ConocoPhillips (COP) Q1 2011 Earnings Report, Transcript and Summary

Welcome to the First Quarter 2011 ConocoPhillips Earning Conference Call. My name is Kim, and I will be your operator for today's call. [Operator Instructions] 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. Good morning, and thanks for your interest in ConocoPhillips. We're here to talk about our first quarter 2011 results. And I'm joined today by Jeff Sheets, Senior Vice President of Finance and Chief Financial Officer. This morning, we'll provide a summary of our key financial and operating results for the first quarter, as well as our outlook for 2011. As in the past, you can find our presentation materials on the Investor Relations section of ConocoPhillips website. Before we get started, I'd like you to take a look at the Safe Harbor statement we've got on Slide 2. And it's just a reminder that we'll be making forward-looking statements during the presentation and the question-and-answer session. 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. Now I'll turn the call over to Jeff to take you through our prepared remarks and presentation.

Thanks, Clayton. And good morning to those on the call and those listening in on the Web. I'll start with Slide 2 which highlights some of our first quarter results. So during the first quarter, our earnings after adjustment for special items were $2.6 billion. That's $1.82 a share, which is up from $1.47 share in the first quarter of 2010. We had improved financial results this quarter compared to a year ago, however we experienced more unscheduled downtime than normal in both our E&P and R&M sectors and that adversely impacted income by about $150 million. Earlier in the quarter, we announced a 20% increase into our dividend and our board authorized a $10 billion share repurchase program. And in the quarter, we returned $2.6 billion of cash to our shareholders in the form of dividends and share repurchases. Our annualized return on capital was 12% for the quarter and cash returned on capital was 21%. Our first quarter production was 1.7 million BOE per day and our global refining capacity was 89% during the first quarter. During the quarter, we generated cash from operations of $4 billion, excluding working capital changes, and ended the quarter with $8.4 billion in cash and short-term investments. So let's turn to Slide 3 and discuss some of the details of our performance. So the total company adjusted earnings were $2.6 billion, up $426 million compared to the first quarter of 2010. Both E&P and R&M improved earnings from over a year ago. Our E&P segment improved $282 million due to higher liquids prices which were partially offset by lower production volumes and higher production taxes. Compared to the first quarter last year, our R&M segment generated $459 million more in earnings this quarter due primarily to higher refining margins. Controllable costs were flat for the quarter compared with a year ago. However, variable compensation expenses related to prior year performance negatively impacted earnings for the quarter by about $50 million and that cost was spread out across the operating segments. This quarter's earnings were also negatively impacted by the discontinuation of equity accounting for LUKOIL. So if you exclude the $385 million impact of LUKOIL earnings in the first quarter of 2010, our adjusted earnings for the first quarter of 2011 are around $800 million higher than our earnings in the first quarter of last year. So we move to our next slide and take a look at production levels for the quarter. First quarter production was 1.7 million BOE per day, that's 126,000 BOE per day lower than the first quarter of last year. Field decline decreased production this quarter versus last quarter by about 187,000 BOE per day, that's primarily out of the North Sea, Lower 48, China and Alaska. But nearly offsetting this decline was 175,000 BOE per day of production from new projects, as well as new drilling and improved well performance around our existing production. Now the increase in production from projects is primarily from Qatargas 3, Bohai Bay and the Lower 48 liquids-rich shale plays. Downtime also adversely impacted our production during the quarter. The 65,000-barrel per day reduction is primarily due to civil unrest in Libya, several-day shutdown of the Trans Alaska Pipeline System in January, supply vessel collision with our Brittania platform in the U.K. and other downtime in the North Sea. The impact to production from asset dispositions was 49,000 BOE per day. Nearly all of this is related to the dispositions we did in 2010 in Canada and the Lower 48. We filled some additional nonoperated interest in the Lower 48 in the first quarter, but that only impacted production by about 2,000 BOE per day. If you look just at North America natural gas, the reduction was about 50,000 BOE per day of this total decrease in production. So if you turn to Slide 5, we can talk about E&P earnings. So E&P adjusted earnings for the quarter were $2.2 billion, which was 15% higher than the same quarter a year ago. Higher prices and other market impacts contributed $519 million of the increased earnings. The earnings improvement was partially offset by a $294 million decrease in after-tax revenue from lower sales volume, and there was a $57 million benefit from costs and other items during the quarter. So if you look at the table on the bottom of the slides, you can see that the improved E&P earnings were driven by international earnings. The U.S. adjusted earnings declined compared to the first quarter last year, largely driven by lower volumes, partially offset by higher liquids prices. Our realized crude oil and NGL prices were higher in the first quarter of last year, while realized prices for bitumen and natural gas were flat to slightly lower. The impact