day rate...

Okay. That's 30-day IP, I mean.

Yes. Average 30-day rate at the Bakken is around 950 barrels a day. We're running 6 rigs. We expect to have 7 by the end of this year and close to 90% black oil. Production in the third quarter is around 20 a day.

And then, Paul, in your questions on Bohai. Bohai is oil production, so it is a -- the cash margins on Bohai, we don't comment on precise cash margins at a field level, but you're in the right direction. We are -- we can't say, obviously, it's oil production, so it's in the better half of our margin production. As far as the timing of when production is going to resume at Bohai, we don't really have a comment on that. I think we don't expect it to be -- it's going to resume in the fourth quarter or early in 2012. But we're going to -- got to continue to work with the authorities on the new development plan. And as we know more, we'll update more on that.

And Jeff, can I just sneak in an unrelated question? In Libya have you guys go back and look at your fuel operation at all? Or that you haven't really in touch of the government yet?

We've just begun that process now. We start by getting some people in there to assess the overall security situation and get our comfort with being able to put people back into Libya. We're really in that process now. We don't have any update yet on the condition of the field and, therefore, really couldn't give a good answer as to timing on when we would expect things to come back.

Our next question comes from Doug Leggate from Bank of America.

The exploration and production step-up in capital for next year, I guess, $13 billion to $15 billion. Can you give us some idea how much of that is going to be in the Lower 48 or in the U.S., I should say, generally?

Yes. Of the $2 billion step-up, because if you think about what we've said previously, had guided more towards a $13 billion number for 2012 for Upstream. About half of that is dedicated to the Lower 48.

So what would that maybe absolute, Jeff, in terms of total CapEx, as you like?

Yes, it's around $5 billion in the Lower 48.

My follow-up, I guess, what's behind my question is, you guys, I guess, as of January 1 are going to -- well maybe not January 1, sometime next year, are going to be defamed on the U.S. tax code as an E&P company, which, if I'm not mistaken, means that you can now write off 100% of your intangible drilling cost. So what I'm trying to get at, Jeff, is how much of a tax shield would you anticipate with that level of capital expenditure in the Lower 48? Because I imagine it's a fairly substantial positive on your cash flow as we look over the next couple of years as you become an E&P...

Yes, I'm not -- I don't have that answer off the top of my head, and I'm not sure if those rules are just strictly based on being -- the business lines that you're in or if there's some size requirements in there as well. I don't have that answer.

So of the $5 billion, can you tell how much of that is actually drill bit capital as opposed to infrastructure?

It's mostly -- it's all drill bit capital.

Our next question comes from Evan Calio from Morgan Stanley.

Question on Poland. I appreciate your update, but I know at least how your partner traded the first horizontal well results in the market. Rednose [ph] is disappointing. I mean, can you assess what you learned from the first horizontal well and how the second one that's in process here probably differs? I believe it's testing the carboniferous zone, which differs in the per zone expectation timing there? If you would, I have a follow-up.

Yes. There's not a lot we can say about that because it's just so early in the play. So we've drilled 4 wells, 2 verticals and 2 horizontals, and we've tested one. And I'd say the results, we thought, were pretty well, within what we expected from that. And we'll need to test the second one, but that's really just going to be the beginning of trying to evaluate that field. So the results are encouraging. It looks like we'll want to continue to go ahead and build this out and acquire more information. But it's just too early for us to really give you much guidance as to whether we think these are good results or bad results. They're encouraging results that encourage us to go further.

Good. I appreciate that. Maybe a broader question. I mean, I know that Conoco's clearly been a better seller of assets, funding of outsize or repurchase, and I appreciate the forward sale guidance discussed. But as portfolio rationalization reaches advanced stages, I mean, is your view changed at all to potentially be a maybe more-targeted acquire with in your core skill set as we move into 2012, currently alongside announced asset high grading?

If you look at our portfolio, we've got a lot of good opportunities to invest within our existing portfolio and where we're going to spend our capital in the next 3 years to 5 years is pretty well defined already. But we're always on the -- be on the lookout for new opportunities. But the opportunities that we are going to be most interested in are things that help build out our longer-term portfolio, so things in 2016 and beyond, perhaps that kind of time frame. So as we think about things that we might acquire, it's still going to be focused on like we have been discussing on adding to our resource acreage base, adding to our exploration acreage and those type of opportunities as opposed to anything that is more focused on near-term capital.

Okay. If I could just -- just slip in a last one of -- just do an update on the current Seaway process and timetable, if you would? I'll leave it at that.

So the Seaway crude pipeline, which we own 50% of, and Enterprise owns 50% of, we've talked in early September that we would be open to selling our interest in that pipeline. Enterprise operates the pipeline. We are having some initial discussions with them about the sales process, and we're working to design and lay out the rest of the sales process. That will happen over the next -- over the coming months. There's nothing really new to report on that process other than that we're actively in the marketing process now for the pipeline.

Our next question comes from Ann Kohler from CRT Capital Group.

Most of my questions have been asked, but I do have a question. In looking at -- you certainly did put out the new -- named the new executives for each of the individual companies. Will you be providing additional color on the rounding out of the management teams for each of the companies? And if so, when will that be?

Yes. I think you can expect to hear more from us about rounding out the management teams before the end of the year.

Our next question comes from Philip Weiss from Argus Research.

Most of my questions have already been asked, but I did have one question on China. With what happened there at Bohai Bay, does this have any impact on your longer-term relationships or plans or opportunities there?