of lower Henry Hub prices being partially offset by higher natural gas prices internationally. So we'll move to the next slide and talk about E&P metrics. Look at E&P income per BOE, both income per BOE and cash contributions per BOE increased reflecting the improvement in prices for oil and NGL, as well as some self-help in the form of shifts in our production mix. We continue to shift production away from Lower 48 and Canadian natural gas given our view that natural gas prices are going to be pretty subdued in the near to medium term. And Lower 48 represents a shrinking -- Lower 48 and Canada gas represents a shrinking part of our portfolio. If you look at 2008, it was 28% of our portfolio, it was 26% in 2010 and 24% in the first quarter of 2011. So full year 2010 E&P income per BOE was $10.56. If you look at the first quarter, it was $14.34, so an improvement of $3.80 per BOE. About 10% of this margin improvement can be explained by the shift in production away from Lower 48 and Canadian natural gas that I just discussed. So turning to R&M on Slide 7. Our Refining & Marketing adjusted earnings improved significantly over the same quarter a year ago. Downstream market conditions were stronger in the U.S. and U.S. market cracks improved over 130%, driving a $464 million improvement in margins and other impacts. Volumes were a small benefit this quarter compared to the first quarter last year mainly driven by increased volumes in some of our specialty businesses and in U.S. marketing. Our refining capacity utilization of 86.7% from the quarter was essentially unchanged from the first quarter of last year. International refining capacity increased to 96%, up from 79% of the same quarter of last year when we adjust for the fact that we are no longer operating the Wilhelmshaven refinery. Unplanned downtime cost us about 2% of first quarter utilization, and the majority of this downtime occurred at our Sweeny and our Borger refineries. Compared to the first quarter of 2010, operating costs were $26 million higher, primarily due to higher maintenance, compensation, and environmental and turnaround costs, partially offset by some lower utility costs. As you saw on our press release, we built inventory in R&M in the quarter. Because we're in the market buying crude for refineries and selling products both from our refineries and our upstream assets, we had a strong fiscal position which allows us to do some profitable trading around these positions by capturing arbitrage and blending opportunities in the market. Establishing discretionary inventories is a part of that trading operation, and trading contributed about $50 million to R&M earnings in the first quarter. So the working capital impacts that we see from these discretionary inventory builds will be used as a cash in some quarters, and they'll be sources of cash in other quarters, but they'll tend to balance out over time. So we'll take a look -- a quick look at results from our other segments on the next slide. Chemicals segment posted record earnings of $193 million in the quarter, up $110 million from a year ago. This increase being driven by higher margins and lower operating costs. Midstream earnings of $73 million were essentially flat with last year, and corporate costs of $300 million were essentially flat with last year as well. So we'll move on to Slide 9 and look at cash flow for the quarter. We generated $4 billion in cash from operations this quarter if you exclude the $2.1 billion increase in working capital. We generated $1.8 billion in cash proceeds from dispositions. These proceeds included about $1.2 billion from the sale of LUKOIL shares and $600 million from other asset dispositions. With this cash, we funded $3.1 billion of the capital program, which was $2.9 billion in E&P and around $200 million in R&M. As I mentioned earlier, distributions to the shareholders were $2.6 billion for the quarter, which included the repurchase of 21 million shares at a total cost of $1.64 billion and $940 million of dividends. We resumed the share repurchase program in mid-February, following the announcement of our dividend increase and our share repurchase program. Debt reduction was around $400 million for the quarter. And at the end of the quarter, we had $6.2 billion in cash and $2.2 billion in short-term investments. And we expect to use the majority of this cash to repurchase ConocoPhillips shares. Now turning to the next slide, we'll take a look at our capital structure. On this slide, we just give some history of our equity and our debt levels. Not a lot of change this quarter compared to the end of 2010. Current debt balance was $23.2 billion; debt to cap ratio, right around 25%. As we said previously, we're happy with where our debt balance is and we'll see it drift down a little bit over time as we have debt issues mature. We had $400 million of debt mature in the first quarter and we'll see about another $500 million of debt reduction for the balance of the year. So we don't see any to substantially reduce the debt balances from where they are today. The debt is long term, it's low cost, and we have a pretax average cost of this debt of around 5.5%. So we'll move to the next slide and talk some about some capital efficiency metrics. ROCE and cash returns here that we're showing now exclude the impact of LUKOIL to our current and our prior periods. So both our ROCE and cash returns improved in the first quarter, driven by growth in earnings and cash flow. Capital employed was basically flat for the quarter, and we had a slight increase due to some foreign currency adjustments. Upstream ROCE for the quarter was 15% compared to 12% in 2010. Downstream ROCE annualized for the quarter was 8% which is compared to 5% in 2010. So this completes the review of our first quarter results, and I'll wrap up with some forward-looking comments before we open the line up for questions. I'll start with some guidance on our downstream business. We expect 2011 turnaround activity to be similar to what we had in 2010, so pretax expenses of around $400 million to $450 million, and this is going to be weighted toward the second half of the year. We expect 2011 global refining capacity utilization rate to be around 90%. And our total refining capacity now is 2.4 million barrels per day, that's down 2.7 million barrels per day last year, due to the shutting down of the Wilhelmshaven refinery. At our Wood River refinery, we still expect the new units related to the core project to be up and running in the fourth quarter of this year. As we pointed out at the analyst presentation, we expect that this project will increase heavy crude capability by about 130,000 barrels per day, improve our clean product yield by 5% and increase our realized margins by about $4 a barrel. So moving to E&P. We've given guidance that we expect 2011 production to be about 1.7 million BOE per day before the impacts related to Libya production or any other additional asset dispositions. Typically, our second quarter and our third quarter production levels are lower than our first and our fourth quarter due to increased maintenance in the North Sea and lower production out of Alaska. The events in Libya negatively impacted our production in the first quarter and will continue to do so at a rate of 45,000 to 50,000 barrels per day. But the earnings and cash flow impact associated with that are around $25 million to $30 million per quarter. Our OECD focused portfolio is less sensitive to PSC impacts. A $10 per barrel increase in our oil price impacts production by about 1,000 to 3,000 barrels per day due to the PSC impacts. So last month, the U.K. proposed a tax legislation, which if it's enacted in the third quarter of this year as they've talked about, it's going to -- which will significantly increase the tax liability to our U.K. upstream operations. When this law is enacted, we would expect that we're going to record about $100 million noncash charge to earnings due to the re-measurement of deferred tax liability. They also announced a second tax proposal related to the taxes -- tax rates applicable to decommissioning costs. And if that's enacted, that will result in an additional noncash charge in 2012 from remeasurement of deferred tax liabilities. And we're currently evaluating the potential impact of that legislation to our operations. So moving to exploration. In the North Sea, we had 2 wildcat wells planned to test the Deep Triassic prospects. We sped the Peking Duck wildcat in late March and expect to reach target depth late in the second quarter. And we expect to spud the Pelican wildcat in 2012. Also in the North Sea, we acquired 2 Norwegian blocks in the Barents Sea during the first quarter. In the Caspian, the results of the Rak More discovery are still being analyzed, and we expect to spud in the Nursultan well later this year or early next year. In Poland, we expect that the third well in May to further delineate our opportunities in this area. This is the first horizontal delineation well, and it follows 2 vertical wells in 2010, which tested the play concept. We continue to pursue high-quality unconventional opportunities in North America. In this quarter, we added 33,000 acres in the emerging Wolfcamp shale play in the Midland Basin. We remain encouraged by what we're seeing from results at Eagle Ford. Early production performance from the wells was better than what we expected. Initial rates are strong and the production is not declining as fast as we initially premised. We expect to have 14 rigs operating in this play during the majority of this year. And production from Eagle Ford in the first quarter was 71% liquids. We're also active in the liquids-rich areas of Bakken, North Barnett and Permian with 10 rigs operating in those areas. We expect to take that up to 12 rigs during this year. And in addition, we are participating in around a dozen nonoperated rigs in these areas. In all of the Lower 48, our plans are to have twice as many rigs running by year end than we have running in the first quarter of last year. So shifting to Australia. APLNG executed a binding sales and purchase agreement with Sinopec for the supply of 4.3 million tons per annum of LNG for 20 years. And as part of this agreement, Sinopec is going to become a 15% equity owner in APLNG. And we are still targeting a midyear final investment decision, at which point we anticipate that we'll recognize around a $250 million loss related to our dilution of our interest in APLNG. And we still are in very active discussions with potential offtakers for the second train volumes. This was the first full quarter of operations for our QG3 projects. The project in general ramped up faster than we expected, and we're very pleased with the performance of this project. Our 50-50 joint venture, Chevron Phillips Chemical, announced that it's advancing a feasibility study to construct a world-scale ethane cracker in one of its facilities along the Gulf Coast. As we discussed in our analyst presentation last month, we continued to advance our asset disposition program and we expect to generate $5 billion to $10 billion of proceeds from asset sales in 2011 and 2012. We had given guidance previously that we expect these sales impact production by 50,000 to 100,000 BOE per day and take refining capacity down from 2.4 million to 1.9 million barrels per day. So on the share repurchase side so far this year, through yesterday, we've repurchased 32 million shares at a total cost of $2.5 billion. And we still expect to spend somewhere between $5 billion and $10 billion on share repurchase in 2011. So that concludes our prepared remarks, and we'll now open the line for questions.