No, we've operated in China for quite a while and hope to continue to operate in China for a long time going forward, and we'll be -- still remain very interested in additional opportunities in China. So the short answer is no, it hasn't really changed our thought about continuing to make investments there.

Yes, they're a big customer. It's a part of the market that's growing. We want to be operating and selling LNG to China for the next 40 years.

Our next question comes from Faisel Khan from Citi.

I just want to get a little more color on the Refining and Marketing results. It looks like $1.2 billion in adjusted earnings. It looks like there wasn't a heck of a lot of after-tax profit on the international side. Is that fair to assume that all this income was basically generated in the domestic portfolio?

Yes, so -- I think there's a breakdown of that on the slides that we've provided. And it's also in the supplemental information. But you're correct, it's mostly in the domestic portfolio.

Can you give me a little bit of color on in terms of what regions the profitability came from? Was it mostly -- was it 50%, 60%, 70% Mid-Continent? Or is it 1/3, 1/3, 1/3 across the entire portfolio?

Well mid-Continent obviously was a very strong -- I don't think we are going to give percentages, but maybe just qualitative comments. Of course, the Mid-Con was a very strong area, substantial feedstock advantage there for refineries that can -- process WTI and WCS given the current state of the market, with the WGI brand differentials. The Gulf Coast and the West Coast markets were also reasonably strong in the third quarter. And the East Coast markets continue to struggle. So the most profitable areas were the refineries we had in the Mid-Con area. I don't have an exact percentage of how much of our earnings came from those refineries.

Okay. And on the CORE project, are you fully ramped up now on the project?

No. We're in the process of starting it up. So construction is mostly complete. And we're in the -- you start up the project in phases, and you start up different units as you go. We think by mid-November we'll be completely started up.

Okay. And you will completely shift your crude slate from light sweet crude to Canadian heavy? Is that fair to say?

No. It's just an incremental addition of Canadian heavy capacity.

Yes, what happens there, Faisel, so you have a significant increase in clean product yield as we convert a lot of asphalt that used to come out of Wood River into clean products. So clean product yield increased to 83% from 78%. Gross crude capacity change or increases to around 365,000 barrels a day. You've got 80,000 barrel a day of coking capacity, and you have increased clean product production of about 50,000 barrels a day with 20,000 of that being diesel and 30,000 of it being gasoline. So it's a -- it really helps you on both sides. You can't run more Canadian crude because you've increased coking capacity, but there's also a big uplift in clean product yield as we reduce the bottoms and produce more gasoline and more diesel fuel.

Okay, I got you. I understand. And then just on the Upstream side, the unplanned -- I guess the planned downtime in North Sea and the unplanned downtime in Alaska of 28,000 barrels a day, where are we with those volumes today?

Those are mostly back online in the fourth quarter.

That's right. Both Alaska and the U.K., North Sea are back online.

That's right.

And then last question on Bohai Bay. Do you guys have to reserve some sort of environmental sort of cost for this whole cleanup? Or is that kind of what we're seeing in your -- internally [ph] in your one-time costs that you flowed through in the third quarter?

Yes. So we had -- as you'll see on the detail of our supplemental information, we had a $40 million income impact related to that in the third quarter. We'll have some carryover to that type of impact in the fourth quarter that won't be as large as that number. We've announced publicly that we're going to set up a couple of funds to deal with any environmental claims and the status of those is that we're continuing to have discussions with the authorities in China about how we set up and administer those funds.

Okay. And that has not been expensed yet, I take it?

No, it has not. And we don't have a good -- any more real detail to provide about those funds.

Our final question comes from Mark Gilman from The Benchmark Company.

Guys, I just want to go back to the Seaway issue again. In terms of your thoughts regarding potential divestiture, have you backed away from the idea that you need that line running in its current direction in order to supply very specific crude requirements in Ponca City?

We think we have found other methods to supply Ponca City, which are more expensive than using the Seaway pipeline to do that. And that would be part of the calculation we'll do when we get a value for the Seaway pipeline, as far as whether it makes sense for us to sell our interest in the pipeline.

Okay. Jeff, if I could just ask, of the $120 million after-tax in the derivative/mark-to-market effects in the third quarter, how much U.S., how much foreign, assumedly all refining?

Yes, all refining. Mostly U.S. I'm not -- I don't have the percent of it. I don't have the exact...

Most of it is in the U.S.

Most of it's U.S. I mean, that's a good point that you raised there, Mark. So that $120 million, just to put a little clarity on that, was a third quarter item. But that was -- we had the opposite effect of that kind of spread out between the first quarter and the second quarter. So that's why we've said that's $120 million in the third quarter, but year-to-date is a 0. And that really has to do with differences on how physical positions and the paper positions, which are used to hedge physical positions, are marked due to the way the accounting rules work. So you get a little bit of timing noise from quarter to quarter as a result of that.

And I assume that's in your published margin?

It is. That is correct.

And we really don't expect any impact from that timing difference between the underlying paper position and the physical to occur in the fourth quarter.

Thank you. That was our final question. I'll now turn the conference back to Mr. Clayton Reasor.

Great. Well, thank you, all, for your interest and participation in the call. You can find the material and a replay of this call on our website later today. I look forward to talking with you in the future. Thank you.

Thank you, ladies and gentlemen. This concludes today's conference. Thank you for participating. You may now disconnect.