[Operator Instructions] And at this time, we have a question from Kate Minyard from JPMorgan.

Just a couple of quick questions. First of all on APLNG, what are the milestones that we're looking for in terms of gas sales agreements that would enable you to reach an FID? And is there any level of gas price risk that ConocoPhillips would be willing to assume in order to advance the project to that stage?

So we've got one train sold now to Sinopec, and we're actively marketing the second train. As we go through the next few months, we'll be having discussions with our partner about exactly what type of final investment decisions we'll take, whether we take a one-train FID or 2-train FID or one train with building infrastructure for the second. Those are all things we'll be in discussion with our partner over the next few months as we continue to market the second train. We can't really say today exactly what type of FID we will take. We're very optimistic about our ability to sell the second train, though. The market continues to have a good, strong demand for LNG both in the nearer term and the longer term. As far as whether ConocoPhillips would take a significant gas price risk to market the trains up, we don't view that that's necessary, that there's a good, strong market out there for sales of LNG from the project.

Okay, great. And then just quickly on CapEx in Lower 48, at current oil prices, just curious as to whether you'd be looking to increase spending in the Lower 48. And if so, when might we see a production volume response from that? And I'll go ahead and leave it there.

Yes. So at the analyst presentation, we talked quite a bit about our plans for the Lower 48 and there's nothing new from what we said about a month ago on Lower 48 capital. So we're continuing to evaluate the resource plays that we have there for potential and incremental investment opportunities. So it is a potential that we could do incremental CapEx. We haven't made any decision to do that yet. But the production guidance that we gave at the analyst presentation as far as the rate of increase from the shale plays is about the same as what we had said before. We ultimately think we're going to get that up to around 100,000 barrels a day coming out of the Eagle Ford, the Bakken and the Barnett. And we think by the end of this year, we're going to be up -- what was that? Do you remember the number there, Clayton? We'll be probably up to 40,000 or 50,000 by the end of this year.

That's right. Yes, I think the guidance we've given on Eagle Ford, Bakken and North Barnett is around 50,000 barrels a day by year end.

Our next question comes from Doug Terreson from ISI.

Jeff, the quality of your E&P portfolio's improved considerably over the last several years with the success you've had over the development side and the divestitures, the plan is underway. And while your costs and on-schedule performance has been pretty good in the past, it looks likely that it's going to be a little bit challenged in the future given the number of projects that you have in Asia, specifically in China, Malaysia and APLNG. It's a pretty long list. And that's true especially with competitor investment in the region rising. So my question is, is how is the company preparing to manage this size while ensuring that you guys sustain this positive project delivery record and the returns that you expect in that area?

Yes, so I think the challenges we have or what you outlined is we're operating in the areas where there's significant other activity. So we're being very aggressive about how we're managing developments. In Queensland, for example, they're working now with our EPC contractor to make sure that we don't run into difficulties there as we execute those projects. In our heavy oil developments in Canada, the same kind of thing, we know that that's a multiyear development, and we really work to schedule those things out to where that gets done. If you look at our resource plays in North America, like how we're developing Eagle Ford, we've made sure we had the rig commitment and the completion commitments in place early as we develop those programs. So yes, we've got a lot of things going on in terms of developing our portfolio and there's always schedule risk. But part of what -- we recognize that going into these projects, and we're putting a lot of effort into managing that schedule and cost risks up front.

Okay. And also in E&P, ConocoPhillips took an almost $5 billion noncash impairment in 2007 related to the position in Venezuela, which over the past few years has progressed in legal system in the ICSID. And so on this point, I want to see if we could get an update on the status, the next steps and the possible timeline, which I know may be difficult on that situation.

Yes, sure, it is difficult to predict the timelines. But as we've talked about before, we have filed -- we're working through the arbitration process through the international courts. But we've had our arbitration hearings. We expect to get a ruling on jurisdiction and the parameters on which values would be calculated later on in this year and then values as far as the damage calculations subsequent to that. But there's also appeals processes that can be used even after these rulings are achieved. So we're probably still several years away from having a judgment that we can collect on.

Our next question comes from Jacques Rousseau from RBC.

I just wanted to follow up on the slide you had talking about upstream production volumes. And specifically, I was curious of the field decline bar of 187,000 BOE per day. How much of that is oil versus gas?

I don't have that right off the top of my head. It's a little bit more weighted. If you look at our portfolio overall, it's particularly related to North America. The shift is away from natural gas, so the decline in natural gases in North America is more than the decline in liquids. I think we just have to get back to you on a more precise split of how that declined. But it's a little bit more gas weighted than oil weighted.

Okay. And one other question if I could. Regarding Alaska, I know there's been a lot of discussion about potentially changing some of the tax laws there, and it looks like it may get pushed off into next year. And I just wanted to get your views on that.

Yes, I mean, Alaska has got a very progressive tax regime now and a very -- and it's getting to be a relatively high cost from a high tax cost area for us. But we think that there would be opportunity for increased investment in Alaska that is adversely impacted by the tax regime up there. So we'll continue to work with the relevant people in the government there to try to influence things. We're hopeful, but it's hard. We don't know what -- it's hard to speculate on what the impact might be.

Our next question comes from Paul Sankey from Deutsche Bank.

You reiterated your disposal guidance, the $5 billion to $10 billion. I was wondering, firstly, what the near-term potential news flow would be out of that program. Secondly, whether the issues in North Africa have potentially derailed some of the potential disposals. And thirdly, any news that you might have on refining, restructuring would be gratefully received.

Yes, as we've talked about at the analyst presentation, as opposed to what we did in 2010 where we were fairly specific about guidance on asset sales, we're taking the approach of -- we have several things we're pursuing, but we're not likely to give a lot of guidance about them until transactions are at an announcement point. So I don't think there's really much more we're going to say other than what we've said so far regarding asset sales. We continue -- we've mentioned before that we're continuing to work the Wilhelmshaven refinery asset sales process. We've got other things we're investigating and working on the downstream side, but it's too early to try to comment on those specifically. And as far as the events in North Africa, there's not much -- there's not really a comment that we can make there on the impact of that on our asset sales program either.

On the pace of the buyback, it was a little bit slower than we expected. Can we anticipate that to accelerate for the rest of the year?

So with the buyback, we spent $1.6 billion basically in first quarter, that was starting in mid-February, after we were out with our dividend and share repurchase announcement. As we talked about a little bit earlier, we spent basically another $900 million in April. So that would give you kind of an idea of the pace we've been going at so far this year, and we'll continue to evaluate that as we go through the year.

Yes. So it would be an appropriate run rate then?

Yes.

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

A couple of, I guess, a little more granular things from me. Your depreciation in the upstream fell about $140 million sequentially, and I'm guessing some of that related to the unplanned downtime. But can you guys give us an idea of what's going on there in terms of how we should think about the run rate on a go-forward basis for, I guess, both for upstream and group for DD&A? And I have a follow-up, please.

Yes. So for DD&A, what we guided at the analyst presentation of about $8 billion for 2011 is still what we would say for guidance. That is lower than DD&A levels in last year. Part of that is due to lower volumes. Also part of it is due to a shift in where our production comes from in that we're having increased production from equity affiliates where the DD&A number is essentially part of the equity earnings number, not separate as a DD&A number. So that is also a significant part of the chain. So guidance is $8 billion for DD&A, $7 billion upstream, $1 billion or so downstream.

Got it. And you kind of read my mind there because my follow-up is really on equity affiliates. Obviously, you don't breakout the earnings there, but is Qatar included in there? And can you just maybe just give us an update on how Qatar is performing because obviously that's been a big part of your incremental production this year and again is expected this year.

Yes, Qatar is in there. And it's performed, as we've mentioned earlier, it's performed quite well. It ramped up faster than we anticipated and production has been fairly steady there. So that's been -- the news has been good coming out of Qatar in the QG3 project.

What are the volumes, Jeff?

The volumes are about 80,000 BOE a day.

That's net.

Our share net. Yes, our share was 80,000 BOE per day, right. No, I'm just saying just in equity affiliates in general, what -- the big things that go into that, of course, our midstream and our chemicals joint venture. Our 2 joint ventures with Cenovus on the upstream, the FCCL joint venture on the upstream and the WRB joint venture on the downstream and APLNG, as well as Qatar project.

And a little bit of Russia.

And a little bit in -- in NMNG, joint venture in Russia.

Okay, that's terrific. And then last one I have, if I may, is the asset sales on the dollar side, I think, the guidance is pretty clear there. But could you give us just a kind of run rate to date as to what you've completed in terms of volumes in the upstream and what you still have set to do? And I'll leave it there.

Yes. So the only thing we did in the -- that was closed in the first quarter, was a relatively small transaction of some Lower 48 nonoperated assets. It was around $300 million to $400 million. The volumes associated with that are relatively small, in the 2,000 to 3,000 barrels a day.

Okay. So what have you got left to do, Jeff?

Pardon me? What's left to do...

What have you got left to do?

Well, we've got left to do the rest of the assets sales program we've talked about, the whole $5 billion to $10 billion. And kind of like the earlier question, we'll comment more on those things as they occur as opposed to identifying specific assets that will be part of this program.

Our next question comes from Blake Fernandez from Howard Weil.

I had a question for you on the refining downtime in the first quarter. The release seems to suggest there was a bit of unplanned downtime. And I was hoping you could kind of address specifically the regions that's coming from and if that's been corrected heading into 2Q.

Yes, it's really -- it's at different places but predominantly, it was at our Borger refinery and at our Sweeny refinery. So part of the Mid-Continent region and part of it out of the Gulf Coast region. Both of those were incidents that occurred which caused us to take facility -- portions of the refinery down for a period of time. And those things are both things that had been corrected. We have unplanned downtime every quarter. The first quarter was a little bit higher than what we would normally expect from unplanned downtime, and we put a number on that of around $50 million impact to R&M for the quarter.

And then the second question for you was on your Permian acreage, the 1 million acreage you have there. Have you guys identified the amount of unconventional opportunity, whether it'd be Avalon or Bone Spring shale?

We are working in those areas actively, but we haven't fully identified. No, we haven't fully identified that yet.

Our next question comes from Lakiesha Bonnie [ph] from Crédit Suisse. Edward Westlake - Crédit Suisse AG: It's Ed Westlake here. Just On the Eagle Ford and the Bakken volumes, can you just talk through how much of that volume already has a pipeline or a rail evacuation route already signed by Conoco in terms of your targets?

So our current production is around a little over 20,000 barrels a day. We have about 5,000 barrels a day, wasn't it, Clayton? That's curtailed as we're working through evacuation. We have plans in place to cater for the full Eagle Ford production, which we expect will be up at the 65,000, 70,000 barrels a day by -- you'll see in a couple of years. So as we go through these next few time periods, there'll be periods where we're a little bit behind on the infrastructure, but we're confident that by the time we get to 2013 and the volumes we think we're going to have there, that we'll have infrastructure to take that volume away. Edward Westlake - Crédit Suisse AG: And then in the short term, that's more rail and then as pipelines evolve or?

It's both truck and I think it's everything. And I think it's -- I don't know if we're using rail there, I think it's primarily truck and pipe. Edward Westlake - Crédit Suisse AG: And then just on the follow-on, obviously, we have announcement yesterday from another refining -- sorry, pipeline coming from Cushing to Gulf. What are your thoughts on, as a big Mid-Con refiner as well as the Gulf Coast, that the Keystone and the other PBT pipeline will be onstream by 2013? And what are the challenges they face?

Well, of course, Keystone XL faces the continuing permitting challenge to get that done. We anticipate that, that will occur and that the pipeline will be constructed in the next year and a half or so. We get the question a lot about whether we should be reversing our Seaway products -- Seaway pipeline which runs from the Gulf Coast to Cushing. That's something we'll continue to evaluate, but there is a solution plan now between Keystone XL and the questions whether there'll be incremental capacity required beyond that. And we, along with a lot of people, are studying that question. Edward Westlake - Crédit Suisse AG: Right. And then my final question on the downstream. You've got better refining margins in Q2. You'll have your refineries hopefully back up onstream from the unplanned downtime. That's good. But what sort of negative impact are you seeing at this point from sort of prices impacting demand and on the retail side?

That's a good question. We don't have as good a window into that as other companies do. But since we don't operate a retail marketing system, we're a wholesaler for our refined products. So we don't have any difficulty moving all the refined products that we can produce out of our refineries at market prices. So we haven't seen any evidence of decreased demand, so I'm not sure that we would be the one to really see that since we don't operate a retail network.

For us, I guess, it would show up in the gasoline margins that we experienced at the refineries.

Our next question comes from Faisel Khan from Citi.

On the refining side, if I'm looking at the domestic earnings, if you could give us a little bit color on the mix of those earnings. Did most of that come from the Gulf Coast Mid-Continent, and was the Northeast profitable this quarter?

Yes, the strongest areas were the Mid-Con refining with the situation with WTI being what it is. East Coast refining was still relatively challenged. West Coast refining margins and Gulf Coast refining margins were actually stronger as well in the first quarter. So the strength in the Midwest, more strength than we've seen recently in the West Coast and, the East Coast was still a more difficult market.

Will you say greater than 50% of your profits came from Mid-Continent/Gulf Coast Area?

Well, between -- probably so.

I'd say that's a fair comment, yes.

Got you. And then just looking at your bitumen price realization sequentially quarter to -- fourth quarter to first quarter, it looks like they were relatively flat for the consolidated company, even though I think the market prices were higher. If you could just kind of help us understand what's going on there? Or how are you getting your guys' bitumen to market? Or how are those realizations kind of being impacted by what's going on today?

So I think we saw a widening of the differential between bitumen prices and crude oil prices during the quarter, which was part of what benefits refining as well. There's no change into how we get our crude -- our bitumen to the market. There's no -- we're not constrained by any infrastructure constraints in moving that product to market. So it's just the shift in differentials which caused -- which is the primary cause for the relatively flat bitumen prices compared to the increased crude oil prices.

So you have no issues getting your product to market?

No. Yes, that's correct.

And then on Qatargas, the LNG volumes, which way were those volumes flowing during the quarter?

We don't -- go into provide detail on exact destinations of where our Qatari volumes have been flowing.

Our next question comes from Paul Cheng from Barclays Capital.

Jeff or Clayton, on the Seaway, your ownership, the 50%, if your partner want to use the right of way to construct another set of pipeline to move from, say, Cushing down to the Gulf Coast, do you guys have the veto power to veto that or the right to veto that if you want to, or that's not part of your agreement?

I don't know the details of that, Paul. I'd be surprised if they could since the right of way that was owned by the company and we have the ability to influence decisions of the company which owns the right of way. But I don't know the answer to that.

Clayton, is it possible that there's something you can share, you can check and get back to me?

I think it's a question if there's a commercial aspect of it or there's negotiation that we're in the middle of, we probably don't want to disclose it. But if it's public out there or it's part of some pipeline agreement that's in the public domain, I'd be happy to.

Okay. In your presentation, you indicate that the underlying field decline from the first quarter last year to the first quarter this year is 187,000 barrels per day or about -- maybe over 10% year-over-year. Is that a reasonable base operation, the kind of run rate that we should assume? Or there's a number of one-off incident that make that number higher than that we should use?

No. I think that's similar to what we've talked about. So that number is just the unmitigated decline rate. So it's similar to what you heard Ryan Lance and Greg Garland talking about at the analyst presentation in March, that's kind of 10%, 11% of our production rate. And then you could do things within those existing fields to bring that decline rate to more like 5%, and then you can -- with new projects, you can arrest the rest of that decline and have production growth.

That would be the number before maintenance and exploitation capital.

So this is before maintenance and exploitation?

Yes, this is just unmitigated decline.

Right.

And so what is the increase in production -- the partial offset in your presentation, is that included in your new project at the other column? You showed 187,000, that including both the new project as well as the benefit from the maintenance work?

Well, from exploitation work is what I think -- doing things within existing fields to capture additional production is included in the projects performance and other on the production chart.

Okay. Jeff, I was looking at, in your cash flow statement, you say the working capital is a use of cash of $2.1 billion. I thought in a rising oil price environment, because you have a longer grace period for the crude purchase and your accounts receivable, the grace period that you gave to your customer, we should see working capital be a source of fund instead of a use of fund. Am I missing something here?

Yes. So there's lots of different impacts that are happening with working capital that are price driven that will balance out over time as prices, as things catch up. So what we wanted to point out in the first quarter, though, is that the consciously chose to increase our inventory levels to facilitate some capturing of some margins in the marketplace that our commercial trading group had opportunities to do. And that was a big driver of the working capital change in the first quarter. And that's something that we could reverse if we chose to. And typically, we do allow our inventories to go up and down during the course of the year, so you'll see that, that will reverse over time. And you can look at previous years and you'll see a similar kind of pattern where we'll have usually inventory -- working capital negatives early in the year, working capital positives later in the year.

Yes. Another source of variance on the working capital can also be taxes payable. A couple of times a year, we'll make a big tax payment and so that number will be -- tax payable will obviously be a source of funds. And there's some variation that comes from that as well in the high price environment. But the big move quarter was obviously inventory.

Okay. So this quarter's inventory, is not the tax, even though it could be a fluctuation factors in the future?

That would be hundreds of millions of dollars. It wouldn't be at the magnitude that you're seeing this quarter.

Okay. Jeff, any insight that you can share with us on the Ekofisk redevelopment effort? Where we are in the process? What kind of estimate development costs on the actual, as well as on the per barrel basis of the incremental reserve that you would be able to recover, and what kind of production impact?

We've got nothing incremental to what we shared at the analyst presentation just about a month ago. We do anticipate that sanction on the Ekofisk -- South Development Ekofisk 2 -- Eldfisk 2 will be among the major projects that we sanction this year. They've got attractive both F&D and rates of return. And it's going to -- that over time, that those are projects which will cause us to move from having a declining production. Well, first, they arrest near-term decline in Norway and, ultimately, we'll get Norway production to where it turns around and see some slight increases.

Yes, I don't think -- where we said the $1.5 billion in capital in 2011 for North Sea. So sanctions this year and then capital will ramp up in subsequent years.

Right. Clayton, any kind of number that you can share?

On total capital?

On the Ecofisk.

Yes. I think we want to wait until we get to actually deciding what we're going to do on those projects. And let us sanction the projects first, and then come up with a total project capital number for you.

Okay, and final question. There's some rumor on the industry newsletter that the Bohai Bay, the performance has not been up to their expectation and has been a little bit challenging. I'm wondering, any comment you can give?

There had been one particular platform in Bohai Bay which has been a challenge, but that's been that way for several quarters now and that's reflected in the production numbers as you've seen from Bohai.

What was the Bohai current production?

60?

I'd have to look at probably in our supplemental information. I would say it's around 50 or 60.

50 to 60 net to you, right?

So internationally, actually, out of China, it was 77 in the first quarter.

Right. But that's more than just Bohai or not?

It's mostly -- well, yes, it's Bohai and Panyu as well. Bohai's, I don't know what off the top of my head, would Bohai is. We can probably get back...

90% of it.

It's most of that number.

Our next question comes from Iain Reid from Jefferies. Iain Reid - Jefferies & Company, Inc.: A couple of questions about Australia. You're still trying to sell the second train. I wonder if as part of this negotiation, you're also going to sell a similar amount of equity in the development after you sold to Sinopec. So could we see potentially being diluted down to below 40% in this development? That's the first question. Maybe I'll hold onto the second one.

Okay. Yes, we're continuing to sell the second train. The buyers we're talking to who are likely buyers in the second train will probably want perhaps some equity position. Some of the buyers we're talking do not want equity, some want a small equity position. It would be unlikely that it would be an equity position of the size that Sinopec came into. So it would be unlikely we would dilute substantially from where we are today. Iain Reid - Jefferies & Company, Inc.: Okay. And second question is, your partner, Origin, seems reluctant to confirm your costs for the overall development. Do you have a kind of a harder total development costs going forward from here for the LNG trains in the upstream development?

Yes. I think you're going to get the same answer from us that you're going to get from Origin, that we're working through that as part of our decision on getting towards the final investment decision in the mid part of this year. And that we'll be able to give you more information on that once we've gotten to that point. Iain Reid - Jefferies & Company, Inc.: Okay. I'll just try a last quick one. Any update on the potential development of Poseidon, and some drilling program in the Browse Basin, which I think you're starting around now?

No, there's not really an update there. We're still working through in getting the permitting process done there.

I think as Larry talked about, we were planning, I think it's 4 appraisal wells around Poseidon and other discoveries in Browse. I think the permitting is taking longer than we had hoped, so I don't have a new time to give you right now on when we start the appraisal drilling around the discovery. Iain Reid - Jefferies & Company, Inc.: Okay. But those wells are actually being -- are appraising Poseidon rather than exploration wells on other the separate prospect?

That's correct. These are appraisal wells.

Our next question comes from Mark Gilman from Benchmark.

I had to add couple of things. Just wanted to go back to that decline rate issue for a sec. Jeff, I thought you mentioned China both as the source of incremental production as well as the contributor to the decline. Can you clarify that for me?

So we have a decline from existing production in Panyu and Xijiang -- or Panyu. And then the way we bucket these things is so we have different -- we have wells and platforms in Bohai which may be in decline and things -- and new things we're bringing on in Bohai as well. So yes, I did mention it in both buckets.

So Bohai itself, all in, is in both buckets?

Right. But you could see overall production levels from China from the details that we give you in the international E&P page in the supplemental.

Well, when you talk about -- this is just a point of clarification. When you talk about declines at something like Bohai, that's x price-related entitlement effects, I assume?

We don't have large price-related entitlement effects.

But you do with Bohai?

We have some, but not -- but that is included in our decline numbers.

So the PSC impact would be included in the numbers.

So in an environment like this, it's being overstated, Clayton, right?

Well, I don't -- it's just the sort -- I guess, whether or not it's a decline as a result of the terms or a decline as a result of, I guess, the field life, we don't differentiate those 2 things in this graph, that's right.

Okay. Jeff, regarding this trading-oriented inventory build, were there any LIFO inventory effects associated with it in your booked downstream earnings, other than the $50 million in trading gains?

Not substantial in this quarter. We can have -- as we talked about in previous quarters, the exactly how physical inventory gets marked compared to how paper positions that are hedging trading positions around that inventory get marked, there can be some noise around that from quarter-to-quarter. This quarter, it was not -- there were not a significant number there related to inventory impacts.

Are those barrels in a separate pool?

You mean outside of R&M?

Well, there is sort of separate pool within R&M, Clayton, what you're doing in terms of trading activity?

We can probably take that discussion off-line as far as the complexities around inventory accounting. Are you talking about like a different layer?

Well, not necessarily different layer, Clayton. I'll take it off-line. Okay. Last one for me, I just want to try to clarify some of the unconventional liquids production numbers. Jeff or Clayton, I think a few moments ago, you've referenced a 20,000 a day current number. Is that just Eagle Ford or is that all of the 3 unconventional liquids-rich plays?

That's just Eagle Ford.

How many wells is producing currently?

Out of Eagle Ford, I don't have that number.

Probably north of 50.

50 net wells?

At least.

Okay. If we include the other plays, the Bakken, as well as the North Barnett, the current level of production would be roughly what?

50. I think we do about -- I think we do, I don't know, somewhere between 15 and 20 out of the Bakken and probably between 10 and 15 out of North Barnett.

Okay. And remind me of the year-end objective?

Where do we want to be around? 70, 65 to 70.

Right. 65.

You're talking about those three fields?

Yes, those plays.

Yes. That's what we're talking about.

Our next question comes from John Herrlin from Societe Generale.

Following up on Mark's shale question. What was sequential growth fourth quarter to first quarter for the shale plays volume-wise?

Well, most of the growth came out of Eagle Ford. I would say it's probably between 5,000 and 10,000 barrels a day.

Any change with Kenai in terms of the shutdown?

In terms of shutdown in Kenai, I don't think -- I think there was additional cargo sold, but I don't think our -- I think the issue is availability of gas.

We would -- obviously there'd be a market for that gas if we can produce it. But with the decline in the Cook Inlet, area, as Clayton says, it's mostly an issue with gas availability, and that compared to domestic demand in the Cook Inlet in the Anchorage area. So I don't really see any plans to prolong Kenai.

I mean, if we do prolong it, it's just for a short period of time.

Okay. That's fine. Last one for me. Regarding the trading that you're doing on the refining, how much of the capital commitment is it?

So it is all capital that we can choose to deploy or not deploy in that business. So the inventory positions that we have are -- can be taken out. So it's not a long-term capital commitment in that business.

I was just trying to figure out how much you're swinging, that's all.

So the swing in the first quarter was $2 billion in the downstream part of our business. And that's a mix of inventories, payables, receivables, all those kinds of working capital impacts. That's a fairly large swing for a particular quarter. If you look historically, we've probably been more to the $1 billion and $1.5 billion swings in working capital in a quarter.

Our next question comes from Pavel Molchanov from Raymond James. Pavel Molchanov - Raymond James & Associates, Inc.: Just two quick ones. One on Libya, I realize visibility there is pretty negligible. But do you have a sense of just the physical state of your assets in terms of damage, et cetera?

No, we do not. We don't have a good -- we don't know production levels, physical state of the assets. Really, we don't have a good information coming out of Libya.

Our employees were -- we got our employees out, what, mid -- was it mid-February? Yes. We really don't know.

Before everything happened there. Pavel Molchanov - Raymond James & Associates, Inc.: Okay. And I completely understood. And then if I can get a quick update on your program in Poland.

Not much more to say than what we've talked about as we are going through the presentation. We've drilled a couple of wells there, vertical wells. We're moving now to drill a horizontal well and we'll continue to just evaluate that program as we move forward. Not a lot more we can say about it at this time.

Our next question comes from Hernan Ladeuix from CLSA

I have a question on the international refining side. We saw some realized margins went down quite sharply quarter-on-quarter when market indicators have not. What would be the main reason for that?

So you're asking why international -- well, I'm not sure...

So, maybe in which segment again?

International refining, basically, margins went down 50%.

So our international refining if you think about it, it is fairly limited. It's the Humber refinery in the U.K., the Melaka refinery in Malaysia and then we have a joint venture refinery in Germany. Humber did well. But I'm not sure market indicators -- you're saying market indicators were higher in European?

Yes. It went up. Singapore went up. Europe, a little bit up. But your realized margins went down by 30% or more.

I don't have a good answer on that.

Yes, we'd have to get back to you on that one. I expect it has to do primarily with changes in co-product pricing which are not part of the market indicators.

That was our final question.

Okay. Well, thanks, everybody, for listening. Appreciate your interest. These comments and transcript we posted on our website along with the presentation material. Thank you, again.